ITEM 1: BUSINESS
General
We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our combined and consolidated subsidiaries.
On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.
Our operations primarily consisted of our ownership interests in the following:
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During the period September 1, 2016 to December 31, 2016, Titan, an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States. Titan Management holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests and to appoint four of seven directors). As discussed further below, Titan is the successor to the business and operations of ARP;
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Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 24,712,471 common limited partner units) in ARP. As discussed further below, ARP was the predecessor to the business and operations of Titan;
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all of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in AGP, a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas; and
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12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of our board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt.
Our cash flows and liquidity are substantially dependent upon AGP’s annual management fee and distributions from AGP, Lightfoot, and Titan. Neither AGP nor Titan are currently paying distributions. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP) for financial reporting purposes, AGP’s annual management fee and distributions from Lightfoot are currently our only sources of liquidity to satisfy our obligations under our credit agreements. In addition, the obligations under our first lien credit agreement mature in September 2017. As a result, we continue to face liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet. Please see “Risk Factors-Risks Related to Our Business- Our long term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time, and we are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet.”
AGP Overview
AGP’s primary business objective is to generate an attractive total return, consisting of current distributions and capital appreciation, through the acquisition of oil and gas assets in North America. As of December 31, 2016, AGP’s estimated proved reserves were 23 Bcfe. Of the estimated proved reserves, approximately 30% were proved developed and approximately 87% were oil. For the year ended December 31, 2016, its average daily net production was approximately 5.7 MMcfe.
On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order retain its cash flow and reinvest in its business and assets At this time, AGP can provide no certainty as to when or if distributions will be reinstituted.
As of December 31, 2016, AGP’s production positions were in the following areas:
Eagle Ford. The Eagle Ford Shale is an Upper Cretaceous-age formation that is prospective for horizontal drilling in approximately 26 counties across South Texas. Target vertical depths range from 4,000 to some 11,000+ feet with thickness from 40 to over 400 feet. The Eagle Ford formation is considered to be the primary source rock for many conventional oil and gas fields including the prolific East Texas Oil Field, one of the largest oil fields in the contiguous United States. AGP owns oil, natural gas and NGL interests in approximately 2,833 net acres, of which 1,592 are undeveloped, non-producing net acres and 704 are developed net acres, in the Eagle Ford Shale in Atascosa County, Texas. AGP acquired its Eagle Ford position through a series of acquisitions in 2014 and 2015 for approximately $100 million. During the year, AGP averaged 5.3 MMcfe/d net production volumes. AGP estimates 23 Bcfe of total proved reserves for its Eagle Ford position, of which 89% are oil.
Marble Falls. The Marble Falls play is Pennsylvanian-age formation located above the Barnett Shale and beneath the Atoka at depths of approximately 5,500 feet and ranges in thickness from 50 and 500 feet. AGP owns oil, natural gas and natural gas liquids interests in approximately 2,208 net acres, of which 770 are undeveloped, non-producing net acres and 1,438 are developed net acres in the Marble Falls formation and the Barnett Shale, in Jack County, Texas. During the year, AGP averaged 0.32 MMcfe/d net production volumes. AGP estimates 0.5 Bcfe of total proved reserves for its North Texas positions, of which 100% are proved developed and producing (“PDP”).
Mississippi Lime. The Mississippi Lime formation is an expansive carbonate hydrocarbon system and is located at depths between 4,000 and 7,000 feet between the Pennsylvanian-aged Morrow formation and the Devonian-age world-class source rock Woodford Shale formation. The Mississippi Lime formation can reach 600 feet in gross thickness, with a targeted porosity zone between 50 and 100 feet thickness. AGP owns a non-operated 21.25% working interest in two wells in the Mississippi Lime formation in Garfield County, Oklahoma, operated by SandRidge Energy, Inc. During the year, AGP averaged 0.043 MMcfe/d net production volumes. AGP estimates 0.15 Bcfe of proved reserves in its Mississippi Lime positions, of which 45% are gas.
Lightfoot Overview
Lightfoot is a private investment vehicle that focuses on investing directly in master limited partnership-qualifying businesses and assets. Lightfoot investors include affiliates of, and funds under management by, GE EFS, us, BlackRock Investment Management, LLC, Magnetar Financial LLC, CorEnergy Infrastructure Trust, Inc. and Triangle Peak Partners Private Equity, LP. As of December 31, 2016, we own an approximate 15.9% interest in Lightfoot’s general partner and a 12.0% interest in Lightfoot’s limited partner.
Lightfoot’s stated strategy is to make investments by partnering with, promoting and supporting strong management teams to build growth-oriented businesses or industry verticals. Lightfoot provides extensive financial and industry relationships and significant master limited partnership experience, which assist in growth via acquisitions and development projects by identifying:
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efficient operating platforms with deep industry relationships;
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significant expansion opportunities through add-on acquisitions and development projects;
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stable cash flows with fee-based income streams, limited commodity exposure and long-term contracts; and
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scalable platforms and opportunities with attractive fundamentals and visible future growth.
On November 6, 2013, ARCX, a master limited partnership owned and controlled by Lightfoot Capital Partners, L.P., began trading publicly on the NYSE. ARCX is focused on the terminalling, storage, throughput and transloading of crude oil and petroleum products in the East Coast, Gulf Coast and Midwest regions of the United States. ARCX’s cash flows are primarily fee-based under multi-year contracts. Lightfoot has a significant interest in ARCX through its ownership of a 27.1% limited partner interest, Lightfoot Capital Partners, G.P., the general partner, and all of Lightfoot’s incentive distribution rights. Lightfoot intends to utilize ARCX to facilitate future organic expansions and acquisitions for its energy logistics business.
Titan Overview
Titan is a publicly traded (OTCQX: TTEN) Delaware limited liability company and independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States with a focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas. Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”) in which it co-invests, to finance a portion of its natural gas, crude oil and natural gas liquids production activities. Titan Management holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s member’ equity, subject to potential dilution in the event of future
equity interests) and to appoint four of seven directors. As discussed further below, Titan is the successor to the business and operations of ARP
Recent Developments
ARP Restructuring and Emergence from Chapter 11 Proceedings
On July 25, 2016, we, solely with respect to certain sections thereof, along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% Senior Notes due 2021 (the “7.75% Senior Notes”) and the 9.25% Senior Notes due 2021 (the “9.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties agreed, subject to certain terms and conditions, to support ARP’s Restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).
On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”
ARP operated its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired by the Plan and were satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.
On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:
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the First Lien Lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche.
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the Second Lien Lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, the Second Lien Lenders received a pro rata share of 10% of the common equity interests of Titan, subject to dilution by a management incentive plan.
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Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of the common equity interests of Titan, subject to dilution by a management incentive plan.
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all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.
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ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended.
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Titan Management received a Series A Preferred Share of Titan, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests and to appoint four of seven directors) and certain other rights. Four of the seven initial members of the board of directors of Titan are designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in Titan’s limited liability company agreement), subject to the
receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of Titan unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.
We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses.
In connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our combined consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a result of these changes, our combined consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our combined financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.
On the Plan Effective Date, we determined that Titan is a variable interest entity based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions.
AGP’s Primary Offering Suspension. On November 2, 2016, AGP’s management decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. At this time, AGP can provide no certainty as to when or if its primary offering efforts will be reinstituted.
AGP’s Cash Distributions Suspension. On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets. At this time, AGP can provide no certainty as to when or if distributions will be reinstituted.
Gas and Oil Production
For the year ended December 31, 2016, our combined consolidated gas and oil production revenues, expenses, and volumes consisted of AGP’s gas and oil production activities and ARP’s gas and oil production activities through July 27, 2016. We deconsolidated ARP for financial reporting purposes as of the date of the Chapter 11 Filings and therefore our 2016 combined consolidated financial statements will not be comparable to our 2015 and 2014 combined consolidated financial statements.
Production Volumes
The following table presents our total net gas, oil and NGL production volumes and production per day for the periods indicated:
(1)
Production quantities consist of the sum of (i) the proportionate share of production from wells in which AGP has and ARP had a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it had an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.
(2)
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.
Production Revenues, Prices and Costs
Our production revenues and estimated gas, oil and natural gas liquids reserves are substantially dependent on prevailing market prices for natural gas and oil prices. The following table presents production revenues and average sales prices for our direct interest natural gas, oil and NGL production, along with average production costs, which include lease operating expenses, taxes and transportation and compression costs, for the periods indicated:
(1)
Excludes the impact of subordination of ARP’s production revenue to investor partners within ARP’s Drilling Partnerships. Including the effect of this subordination, the average realized gas sales prices were $3.41 per Mcf ($1.66 per Mcf before the effects of financial hedging), $3.36 per Mcf ($2.19 per Mcf before the effects of financial hedging), and $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging) for the years ended December 31, 2016, 2015 and 2014, respectively.
(2)
Includes the impact of $0.2 million and $0.5 million of cash settlements for the years ended December 31, 2016 and 2015, respectively, on AGP’s oil derivative contracts which were entered into subsequent to our decision to discontinue hedge accounting beginning on January 1, 2015. Includes the impact of cash settlements on ARP’s commodity derivative contracts not previously included within accumulated other comprehensive income following our decision to de-designate hedges beginning on January 1, 2015. Cash settlements on ARP’s commodity derivative contracts excluded from production revenues consisted of $62.6 million and $48.6 million associated with natural gas derivative contracts and $26.5 million and $35.8 million associated with crude oil derivative contracts for the years ended December 31, 2016 and 2015, respectively. Cash settlements on ARP’s natural gas liquids derivative contracts excluded from production revenues were $8.3 million for the year ended December 31, 2015 (see “Item 8. Financial Statements - Note 8”).
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Excludes the effects of our proportionate share of lease operating expenses associated with subordination of ARP’s total production revenue to investor partners within its Drilling Partnerships. Including the effects of these costs, ARP’s total lease operating expenses per Mcfe were $1.16 per Mcfe ($1.58 per Mcfe for total production costs), $1.32 per Mcfe ($1.74 per Mcfe for total production costs), and $1.25 per Mcfe ($1.77 per Mcfe for total production costs) for the years ended December 31, 2016, 2015 and 2014, respectively. Including the effects of these costs, our total lease operating expenses per Mcfe were $1.14 per Mcfe ($1.56 per Mcfe for total production costs), $1.31 per Mcfe ($1.73 per Mcfe for total production costs), and $1.26 per Mcfe ($1.78 per Mcfe for total production costs) for the years ended December 31, 2016, 2015 and 2014, respectively.
(4)
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.
Drilling Activity
The number of wells we drill will vary depending on, among other things, the amount of money we have available and the money raised by ARP’s Drilling Partnerships, the cost of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. The following table sets forth information with respect to the number of wells we drilled, both gross and net during the periods indicated:
(1)
Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) ARP’s percentage interest in the wells based on its percentage ownership in its Drilling Partnerships.
(2)
Includes AGP’s percentage interest in the wells in which it has a direct ownership interest.
(3)
Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.
(4)
There were no exploratory wells drilled during any of the periods presented. There were no gross or net dry wells within our operating areas during any of the periods presented.
(5)
The drilling activity related to AGP’s Eagle Ford operating area was included effective November 5, 2014, the date of acquisition. Ten wells were drilled by the prior owner but not yet turned in line, at the date of acquisition
(6)
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.
We do not operate any of the rigs or related equipment used in our drilling operations, relying instead on specialized subcontractors or joint venture partners for all drilling and completion work. This enables us to streamline operations and conserve capital for investments in new wells, infrastructure and property acquisitions, while generally retaining control over all geological, drilling, engineering and operating decisions. We perform regular inspection, testing and monitoring functions on each of our operated wells.
As of December 31, 2016, we did not have any ongoing drilling activities.
Contractual Revenue Arrangements
Natural Gas and Oil Production
Natural Gas. We market the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market our gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The pricing index for our Eagle Ford production is primarily Houston Ship Channel, primarily Waha for our Marble Falls production and primarily Southern Star for our Mississippi Lime production.
We sell the majority of natural gas produced at monthly, fixed index first of the month prices and a smaller portion at index daily prices. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of natural gas in any future periods under existing contracts or agreements.
Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting on behalf of the oil purchaser. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.
Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as indicated above and our NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage retention by the processing and fractionation facility. We do not have delivery commitments or firm transportation contracts for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.
For the year ended December 31, 2016, Tenaska Marketing Ventures, Interconn Resources LLC and Chevron accounted for approximately 29%, 15% and 14%, respectively, of ARP’s natural gas, oil and NGL production revenues with no other single customer accounting for more than 10% for this period. For the year ended December 31, 2016, Shell Trading Company and Enterprise Crude Oil LLC individually accounted for approximately 64% and 29%, respectively, of AGP’s natural gas, oil and NGL production revenues with no other single customer accounting for more than 10% for this period.
Competition
The oil and natural gas industry is highly competitive. We encounter strong competition from independent oil and gas companies, MLPs and from major oil and gas companies in acquiring properties, contracting for drilling equipment and arranging for the services of trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or other resources will permit.
Competition is strong for attractive oil and natural gas properties and there can be no assurances that we will be able to compete satisfactorily when attempting to make acquisitions. In general, sellers of producing properties are influenced primarily by the price offered for the property, although a seller also may be influenced by the financial ability of the purchaser to satisfy post-closing indemnifications, plugging and abandoning operations and similar factors.
We also may be affected by competition for drilling rigs, human resources and the availability of related oilfield services and equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.
Seasonal Nature of Business
Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas where we may acquire producing properties. In addition, it is possible that we will acquire oil and gas properties that are subject to flooding, drought or tornados. These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off-peak months. This can also lessen seasonal demand fluctuations.
Environmental Matters and Regulation
Our operations relating to drilling and waste disposal are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, we must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:
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restricting the way waste disposal is handled;
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limiting or prohibiting drilling, construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by threatened or endangered species;
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requiring the acquisition of various permits before the commencement of drilling;
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requiring the installation of expensive pollution control equipment and water treatment facilities;
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restricting the types, quantities and concentration of various substances that can be released into the environment in connection with siting, drilling, completion, production, and plugging activities;
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requiring remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;
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enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations;
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imposing substantial liabilities for pollution resulting from operations; and
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requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.
We believe that our operations are in substantial compliance with applicable environmental laws and regulations, and compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.
Environmental laws and regulations that could have a material impact on our operations include the following:
National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA.” NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands, if any, require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.
Hydraulic Fracturing. In recent years, federal, state, and local scrutiny of hydraulic fracturing has increased. Regulation of the practice remains largely the province of state governments, except for a Bureau of Land Management rule that would have imposed conditions on fracturing operations on federal lands, which was enjoined by a federal court holding BLM lacked the authority to adopt the rule. Common elements of state regulations governing hydraulic fracturing may include, but not be limited to, the following: requirement that logs and pressure test results are included in disclosures to state authorities; disclosure of hydraulic fracturing fluids and chemicals, potentially subject to trade secret/confidential proprietary information protections, and the ratios of same used in operations; specific disposal regimens for hydraulic fracturing fluids; replacement/remediation of contaminated water assets; and minimum depth of hydraulic fracturing. In December 2016, EPA released the final report of its study of the impacts of hydraulic fracturing on drinking water in the U.S. finding that the hydraulic fracturing water cycle can impact drinking water resources under some circumstances. Those circumstances included where (1) there are water withdrawals for hydraulic fracturing in times or areas of low water availability, (2) hydraulic fracturing fluids and chemicals or produced water are spilled, (3) hydraulic fracturing fluids are injected into wells with inadequate mechanical integrity, and (4) hydraulic fracturing wastewater is stored or disposed in unlined pits. If new federal regulations were adopted as a result of these findings, they could increase our cost to operate.
Oil Spills. The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.
Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations a number of different types of requirements on our operations. First, these laws and regulations impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Second, the Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The precise definition of waters and wetland subject to the dredge-and-fill permit requirement has been enormously complicated and is subject to on-going litigation. A broader definition could result in more water and wetlands being subject to protection creating the possibility of additional permitting requirements for some of our existing or future facilities. Third, the Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that our operations are in substantial compliance with the requirements of the Clean Water Act.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean Air Act, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Clean Air Act rules impose additional emissions control requirements and practices on some of our operations. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new or revised requirements. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act and comparable state laws and regulations. While we will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to obtain and maintain operating permits and approvals for air
emissions, we believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companies.
Greenhouse Gas Regulation and Climate Change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. Under the past eight years during the Obama Administration several Clean Air Act regulations were adopted to reduce greenhouse gas emissions, and a couple foundational regulations were upheld by the courts. President Trump pledged during the election campaign to suspend or reverse many if not all of the Obama Administration’s initiatives to reduce the nation’s emissions of greenhouse gases. Some of the foundational regulations, however, appear unyielding. It would be a significant departure from the principle of stare decisis for the Supreme Court to reverse its decision in Massachusetts v. EPA, 549 U.S. 497 (2007) holding that greenhouse gases are “air pollutants” covered by the Clean Air Act. Similarly, reversing EPA’s final determination that greenhouse gases “endanger” public health and welfare, 74 Fed. Reg. 66,496 (Dec. 15, 2009), upheld in Coalition for Responsible Regulation, Inc. v. EPA, 684 F.3d 102 (D.C. Cir. 2012), would seem to require development of new scientific evidence that runs counter to general discoveries since that determination.
On March 28, 2017, President Trump issued an Executive Order on Promoting Energy Independence and Economic Growth explaining how his Administration would withdraw, rescind, revisit, or revise virtually every element the Obama Administration’s program for reducing greenhouse gas emissions. Under the Executive Order, some actions had immediate effect. Other actions, including those most directly affecting our operations and the overall consumption of fossil fuels, will be the subject of potentially lengthy notice-and-comment rule-making. With respect to rules more directly applicable to the types of operations AGP conducts, the Executive Order directed EPA to undertake new rule-making to revise or rescind 2015 methane emissions standards for new or modified wells. Similarly, the Order directed the Department of Interior to re-write a 2015 rule imposing restrictions on fracturing operations conducted on federal land and a 2016 rule restricting flaring of methane emissions from oil and gas extraction on federal land. With respect to rules of greater applicability affecting overall consumption of fossil fuels, the Order instructed EPA to rewrite (1) the 2015 Clean Power Plan - the rule aimed at reducing greenhouse gas emissions from existing power plants by one-third (compared to 2005 levels), and (2) the 2015 New Source Rule setting greenhouse gas emission requirements for construction of new power plants.
While we generally foresee a less stringent approach to the regulation of greenhouse gases, undoing the Obama Administrations regulations of greenhouse gas emissions will necessarily involve lengthy notice-and-comment rulemaking and the resulting decisions may then be subject to litigation by those opposed to rolling back existing regulations. Thus, it could be several years before existing regulations are off the books. Opponents of the rollbacks, including states and environmental groups, may then decide to sue large sources of greenhouse gas emissions for the alleged nuisance created by such emissions. In 2011, the Supreme Court held that federal common law nuisance claims were displaced by the EPA’s authority to regulate greenhouse gas emissions from large sources of emissions. If the Administration fails to pursue regulation of emissions from such sources or takes the position that it has no authority to do regulate their emissions, then it is possible that a court would find common law nuisance claims are no longer displaced.
Although further regulation of greenhouse gas emissions from our operations may stall at the federal level, it is possible that, in the absence of additional federal regulatory action, states may pursue additional regulation of our operations, including restrictions on new and existing wells and fracturing operations, as many states already have done.
Waste Handling. The Solid Waste Disposal Act, including RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. With authority granted by federal EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous in the future. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as “solid waste.” The transportation of natural gas in pipelines may also generate some “hazardous wastes” that are subject to RCRA or comparable state law requirements. We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations. More stringent regulation of natural gas and oil exploration and production wastes could increase the costs to manage and dispose of such wastes.
CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” (but excluding petroleum) into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property
damage allegedly caused by the hazardous substances released into the environment. Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. We are not presently aware the need for us to respond to releases of hazardous substances that would impose costs that would be material to our financial condition.
OSHA and Chemical Reporting Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes. On March 25, 2016, OSHA published its final Occupational Exposure to Respirable Crystalline Silica final rule, which imposes specific requirements to protect workers engaged in hydraulic fracturing. 81 Fed. Reg. 16,285. The requirements of that final rule as it applies to hydraulic fracturing become effective June 23, 2018, except for the engineering controls component of the final rule, which has a compliance date of June 23, 2021. We expect implementation of the rule to result in significant costs. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. If the sectors to which community-right-to-know or similar chemical inventory reporting are expanded, our regulatory burden could increase. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. We conduct our natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. We employ numerous safety precautions at our operations to ensure the safety of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in substantial compliance with all such requirements.
Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our or its wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.
State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2015, the impact fee for qualifying unconventional horizontal wells spudded during 2015 was $45,300 per well, while the impact fee for unconventional vertical wells was $9,100 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources.
States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill. Texas imposes a 7.5% tax on the market value of natural gas sold, 4.6% on the market value of condensate and oil produced and an oil field clean up regulatory fee of $0.000667 per Mcf of gas produced, a regulatory tax of $.001875 and the oil field clean-up fee of $.00625 per barrel of crude. New Mexico imposes, among other taxes, a severance tax of up to 3.75% of the value of oil and gas produced, a conservation tax of up to 0.24% of the oil and gas sold, and a school emergency tax of up to 3.15% for oil and 4% for gas. Alabama imposes a production tax of up to 2% on oil or gas and a privilege tax of up to 8% on oil or gas. Oklahoma imposes a gross production tax of 7% per Bbl of oil, up to 7% per Mcf of natural gas and a petroleum excise tax of .095% on the gross production of oil and gas.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.
Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on the industry. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.
Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.
Employees
We employed approximately 389 persons as of December 31, 2016. Some of our officers may spend a substantial amount of time managing the business and affairs of AGP, Titan and their affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.
Available Information
We make our periodic reports under the Securities Exchange Act of 1934, our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports, available through our website at www.atlasenergy.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. To view these reports, click on “Investor Relations”, then “SEC Filings”. The other information contained on or hyperlinked from our website does not constitute part of this report. You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive - Suite 400, Pittsburgh, Pennsylvania 15275, telephone number (412) 489-0006. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings is also available at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.
ITEM 1A:
ITEM 1A:
RISK FACTORS
Limited liability company interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider those risk factors included herein, together with all the other information included in this report, including the matters addressed under “Forward-Looking Statements,” in evaluating an investment in our common units. If any of the following risks were to occur, our business or financial condition or results of operations could be materially adversely affected. In such case, the trading price of our common units could decline and you could lose all or part of your investment.
Risks Relating to Our Business
Our long term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time, and we are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet.
We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. AGP recently suspended its quarterly distributions, and we do not expect that Titan will pay distributions for the foreseeable future. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP), for financial reporting purposes, those distributions, along with distributions from Lightfoot and AGP’s annual management fees, are our primary sources of liquidity to satisfy our obligations under our credit agreements. In addition, the obligations under our first lien credit agreement mature in September 2017. Our cash on hand and cash flow from operations are not sufficient to continue to fund our operations and allow us to satisfy our obligations.
We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet and meeting our debt service obligations. We could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. We are evaluating various options with our lenders, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. We expect that any changes to our capital structure we undertake has the potential to result in cancellation of indebtedness income that would be allocable to our unitholders, which may be significant. Please see “-Tax Risks to Unitholders-We expect to engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.”
We cannot assure you that we would be able to implement the above actions, if necessary, on commercially reasonable terms, or at all, in a manner that would be permitted under the terms of our debt instruments or in a manner that does not negatively impact the price of our securities. Additionally, there can be no assurance that the above actions would allow us to meet our debt obligations and capital requirements.
Please see “Management’s Discussion and Results of Operations- Liquidity, Capital Resources and Ability to Continue as a Going Concern.”
If we do not pay distributions on our common units in any fiscal quarter, our unitholders are not entitled to receive distributions for such prior periods in the future.
Our distributions to our unitholders are not cumulative. Consequently, if we do not pay distributions on our common units with respect to any quarter, our unitholders are not entitled to such payments in the future.
Natural gas and oil prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and oil, which have declined substantially. Lower commodity prices may reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in an impairment charge. Because our reserves are predominantly natural gas, changes in natural gas prices have a more significant impact on our financial results.
Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:
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the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas and oil (such as that produced from our Marcellus Shale properties) on the domestic and global natural gas and oil supply;
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the level of industrial and consumer product demand;
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weather conditions;
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fluctuating seasonal demand;
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political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa and South America;
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the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls;
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the price level of foreign imports;
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actions of governmental authorities;
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the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil;
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inventory storage levels;
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the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;
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the price, availability and acceptance of alternative fuels;
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technological advances affecting energy consumption;
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speculation by investors in oil and natural gas;
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variations between product prices at sales points and applicable index prices; and
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overall economic conditions, including the value of the U.S. dollar relative to other major currencies.
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of natural gas and oil. In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2016, the NYMEX Henry Hub natural gas index price ranged from a high of $3.93 per MMBtu to a low of $1.64 per MMBtu, and West Texas Intermediate (“WTI”) oil prices ranged from a high of $54.06 per Bbl to a low of $26.21 per Bbl.
A continuation of the prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition and results of operations. We may use various derivative instruments in connection with anticipated oil and natural gas sales to reduce the impact of commodity price fluctuations. However, the entire exposure of our operations from commodity price volatility is not currently hedged, and we may not be able to hedge such exposure going forward. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be further diminished.
In addition, low oil and natural gas prices have reduced, and may in the future further reduce, the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices.
Drilling for and producing natural gas and oil are high-risk activities with many uncertainties.
Our drilling activities are subject to many risks, including the risk that they will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. This risk is exacerbated by the current decline in oil and gas prices. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
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the high cost, shortages or delivery delays of equipment and services;
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unexpected operational events and drilling conditions;
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adverse weather conditions;
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facility or equipment malfunctions;
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title problems;
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pipeline ruptures or spills;
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compliance with environmental and other governmental requirements;
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unusual or unexpected geological formations;
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formations with abnormal pressures;
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injury or loss of life and property damage to a well or third-party property;
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leaks or discharges of toxic gases, brine, natural gas, oil, hydraulic fracturing fluid and wastewater from a well;
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environmental accidents, including groundwater contamination;
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fires, blowouts, craterings and explosions; and
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uncontrollable flows of natural gas or well fluids.
Any one or more of these factors could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings. Any of these events can also cause substantial losses, which may not fully be covered by insurance, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties, which could reduce our cash flow.
Although we and AGP maintain insurance against various losses and liabilities arising from AGP’s operations, insurance against all operational risks is not available to us. Additionally, we or AGP may not elect to obtain insurance if we or AGP believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could reduce the results of AGP’s operations.
Economic conditions and instability in the financial markets could negatively impact our businesses.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, and the Chinese economy have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and could lead to a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil, natural gas and natural gas liquids produced from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately adversely impact our results of operations, financial condition and potential cash available for distribution.
The above factors can also cause volatility in the markets and affect our and AGP’s ability to raise capital and reduce the amount of cash available to fund operations. We cannot be certain that additional capital will be available to us to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively impact our and AGP’s access to liquidity needed for our businesses and impact flexibility to react to changing economic and business conditions. We may be unable to execute our growth strategies, take advantage of business opportunities, respond to competitive pressures or service our debt, any of which could negatively impact our businesses.
A continuing or weakening of the current economic situation could have an adverse impact on producers, key suppliers or other customers, or on our lenders, causing them to fail to meet their obligations. Market conditions could also impact our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and AGP’s cash flow could be impacted. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we currently cannot predict or anticipate.
Restrictions in our credit agreements limit could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
Our credit agreements limit our ability to, among other things:
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incur or guarantee additional debt;
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redeem or repurchase units or make distributions under certain circumstances;
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make certain investments and acquisitions;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
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transfer, sell or otherwise dispose of assets.
Our credit agreements also contain covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet any such ratios and tests. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP), for financial reporting purposes, distributions from AGP and Titan along with distributions from Lightfoot and AGP’s annual management fee, are our primary sources of liquidity to satisfy our obligations under our credit agreements. However, neither AGP nor Titan is currently paying distributions. In addition, the obligations under our first lien credit agreement mature in September 2017.
We are evaluating various options with our lenders, but there is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes in our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders. A breach of any of the covenants in our credit facilities, could result in an event of default thereunder as well as a cross-default under such defaulting party’s other debt agreements and, in either case, our credit agreement. Upon the occurrence of an event of default, the lenders under these credit agreements, could elect to declare all amounts outstanding immediately due and payable and the lenders could terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness, if any.
Our borrowings under our credit agreements are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same. The provisions of our credit agreements may also affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions.
Our debt obligations could have a negative impact on our financing options and liquidity position.
Our debt obligations could have important consequences to us, and our investors, including:
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requiring a substantial portion of cash flow to make interest payments on this debt;
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making it more difficult to satisfy debt service and other obligations;
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increasing the risk of a future credit ratings downgrade of our debt, which could increase future debt costs and limit the future availability of debt financing;
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increasing our vulnerability to general adverse economic and industry conditions;
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reducing the cash flow available to fund capital expenditures and other corporate purposes and to grow our business;
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limiting our flexibility in planning for, or reacting to, changes in our business and the industry;
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placing us at a competitive disadvantage relative to competitors that may not be as leveraged with debt;
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limiting our ability to borrow additional funds as needed or take advantage of business opportunities as they arise; and
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limiting our ability to commence or pay cash distributions.
In addition, the recent Third Amendment to our First Lien Credit Agreement prohibits us from paying cash distributions on our common and preferred units.
Hedging transactions may limit our potential gains or cause us to lose money.
Pricing for natural gas, NGLs and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we may use financial hedges and physical hedges for our production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and oil and are considered normal sales of natural gas and oil. We generally limit these arrangements to smaller quantities than those we project to be available at any delivery point.
In addition, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties in compliance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, (the “Dodd-Frank Act”). The futures contracts are commitments to purchase or sell natural gas and oil at future dates and generally cover one-month periods for up to six years in the future. The over-the-counter derivative contracts are typically cash settled by determining the difference in financial value between the contract price and settlement price and do not require physical delivery of hydrocarbons.
These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on our cash flow from operations for the periods covered by these arrangements. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit our potential gains if commodity prices were to rise substantially over the price established by the hedge. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
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a counterparty is unable to satisfy its obligations;
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production is less than expected; or
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there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production.
However, it is not always possible for us to engage in a derivative transaction that completely mitigates our exposure to commodity prices and interest rates. Our financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we and our subsidiaries are unable to enter into a completely effective hedge transaction.
The failure by counterparties to our derivative risk management activities to perform their obligations could have a material adverse effect on our results of operations.
The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under our derivative arrangements, such a default could have a material adverse effect on our results of operations, and could result in a larger percentage of our future production being subject to commodity price changes.
Regulations adopted by the Commodities Futures Trading Commission could have an adverse effect on our and our subsidiaries’ ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our businesses.
The ongoing implementation of derivatives legislation adopted by the U.S. Congress could have an adverse effect on our and our subsidiaries’ ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our businesses. The Dodd-Frank Act, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation requires the Commodities Futures Trading Commission (the “CFTC”), and the SEC to promulgate rules and regulations implementing the new legislation. The CFTC finalized many of the regulations associated with the reform legislation, and is in the process of implementing position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The CFTC adopted final rules establishing margin requirements for uncleared swaps entered by swap dealers, major swap participants and financial end users (though non-financial end users are excluded from margin requirements). While, as a non-financial end user, we are not subject to margin requirements, application of these requirements to our counterparties could affect the cost and availability of swaps we use for hedging. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.
The new legislation and any new regulations could significantly increase the cost of derivative contracts; materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks we and our subsidiaries encounter; reduce our and our subsidiaries’ ability to monetize or restructure our derivative contracts in existence at that time; and increase our exposure to less creditworthy counterparties. If we and our subsidiaries reduce or change the way we use derivative instruments as a result of the legislation or regulations, our and our subsidiaries’ results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our and our subsidiaries’ ability to plan for and fund capital expenditures. Finally, the legislation was also intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our and our subsidiaries’ revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our and our subsidiaries’ consolidated financial position, results of operations and/or cash flows.
Any acquisitions we or our subsidiaries complete are subject to substantial risks that could adversely affect our and our subsidiaries’ financial condition and results of operations.
Any acquisition involves potential risks, including, among other things:
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the validity of our assumptions about reserves, future production, revenues, capital expenditures and operating costs;
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an inability to successfully integrate the businesses we or our subsidiaries acquire;
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a decrease in our or our subsidiaries’ liquidity by using a portion of our or our subsidiaries’ available cash or borrowing capacity under respective revolving credit facilities to finance acquisitions;
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a significant increase in interest expense or financial leverage if we or our subsidiaries additional debt to finance acquisitions;
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the assumption of unknown environmental or title and other liabilities, losses or costs for which we or our subsidiary are not indemnified or for which our indemnity is inadequate;
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the diversion of management’s attention from other business concerns and increased demand on existing personnel;
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the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges;
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unforeseen difficulties encountered in operating in new geographic areas;
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the loss of key purchasers of our production; and
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the failure to realize expected growth or profitability.
Our decision to acquire oil and natural gas properties depends in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, seismic data and other information, the results of which are often inconclusive and subject to various interpretations. The scope and cost of the above risks may be materially greater than estimated at the time of the acquisition. Further, our and our subsidiaries’ future acquisition costs may also be higher than those we have achieved historically. Any of these factors could adversely affect future growth and the ability to commence distributions.
We may be unsuccessful in integrating the operations from any future acquisitions with our operations and in realizing all of the anticipated benefits of these acquisitions.
The integration of previously independent operations can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations we or our subsidiaries may acquire in the future, include, among other things:
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operating a significantly larger combined entity;
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the necessity of coordinating geographically disparate organizations, systems and facilities;
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integrating personnel with diverse business backgrounds and organizational cultures;
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consolidating operational and administrative functions;
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integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate governance matters;
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the diversion of management’s attention from other business concerns;
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customer or key employee loss from the acquired businesses;
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a significant increase in our or our subsidiaries’ indebtedness; and
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potential environmental or regulatory liabilities and title problems.
Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to expand our or our subsidiaries’ operations could harm our business or future prospects, and result in significant decreases in our or our subsidiaries’ gross margin and cash flows.
If in the future we cease to manage Titan or control AGP, we may be deemed to be an investment company.
If we cease to manage Titan or control AGP, we may be deemed to be an investment company under the Investment Company Act of 1940 and would then either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, such as the purchase and sale of securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.
If we had to register as an investment company under the Investment Company Act of 1940, we would also be unable to qualify as a partnership for U.S. federal income tax purposes and would be treated as a corporation for U.S. federal income tax purposes. We would pay U.S. federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, any cash available for distribution to you would be substantially reduced, which could result in a material reduction in distributions to you, if any, with a possible corresponding reduction in the value of our common units.
If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.
A cyber incident or terrorist attack could result in information theft, data corruption, operational disruption and/or financial loss.
We have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves, as well as other
activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future cyber or terrorist attacks than other targets in the United States. Deliberate attacks on, or security breaches in our systems or infrastructure, or the systems or infrastructure of third parties or the cloud, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, challenges in maintaining our books and records and other operational disruptions and third party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
Risks Relating to Exploration and Production Operations
Our operations require substantial capital expenditures to increase our asset bases. If we are unable to obtain needed capital or financing on satisfactory terms, our asset bases will decline, which could cause revenues to decline and affect our ability to commence or continue distributions.
The natural gas and oil industry is capital intensive. Because we distribute our available cash, if any, to our unitholders each quarter in accordance with the terms of our LLC Agreement, we expect we will rely primarily on external financing sources such as commercial bank borrowings and the issuance of debt and equity securities to fund any expansion and investment capital expenditures. If we are unable to obtain sufficient capital funds on satisfactory terms, we may be unable to increase or maintain our inventories of properties and reserve base, or be forced to curtail drilling or other activities. This could cause our revenues to decline and diminish its and our ability to service any debt that any of us may have at such time. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our respective business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on our units.
We depend on certain key customers for sales of our natural gas, crude oil and NGLs. To the extent that these customers reduce the volumes of natural gas, crude oil and NGLs they purchase or process from us, or cease to purchase or process natural gas, crude oil and NGLs from us, our revenues and available cash could decline.
We market the majority of our natural gas production to gas marketers directly or to third-party plant operators who process and market our gas. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. Natural gas liquids are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. For the year ended December 31, 2016, Shell Trading Company and Enterprise Crude Oil LLC accounted for approximately 64% and 29% of AGP’s natural gas, oil and NGL production revenues, respectively, with no other single customer accounting for more than 10% for this period. To the extent these and other key customers reduce the amount of natural gas, crude oil and NGLs they purchase from AGP, our revenues and cash available for distributions to unitholders could temporarily decline in the event we are unable to sell to additional purchasers.
An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price that we receive for our production could significantly reduce our available cash and adversely affect our financial condition.
The prices that we receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price that we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price that we receive could significantly reduce our available cash and adversely affect our financial condition. We use the relevant benchmark price to calculate our hedge positions, and in certain areas, we do not have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our results of operations.
Competition in the natural gas and oil industry is intense, which may hinder our ability to acquire natural gas and oil properties and companies and to obtain capital, contract for drilling equipment and secure trained personnel.
We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, contracting for drilling equipment and securing trained personnel. Our competitors may be able to pay more for natural gas, NGLs and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Moreover, competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than we have. All of these challenges could make it more difficult for us to execute our growth strategies. We may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.
Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling natural gas and oil. Many of our competitors possess greater financial and other resources than we do or they have, which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we can.
Unless we replace our natural gas and oil reserves, the reserves and production will decline, which would reduce cash flow from operations and income.
Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas and oil reserves and production and, therefore, cash flow and income are highly dependent on their success in efficiently developing and exploiting reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on generating sufficient cash flow from operations and other sources of capital, all of which are subject to the risks discussed elsewhere in this section.
The recent decrease in natural gas and oil prices, or any further decrease in commodity prices, could subject our oil and gas properties to a non-cash impairment loss under U.S. generally accepted accounting principles.
U.S. generally accepted accounting principles require oil and gas properties and other long-lived assets to be reviewed for impairment whenever events or changes in circumstances indicate that their carrying amounts may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. We test our oil and gas properties on a field-by-field basis, by determining if the historical cost of proved properties less the applicable depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our economic interests and our plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. We estimate prices based on current contracts in place at the impairment testing date, adjusted for basis differentials and market related information, including published future prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates.
Prolonged depressed prices of natural gas and oil may cause the carrying value of our oil and gas properties to exceed the expected future cash flows, and a non-cash impairment loss would be required to be recognized in the financial statements for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to AGP’s proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties.
Our acquisitions may prove to be worth less than we paid, or provide less than anticipated proved reserves, because of uncertainties in evaluating recoverable reserves, well performance, and potential liabilities as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs.
Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Our estimates of future reserves and estimates of future production for our acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by our internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain our proved reserves estimates may thus exceed actual acquired proved reserves. In connection with our assessments, we perform a review of the acquired properties that we believe is generally consistent with industry practices. However, such a review will not reveal all existing problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we pay to acquire oil and natural gas properties may exceed the value we realize.
Also, our reviews of acquired properties are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given the time constraints imposed by the applicable acquisition agreement. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor would it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.
We may not identify all risks associated with the acquisition of oil and natural gas properties or existing wells, and any indemnification received from sellers may be insufficient to protect us from such risks, which may result in unexpected liabilities and costs to us.
We have acquired and may make additional acquisitions of undeveloped oil and gas properties from time to time, subject to available resources. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and other liabilities and other factors. Generally, it is not feasible for us to review in detail every individual property involved in a potential acquisition. In making acquisitions, we generally focus most of the title, environmental and valuation efforts on the properties that we believe to be more significant, or of higher value. Even a detailed review of properties and records may not reveal all existing or potential problems, nor would it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not inspect in detail every well that any of us acquires. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we perform a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively affect our financial condition and results of operations.
Even if we are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems, the indemnity may not be fully enforceable, the amount of recoverable losses may be limited by floors and caps, or the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on the ability to recover the costs related any potential problem could materially affect our financial condition and results of operations.
Ownership of our oil, gas and NGLs production depends on good title to our respective properties.
Good and clear title to our oil and gas properties is important. Although we will generally conduct title reviews before the purchase of most oil, gas, NGLs and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat a claim, which could result in a reduction or elimination of the revenue received by us or AGP from such properties.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition and results of operations.
We are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of our doing business.
Our operations are regulated extensively at the federal, state and local levels. The regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas, NGLs and oil we may produce and sell. A major risk inherent in a drilling plan is the need to obtain drilling permits (which can include financial responsibility requirements) from state agencies and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our respective properties. The natural gas, NGLs and oil regulatory environment could also change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. We may be put at a competitive disadvantage to larger companies in the industry that can spread these additional costs over a greater number of wells and these increased regulatory hurdles over a larger operating staff.
Because we handle natural gas, NGLs and oil, we may incur significant costs and liabilities in the future in order to comply with, or as a result of failing to comply with, new or existing environmental regulations or from an accidental release of substances into the environment.
How we plan, design, drill, install, operate and abandon natural gas and oil wells and associated facilities are matters subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:
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The federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;
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The federal Clean Water Act and comparable state laws and regulations that impose obligations related to spills, releases, streams, wetlands and discharges of pollutants into regulated bodies of water;
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The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our facilities;
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The federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal; and
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Wildlife protection laws and regulations such as the Migratory Bird Treaty Act and the Endangered Species Act, which require operators to cover reserve pits during the cleanup phase of the pit, if the pit is open more than 90 days, and impose restrictions regarding the extent and timing of development, including, for example, prohibitions for tree clearing.
Complying with these environmental requirements may increase costs and prompt delays in natural gas, NGLs and oil production. It is possible that the costs and delays associated with compliance with such requirements could cause us to delay or abandon the further development of certain properties. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations.
There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business and the substances we handle. For example, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and remediation costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover remediation costs, or other losses/damages, under our respective insurance policies.
We may incur costs or delays and encounter operational restrictions in connection with complying with stringent environmental regulations that apply specifically to hydraulic fracturing.
Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand, and chemical additives under pressure into formations to fracture the surrounding rock and stimulate production. Some of the potential effects of Federal, state, and local environmental regulation of hydraulic fracturing, including future changes in such regulation, could include the following:
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additional permitting requirements and permitting delays;
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increased costs;
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changes in the way operations, drilling and/or completion must be conducted;
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increased recordkeeping and reporting; and
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restrictions on the types of additives that can be used and locations in which we can operate.
Restrictions on hydraulic fracturing could also reduce the amount of natural gas, NGLs and oil that we are ultimately able to produce from our reserves.
State regulation of hydraulic fracturing and related development operations could result in increased costs and additional operating restrictions or delays.
The hydraulic fracturing and related development operations processes are typically regulated by state oil and natural gas commissions or by state environmental agencies. Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing and related development operations in certain circumstances. State regulation of hydraulic fracturing can take many forms. Among the forms of regulation that do, and in the future could, affect our operations or increase our costs are the following:
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Typically, states impose, by means of permits, well casing, cementing, drilling, mechanical integrity, completion, well control, and plugging and abandonment requirements to ensuring hydraulic fracturing and related development operations do not contaminate groundwater and nearby surface water.
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Most states require the disclosure of chemicals used in hydraulic fracturing fluids.
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Many states have imposed controls on the management, reuse, recycling, and disposal of hydraulic fracturing flowback fluid and production fluids.
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States limit when venting/flaring of casing head gas and gas well gas may occur.
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States may limit where fracturing can be performed and/or impose operating restrictions in certain geographic regions (i.e., location standards). For example, in areas in which there are concerns regarding induced seismicity, a state could curtail fracturing operations in the area or allow its continuance only under certain operational limitations.
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States may impose performance standards for surface activities at oil and natural gas well sites (including containment and spill response and remediation practices) and requiring operators to identify and monitor abandoned, orphaned and inactive wells prior to hydraulic fracturing.
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States may impose conditions on the disposal of drilling wastes containing naturally occurring radioactive material, as well as regulations applying to facilities that receive such wastes.
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States could even take the step of a total ban on hydraulic fracturing, as New York has done, blocking our business from that state.
Local and municipal laws could also result in increased costs and additional operating restrictions or delays.
In addition to state law, local land use restrictions, such as municipal ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing and related operations in particular. In some jurisdictions, the authority of localities to regulate hydraulic fracturing has become contentious. Courts have been asked to determine whether state regulatory schemes “pre-empt” local regulation. The outcome of legal challenges to local efforts to regulate hydraulic fracturing depends in large part on the intent of the State legislature and the comprehensiveness of its statutory scheme. If the right of municipalities to impose additional requirements is upheld, and municipalities elect to do so, local rules could impose additional constraints - such as siting and setback restrictions - and costs on our operations.
If the federal government were to comprehensively regulate hydraulic fracturing, it could impose greater costs or additional restrictions on our operations.
To date, hydraulic fracturing has not generally been subject to comprehensive regulation at the federal level. Instead, there has been limited federal regulation. For example, U.S. EPA released guidance, under its Safe Drinking Water Act underground injection control authority, regarding the use of diesel fuels in hydraulic fracturing. Implementation of the guidance will largely occur through State permitting programs. As another example, the Department of Interior’s Bureau of Land Management had issued regulations governing the conduct of hydraulic fracturing federal and Indian lands, but, on June 21, 2016, a Wyoming federal district judge invalidated the rules on the basis that Congress had not given the Department authority to regulate in this manner. The Federal government appealed the decision to the 10th Circuit Court of Appeals on June 24, 2016, and the litigation is ongoing. On-going federal agency environmental reviews of hydraulic fracturing could, however, result in additional regulation. Or Congress could adopt new laws affecting our operations or directing a federal agency to regulate our operations in new or additional ways. Any such development on the federal level could make it more difficult or costly for us to perform hydraulic fracturing to stimulate production from dense subsurface rock formations.
Our drilling and production operations require both adequate sources of water to facilitate the fracturing process and the disposal of flowback and produced fluids. If we are unable to dispose of the flowback and produced fluids at a reasonable cost and in compliance with applicable environmental rules, our ability to produce gas economically and in commercial quantities could be impaired.
A significant portion of our natural gas, NGLs and oil extraction activities utilize hydraulic fracturing, which results in water that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance. Our ability to collect and dispose of flowback and produced fluids will affect our production, and potential increases in the cost of wastewater treatment, handling, and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of wastewater, drilling fluids and other substances associated with the exploration, development and production of natural gas, NGLs and oil.
Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, while potential physical effects of climate change could disrupt our operations and cause us to incur significant costs in preparing for or responding to those effects.
Future laws and regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with its operations.
With the issuance, on March 28, 2017, of President Trump’s Executive Order on Promoting Energy Independence and Economic Growth, we believe it may take many years for new comprehensive federal policy aimed at greenhouse gas emissions to gel (see “Item 1. Business- Environmental Matters and Regulation - Greenhouse Gas Regulation and Climate Change”). Given the Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are “air pollutants” covered by the Clean Air Act) and scientific hurdles to overturning EPA’s endangerment finding, we believe the new Administration will have to pursue some form of regulation. Regulations with the most direct impact on our operations concern controlling methane emissions from wells. Rules that affect overall consumption of fossil fuels, and the mix of fossil fuels consumed, could also affect the demand for our products. We believe, however, that federal agency implementation of the President’s Executive Order is some years away. While Congress has from time to time considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. Reports of greater Congressional activity with respect to greenhouse gas emissions are scare.
In the absence of comprehensive federal climate change policy, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing greenhouse gas emissions by means of cap and trade programs that typically require major sources of greenhouse gas emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those greenhouse gases. States may also pursue additional regulation of our operations, including restrictions on methane emissions from new and existing wells and fracturing operations. State and regional initiatives could result in significant costs, including increased capital expenditures and operating costs, affect the demand for our products, and could affect the results of their business.
Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations.
Rules regulating air emissions from oil and natural gas operations could cause us to incur increased capital expenditures and operating costs.
In 2012, USEPA established the NSPS rule for oil and natural gas production, transmission, and distribution, and also made significant revisions to the existing National Emission Standards for Hazardous Air Pollutants (“NESHAP”) rules for oil and natural gas production, transmission, and storage facilities. These rules require oil and natural gas production facilities to conduct “green completions” for hydraulic fracturing, which is recovering rather than venting the gas and natural gas liquids that come to the surface during completion of the fracturing process. The rules also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. Both the NSPS and NESHAP rules continue to evolve based on new information and changing environmental concerns. President Trump’s March 28, 2017, Executive Order on Promoting Energy Independence and Economic Growth ordered federal agencies to revisit federal rules aimed at limiting methane emissions from oil and gas wells. We believe it will be several years before those new rules are fully implemented
States are also proposing increasingly stringent requirements for air pollution control and permitting for well sites and compressor stations. For example, in January 2016, the Governor of Pennsylvania announced a comprehensive new regulatory strategy for reducing methane emissions from new and existing oil and natural gas operations, including well sites, compressor stations, and pipelines. Implementation of this strategy will result in significant changes to the air permitting and pollution control standards that apply to the oil and gas industry in Pennsylvania. It may also influence air programs in other oil and gas-producing states. Moreover, West Virginia issued General Permit 70-A for natural gas production facilities at the well site in 2013. In response to industry concerns regarding the restrictiveness of the general permit, in November 2015, West Virginia issued General Permit 70-B which provides more flexibility for emission sources located at the well site.
Compliance with new rules regulating air emissions from AGP’s operations could result in significant costs, including increased capital expenditures and operating costs, and could affect the results of its business.
If fully implemented, environmental policies the new President supported during his campaign could increase supply in the overall markets for fuels, thereby potentially reducing prices for the Company’s output.
During the election campaign, President Trump pledged to implement policies that would reinvigorate coal’s use for energy production and ease restrictions on production and transportation of petroleum. If fully implemented, these policies could have the effect of increasing the overall fuel supply, thereby reducing prices for the Company’s output. For example, President Trump pledged to reverse the prior Administration’s policies that disadvantaged coal as a fuel for energy production. President Trump promised to take several actions to encourage burning coal for energy production and lessen the financial burden of environmental regulations on coal-fired plants’ operations. The President pledged to withdraw from the Paris Climate Agreement, withdraw or re-write the Clean Power Plan, withdraw mercury limits on coal plants’ air emissions, lift the prior Administration’s ban on new coal leases on federal lands and end the review of the program’s greenhouse gas impacts, and withdraw the “Waters of the United States” stream protection rule. The new Administration has taken this final action. President Trump also indicated his Administration would open more federal lands for oil and gas production, approve the construction of the Keystone Pipeline to facilitate refining of Alberta oil shale in the U.S., license the Dakota Access Pipeline, and open areas in the Arctic and Atlantic Ocean to drilling. If fully implemented, these policies would increase the overall fuel supply and could have the effect of diminishing demand for the Company’s natural gas output. Diminished demand could put additional downward pressure on the price of the natural gas the Company produces.
Because we handle natural gas, NGLs and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of substances into the environment.
How we plan, design, drill, install, operate and abandon natural gas wells and associated facilities are matters subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:
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the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions;
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the federal Clean Water Act and comparable state laws and regulations that impose obligations related to spills, releases, streams, wetlands and discharges of pollutants into regulated bodies of water;
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the federal Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters;
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the federal Comprehensive Environmental Response, Compensation, and Liability Act, or “CERCLA,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by AGP or at locations to which we have sent waste for disposal; and
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wildlife protection laws and regulations such as the Migratory Bird Treaty Act that requires operators to cover reserve pits during the cleanup phase of the pit, if the pit is open more than 90 days.
Complying with these requirements is expected to increase costs and prompt delays in natural gas production. There can be no assurance that we will be able to obtain all necessary permits and, if obtained, that the costs associated with obtaining such permits will not exceed those that previously had been estimated. It is possible that the costs and delays associated with compliance with such requirements could cause AGP to delay or abandon the further development of certain properties.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. These enforcement actions may be handled by USEPA and/or the appropriate state agency. In some cases, USEPA has taken a heightened role in enforcement activities targeting the oil and gas extraction sector. For example, in 2011, USEPA Region III requested the lead on all oil and gas related violations in the United States Army Corps of Engineers’ Pittsburgh District. USEPA, the United States Army Corps of Engineers and the United States Department of Justice have been actively pursuing instances of unpermitted stream and wetland impacts, particularly for activities occurring in West Virginia. We also understand that USEPA has taken an increased interest in assessing operator compliance with the Spill Prevention, Control and Countermeasures regulations, set forth at 40 CFR Part 112.
Certain environmental statutes, including RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where certain substances have been disposed of or otherwise released, whether caused by our operations, the past operations of its predecessors or third parties. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
There is an inherent risk that we may incur environmental costs and liabilities due to the nature of the businesses and the substances handled. For example, an accidental release from one of AGP’s wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our compliance costs
and the cost of any remediation that may become necessary. We may not be able to recover remediation costs under their insurance policies.
We are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of doing business.
Our operations are regulated extensively at the federal, state and local levels. The regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas and oil we may produce and sell. A major risk inherent in a drilling plan is the need to obtain drilling permits from state agencies and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our respective properties. The natural gas and oil regulatory environment could also change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. For example, Pennsylvania’s 2012 Oil and Gas Act imposes significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for unconventional gas wells, based on the price of natural gas and the age of the unconventional gas well. PADEP’s proposed regulatory amendments associated with this legislation, when finalized will affect how natural gas operations are conducted in Pennsylvania. Moreover, PADEP has indicated that more regulatory amendments are likely to be proposed in 2016. West Virginia has promulgated regulations associated with its existing Horizontal Well Control Act and has developed new aboveground storage tank laws that are being applied broadly and impose stringent requirements that affect the natural gas industry. We may be put at a competitive disadvantage to larger companies in the industry that can spread these additional costs over a greater number of wells and these increased regulatory hurdles over a larger operating staff.
Estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we will make certain assumptions regarding future natural gas prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Our PV-10 and standardized measure are calculated using natural gas prices that do not include financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from the reserve estimates.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of the estimated natural gas and oil reserves. We base the estimated discounted future net cash flows from proved reserves on historical prices and costs, but actual future net cash flows from our natural gas and oil properties will also be affected by factors such as:
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actual prices received for natural gas and oil;
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the amount and timing of actual production;
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the amount and timing of capital expenditures;
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supply of and demand for natural gas and oil; and
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changes in governmental regulations or taxation.
The timing of both the production and incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor that we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the company or the natural gas and oil industry in general.
Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and standardized measure, and the financial condition and results of operations. In addition, our reserves or PV-10 and standardized measure may be revised downward or upward based upon production history, results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of reserves because the economic life of the wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10 and standardized measure.
Risks Relating to the Ownership of Our Common Units
Our common units are quoted on the OTCQX and have a limited trading market.
As of March 21, 2016, our common units commenced being quoted on the OTCQX Market (the “OTCQX”). The OTCQX is not an exchange and the quotation of our common units on the OTCQX does not assure that a liquid trading market exists or will develop. Securities traded on the OTCQX marketplace generally have limited trading volume and exhibit a wider spread between the bid/ask quotations compared to securities traded on national securities exchanges such as the NYSE, on which our common units were previously listed. As a result, investors may find it difficult to dispose of, or to obtain accurate quotations of the price of, our common units. This significantly limits the liquidity of the common units and may adversely affect the market price of our common units. Moreover, a significant number of institutional investors have investment policies that prohibit them from trading in securities on the OTCQX marketplace. In addition, since our common units are quoted on the OTCQX, our common units are not “covered securities” for purposes of the Securities Act and our unitholders may face significant restrictions on the resale of our common units due to a state’s own securities laws, often called “blue sky” laws. Not being listed on a national securities exchange and a limited trading market may also impair our ability to raise additional financing through public or private sales of equity securities and could also have other negative results, including the loss of institutional investor interest and fewer business development opportunities.
If prices of our common units decline, our common unitholders could lose a significant part of their investment.
The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
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changes in securities analysts’ recommendations and their estimates of our financial performance;
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the public’s reaction to our press releases, announcements and our filings with the SEC;
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fluctuations in broader securities market prices and volumes, particularly among securities of natural gas and oil companies;
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fluctuations in natural gas and oil prices;
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changes in market valuations of similar companies;
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departures of key personnel;
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commencement of or involvement in litigation;
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variations in our quarterly results of operations or those of other natural gas and oil companies;
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variations in the amount of our cash distributions;
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future issuances and sales of our securities; and
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changes in general conditions in the U.S. economy, financial markets or the natural gas and oil industry.
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
The trading price of our common units may be volatile, with the result that an investor may not be able to sell any shares acquired at a price equal to or greater than the price paid by the investor.
Our Common Shares are quoted on the OTCQX Market under the symbol “ATLS.” These markets are relatively unorganized, inter-dealer, over-the-counter markets that provide significantly less liquidity than the NASDAQ or the NYSE. Although we will use our commercially reasonable efforts to list our common units on the NYSE (or other national securities exchange approved by our board of directors as soon as practicable after the applicable listing standards are satisfied or have been waived, no assurances can be
given that our common units can be listed on the NYSE (or other national securities exchange). In this event, there would be a highly illiquid market for our common units and you may be unable to dispose of your common units at desirable prices or at all.
Sales of our common units may cause our share price to decline.
Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our shares to decline. In addition, the sale of these common units could impair our ability to raise capital through the sale of additional shares.
Certain provisions of our LLC Agreement and Delaware law could deter acquisition proposals and make it difficult for a third party to acquire control of us. This could have a negative effect on the price of our common units.
Our LLC Agreement contains provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include:
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a board of directors that is divided into three classes with staggered terms, and this classified board provision could have the effect of making the replacement of incumbent directors more time consuming and difficult;
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rules regarding how our common unitholders may present proposals or nominate directors for election;
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the inability of our common unitholders to call a special meeting;
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the inability of our common unitholders to remove directors; and
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the ability of our directors, and not unitholders, to fill vacancies on our board of directors.
These provisions are intended to protect our common unitholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions will apply even if an offer may be considered beneficial by some of our unitholders and could delay or prevent an acquisition that our board of directors determines is in our best interest and that of our unitholders. These provisions may also prevent or discourage attempts to remove and replace incumbent directors. Any of the foregoing provisions could limit the price that some investors might be willing to pay for our common units.
With limited exceptions, our LLC Agreement restricts the voting rights of unitholders that own 20% or more of our common units.
Our LLC Agreement prohibits any person or group that owns 20% or more of our common units then outstanding, other than persons who acquire common units with the prior approval of our board of directors, from voting on any matter.
Our unitholders who fail to furnish certain information requested by our board of directors or who our board of directors determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.
We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any member. Our board of directors may require any member or transferee to furnish information about his nationality, citizenship or related status. If a member fails to furnish information about his nationality, citizenship or other related status within a reasonable period after a request for the information or our board of directors determines after receipt of the information that the member is not an eligible citizen, the member may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information.
Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.
If our board of directors determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our members, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our board of directors may adopt such amendments to our LLC Agreement as it determines are necessary or appropriate to obtain proof of the U.S. federal income tax status of our members (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rate that
can be charged to customers by our subsidiaries or who fails to comply with the procedures instituted by our board of directors to obtain proof of the U.S. federal income tax status.
Tax Risks to Unitholders
We expect to engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.
We continually monitor the respective capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. As such, we are actively evaluating potential transactions to deleverage our balance sheet and manage our liquidity, which could include reducing existing debt through debt exchanges, debt repurchases and other modifications and extinguishment of existing debt. If, as expected, we execute such a strategic transaction, we expect that we would recognize cancellation of indebtedness income (“CODI”), which will be allocated to our unitholders at the time of such transaction. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of liquidity and capital resources.
The amount of CODI generally will be equal to the excess of the adjusted issue price of the restructured debt over the value of the consideration received by debtholders in exchange for the debt. In certain cases, CODI can be realized even when existing debt is modified with no reduction in such debt’s stated principal amount. We will not make a corresponding cash distribution with respect to such allocation of CODI. Therefore, any CODI will cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to such unitholder. Such CODI, like other items of our income, gain, loss, and deduction that are allocated to our unitholders, will be taken into account in the taxable income of the holders of our units as appropriate. CODI is not itself an additional tax due but is an amount that must be reported as ordinary income by the unitholder, potentially increasing such unitholder’s tax liabilities.
Our unitholders may not have sufficient tax attributes available to offset such allocated CODI. Moreover, CODI that is allocated to our unitholders will be ordinary income, and, as a result, it may not be possible for our unitholders to offset such CODI by claiming capital losses with respect to their units, even if such units are cancelled for no consideration in connection with such a restructuring. Importantly, certain exclusions that are available with respect to CODI generally do not apply at the partnership level, and any solvent unitholder that is not in a Chapter 11 proceeding will be unable to rely on such exclusions.
CODI with respect to any future transaction undertaken by us will be allocated to our unitholders of record (as applicable) on the date on which such a strategic transaction closes (the “CODI Allocation Date”). No CODI should be allocated to a unitholder with respect to units which are sold prior to the CODI Allocation Date.
Each unitholder’s tax situation is different. The ultimate effect to each unitholder will depend on the unitholder’s individual tax position with respect to its units. Additionally, certain of our unitholders may have more losses available than other of our unitholders, and such losses may be available to offset some or all of the CODI that could be generated in a strategic transaction involving our debt. Accordingly, unitholders are highly encouraged to consult, and depend on, their own tax advisors in making such evaluation.
Unitholders are required to pay taxes on their share of our taxable income, including their share of ordinary income and capital gain upon dispositions of properties by us or cancellation of our debt, even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholder’s interest in our economic profits.
Our unitholders are required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
We expect to engage in transactions in the future that would result in CODI that will be allocated to our unitholders. Some or all of our unitholders may be allocated substantial amounts of such taxable income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect to each unitholder would depend on the unitholder’s individual tax position with respect to the units; however, taxable income allocations from us, including CODI, increase a unitholder’s tax basis in their units.
In addition, we and our subsidiaries may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the proceeds to our unitholders, and some or all of our unitholders may be allocated substantial taxable income with respect to that sale. A unitholder’s share of our taxable income upon a disposition of property by us may be ordinary income or capital gain or some combination thereof. Even where we dispose of properties that are capital assets, what otherwise would be capital gains may be recharacterized as ordinary income in order to “recapture” ordinary deductions that were previously allocated to that unitholder related to the same property.
A unitholder’s share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially less than, the unitholder’s interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange. Cash distributions from us decrease a unitholder’s tax basis in its units, and the amount, if any, of excess distributions over a unitholder’s tax basis in its units will, in effect, become taxable income to the unitholder, above and beyond the unitholder’s share of our taxable income and gain (or specific items thereof).
In addition, we have issued and outstanding as of December 31, 2016 approximately 1.8 million Series A convertible preferred units with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”) to certain members of our management, two management members of the Board, and outside investors. All of the Series A Preferred Units are convertible into approximately 5.7 million common units at the option of the holder at any time. If the Series A Preferred Units are converted into common units, net income that otherwise would have first been allocated to the Series A Preferred Units will instead be allocated to all common unitholders, including the holders of common units received in the conversion. Such net income allocations could include types of income, including CODI, for which our unitholders may not receive cash distributions from us equal to their share of such taxable income or even equal to the actual tax liability that results from their share of such taxable income.
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to a material amount of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.
The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.
We are currently treated as a partnership for U.S. federal income tax purposes, which requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for U.S. federal income tax purposes or otherwise be subject to U.S. federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to unitholders would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to them. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.
Current law or our business may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced.
Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.
Unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
A successful IRS contest of the U.S. federal income tax positions we take may harm the market for our common units, and the costs of any contest will reduce cash available for distribution.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter that affects us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and a court may disagree with some or all of those positions. Any contest with the IRS may lower the price at which our common units trade. In addition, our costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
We will treat each holder of our common units as having the same tax benefits without regard to the common units held. The IRS may challenge this treatment, which could reduce the value of the common units.
Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could reduce the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.
The sale or exchange of 50% or more of our, or AGP’s capital and profits interest within a 12-month period will result in the termination of our, or AGP’s partnership for U.S. federal income tax purposes.
We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in our capital and profits within a 12-month period. Likewise, AGP will be considered to have terminated its partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in their capital and profits within a 12-month period. The termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of U.S. federal taxable income for the year in which we are considered to be terminated and for later years as a percentage of the cash distributed to the unitholder with respect to that period.
Tax gain or loss on the disposition of our common units could be more or less than expected because prior distributions in excess of allocations of income will decrease unitholders’ tax basis in their units.
If unitholders sell any of their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions, and the allocation of losses (including depreciation deductions), to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to them. The current maximum marginal U.S. federal income tax rate on ordinary income is 39.6% plus a 3.8% Medicare surtax on investment income. As a result, a unitholder may incur a tax liability in excess of the amount of cash it receives from the sale.
Unitholders may be subject to state and local taxes and return filing requirements, including in states where they do not live, as a result of investing in our common units.
In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or AGP do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We, and AGP presently anticipate that substantially all of our income will be generated in Alabama, Colorado, Indiana, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia, West Virginia and Wyoming. As we make acquisitions or expand our businesses, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all U.S. federal, foreign, state and local tax returns that may be required of such unitholder.
The IRS may challenge our tax treatment related to transfers of units, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Recently, the U.S. Treasury Department issued Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. The regulations do not, however, specifically authorize the use of the proration method we have adopted. If the IRS were to challenge this method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Risks Relating to Our Conflicts of Interest
Although we control AGP and exercise significant control over Titan, certain duties are owed to each such entity and its unitholders, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including between us (as holder of the Series A Preferred Share of Titan), on the one hand, and Titan and its common shareholders, on the other hand, as well as between the general partner of AGP, on the one hand, and AGP and its limited partners, on the other hand. Our AGP’s general partner has a duty to manage AGP in a manner beneficial to us, its owner. At the same time, these directors and officers have a duty to manage AGP in a manner they believe is beneficial to the partnership’s interests. In addition, our officers and directors who serve as officers and directors of Titan owe certain duties. Titan’s board of directors and the board of directors of AGP’s general partner, or Titan’s or AGP’s respective conflicts committees, will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
Conflicts of interest may arise in the following situations, among others:
•
the allocation of shared overhead expenses;
•
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Titan or AGP, on the other hand;
•
the determination and timing of the amount of cash to be distributed to our and our subsidiaries’ partners and the amount of cash reserved for the future conduct of their businesses;
•
the decision as to whether Titan or AGP should make acquisitions, and on what terms; and
•
any decision we make in the future to engage in business activities independent of, or in competition with our subsidiaries.
Our affiliates may in certain circumstances compete with us or with each other, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, and this could adversely affect our results of operations and potential cash available for distribution to our unitholders.
Our LLC Agreement, Titan’s limited liability company agreement and the partnership agreements of AGP do not prohibit Titan, AGP or our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, our affiliates, Titan or AGP. In addition, Titan, AGP and their affiliates may acquire, develop or dispose of additional assets related to the production and development of oil, natural gas and NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. As a result, competition among these entities could adversely affect our results of operations and cash available for paying required debt service on our credit facilities or making distributions.
Pursuant to the terms of our LLC Agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our directors or executive officers or any of their affiliates. Some of these executive officers and directors also serve as officers of Titan and/or AGP. No such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any unitholder for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, Titan, AGP and their affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us on an operations basis.
Our LLC Agreement eliminates our directors’ and officers’ fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our directors and officers.
Our LLC Agreement contains provisions that eliminate any fiduciary standards to which our directors and officers and their affiliates could otherwise be held by state fiduciary duty laws. Instead, our directors and officers are accountable to us and our unitholders pursuant to the contractual standards set forth in our LLC Agreement. Our LLC Agreement reduces the standards to which our directors and officers would otherwise be held by state fiduciary duty law and contains provisions restricting the remedies available to unitholders for actions taken by our directors or officers or their affiliates. For example, it provides that:
•
whenever our board of directors or officers make a determination or take, or decline to take, any other action in such capacity, our directors and officers are required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard (including fiduciary standards) imposed by Delaware law or any other law, rule or regulation or at equity;
•
our directors and officers will not have any liability to us or our unitholders for decisions made in their capacity as a director or officer so long as they acted in good faith, meaning they believed that the decision was not adverse to our interests; and
•
our directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.
It will be presumed that, in making decisions and taking, or declining to take, actions, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
By accepting or purchasing a common unit, a unitholder agrees to be bound by the provisions of the LLC Agreement, including the provisions discussed above and, pursuant to the terms of our LLC Agreement, is treated as having consented to various actions contemplated in our LLC Agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law.
ITEM 1B:
ITEM 1B:
UNRESOLVED STAFF COMMENTS
None.
ITEM 2:
ITEM 2:
PROPERTIES
Natural Gas, Oil and NGL Reserves
The following tables summarize information regarding our estimated proved natural gas, oil and NGL reserves as of December 31, 2016 and 2015. Proved reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties as well as the reserves attributable to ARP’s percentage interests in the oil and gas properties owned by Drilling Partnerships in which ARP owned partnership interests. All of the reserves are located in the United States. We base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared independent third-party engineers. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas and oil properties. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 reserves will not be comparable to our 2015 reserves. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 31, 2016 and 2015, and are listed below as of the dates indicated:
(1)
Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for year ended December 31, 2015. Including the effect of this subordination, the average realized sales price was $2.19 per Mcf before the effects of financial hedging for year ended December 31, 2015.
Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas, oil and NGL reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
The preparation of our natural gas, oil and NGL reserve estimates were completed in accordance with prescribed internal control procedures by reserve engineers. Other than for ARP’s Rangely assets, for the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 40 years of experience in the estimation and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. For ARP’s Rangely assets, Cawley, Gillespie and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 34 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our President.
Results of drilling, testing and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas, oil and NGLs may be different from those estimated by our independent third-party engineers in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Due to these factors, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. The estimated standardized measure values may not be representative of the current or future fair market value of our proved natural gas and oil properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas, oil and NGL prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based (see “Item 1A: Risk Factors-Risks Relating to Our Business”).
We evaluate natural gas and oil reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas and oil reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. We base the estimates on operating methods and conditions prevailing as of the dates indicated:
(1)
At December 31, 2015, ARP’s ownership in these reserves was subject to reduction as ARP generally makes capital contributions, which includes leasehold acreage associated with ARP’s proved undeveloped reserves, to its Drilling Partnerships in exchange for an equity interest in these partnerships, which was approximately 30%, which would reduce ARP’s ownership interest in these reserves from 100% to its respective ownership interest as ARP makes these contributions.
(2)
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 reserves will not be comparable to our 2015 reserves.
Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells on which a relatively major expenditure is required for recompletion.
Proved Undeveloped Reserves (“PUDs”)
PUD Locations. As of December 31, 2016, we had 10 PUD locations totaling approximately 17 net Bcfe’s of natural gas, oil and NGLs. These PUDS are based on the definition of PUD’s in accordance with the SEC’s rules allowing the use of techniques that have been proven effective through documented evidence, such as actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.
Material changes in PUDs. As of January 1, 2016, we had 128 PUD locations totaling approximately 204 net Bcfe’s of natural gas, oil, and NGLs. Material changes in PUDS that occurred during the year ended December 31, 2016 were due to negative revisions
of approximately 24 Bcfe in PUDs due to the reduction of our five year drilling plans and unfavorable pricing environment and a decrease of 179 Bcfe due to the deconsolidation of ARP for financial reporting purposes.
Development Costs. There were no costs incurred related to the development of PUDs that remained after the deconsolidation of ARP for financial reporting purposes for the year ended December 31, 2016. As of December 31, 2016, there were no PUDs that had remained undeveloped for five years or more. The proved undeveloped reserves disclosed at December 31, 2016 are included within our five-year development plan and will be developed within five years of the initial disclosure.
Productive Wells
The following table sets forth information regarding productive natural gas and oil wells in which AGP has a working interest as of December 31, 2016. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which AGP has an interest directly and net wells are the sum of our fractional working interests in gross wells:
(1)
There were no exploratory wells drilled by AGP during the year ended December 31, 2016. There were no gross or net dry wells within AGP’s operating areas during the year ended December 31, 2016.
Developed and Undeveloped Acreage
The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of December 31, 2016:
(1)
Developed acres are acres spaced or assigned to productive wells.
(2)
Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(3)
A gross acre is an acre in which AGP owns a working interest. The number of gross acres is the total number of acres in which we own a working interest.
(4)
Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.5 net acres.
The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. There are no concessions for undeveloped acreage as of December 31, 2016. As of December 31, 2016, there are no leases set to expire on or before December 31, 2017 and 2018.
We believe that we hold good and indefeasible title related to our producing properties, in accordance with standards generally accepted in the industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.
Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.
ITEM 3:
ITEM 3:
LEGAL PROCEEDINGS
We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See “Item 8: Financial Statements and Supplementary Data - Note 11”.
ITEM 4:
ITEM 4:
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5:
ITEM 5:
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common units began trading on March 2, 2015 on the New York Stock Exchange (“NYSE”). On March 18, 2016, we were notified by the NYSE that it had determined to commence proceedings to delist our common units. Our common units commenced quotation on the OTCQX under the symbol “ATLS” on March 21, 2016. On April 12, 2017, the closing price of our common units was $0.19, and there were 160 holders of record of our common units. The following table sets forth the high and low sales price per unit of our common units as reported by the OTCQX and the NYSE for the year ended December 31, 2016 and the NYSE for the year ended December 31, 2015 and the cash distributions declared by quarter per unit on our common units:
(1)
The determination of the amount of future cash distributions declared, if any, is at the sole discretion of our General Partner’s board of directors and will depend on various factors affecting our financial conditions and other matters the board of directors deems relevant.
(2)
Reflects the high and low sales price per unit during the period from March 2, 2015, the date our common units began trading “regular way,” to March 31, 2015.
For information concerning common units authorized for issuance under our long-term incentive plan, see “Item 12: Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters - Equity Compensation Plan Information”.
ITEM 6:
ITEM 6:
SELECTED FINANCIAL DATA
The following table presents our selected historical combined consolidated financial data, as of and for the periods indicated and should be read in conjunction with “Item 7:
ITEM 7:
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with “Item 6: Selected Financial Data” and “Item 8: Financial Statements and Supplemental Data”, which contains our combined consolidated financial statements.
The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and in “Item 1A: Risk Factors”. We believe the assumptions underlying the consolidated financial statements are reasonable. However, our combined consolidated financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future.
BUSINESS OVERVIEW
We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our combined and consolidated subsidiaries.
On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.
Our operations primarily consisted of our ownership interests in the following:
•
During the period September 1, 2016 to December 31, 2016, Titan, an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States. Titan Management holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests and to appoint four of seven directors). Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. As discussed further below, Titan is the successor to the business and operations of ARP;
•
Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 24,712,471 common limited partner units) in ARP. As discussed further below, ARP was the predecessor to the business and operations of Titan;
•
all of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in AGP, a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas; and
•
12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of our board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt.
Our cash flows and liquidity are substantially dependent upon AGP’s annual management fee and distributions from AGP, Lightfoot, and Titan. Neither AGP nor Titan are currently paying distributions. Though we consolidate the operations of AGP (and, prior to July 27, 2016, we consolidated the operations of ARP) for financial reporting purposes, AGP’s annual management fee and distributions from Lightfoot are currently our only sources of liquidity to satisfy our obligations under our credit agreements. In addition, the obligations under our first lien credit agreement mature in September 2017. As a result, we continue to face significant liquidity issues and are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and strengthen our balance sheet. Please see “Item 1A Risk Factors-Risks Related to Our Business- Our long term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time, and we are currently considering, and are likely to make, changes to our capital structure to maintain sufficient liquidity, meet our debt obligations and manage and strengthen our balance sheet.”
RECENT DEVELOPMENTS
Atlas Resource Partners
ARP Restructuring and Emergence from Chapter 11 Proceedings
On July 25, 2016, we, along with ARP and certain of its subsidiaries, solely with respect to certain sections thereof, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% Senior Notes due 2021 (the “7.75% Senior Notes”) and the 9.25% Senior Notes due 2021 (the “9.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties agreed, subject to certain terms and conditions, to support ARP’s restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).
On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”
ARP operated its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired by the Plan and were satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.
On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:
•
the First Lien Lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche.
•
the Second Lien Lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, the Second Lien Lenders received a pro rata share of 10% of the common equity interests of Titan, subject to dilution by a management incentive plan.
•
Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of the common equity interests of Titan, subject to dilution by a management incentive plan.
•
all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.
•
ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
•
Titan Energy Management, LLC, our wholly owned subsidiary (“Titan Management”), received a Series A Preferred Share of Titan, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests and to appoint four of seven directors) in Titan and certain other rights. Four of the seven initial members of the board of directors of Titan are designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in Titan’s limited liability company agreement), subject to the receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of Titan unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.
We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses.
Atlas Growth Partners
Primary Offering Suspension
On November 2, 2016, AGP’s Board of Directors elected to suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. At this time, AGP can provide no certainty as to when or if its primary offering efforts will be reinstituted.
Cash Distributions.
On November 2, 2016, AGP’s Board of Directors elected to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order retain its cash flow and reinvest in its business and assets. At this time, AGP can provide no certainty as to when or if distributions will be reinstituted.
FINANCIAL PRESENTATION
Our combined consolidated financial statements were derived from the accounts of Atlas Energy and its controlled subsidiaries for the periods prior to February 27, 2015. Because a direct ownership relationship did not exist among all the various entities consolidated in our combined consolidated financial statements, Atlas Energy’s net investment in us is shown as equity in the combined consolidated financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive our financial statements. Actual balances and results could be different from those estimates. All significant intercompany transactions and balances have been eliminated in the combination of the financial statements.
Our combined consolidated financial statements contain our accounts and those of our combined consolidated subsidiaries as of December 31, 2016. We determined that ARP (through the Plan Effective Date, as discussed further below) and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct the activities that most significantly impact each of their respective economic performance, and our ownership of each of their respective incentive distribution rights. Accordingly, we consolidated the financial statements of ARP (until the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP into our combined consolidated financial statements. As the general partner for both ARP (through the Plan Effective Date) and AGP, we have unlimited liability for the obligations of ARP (through the Plan Effective Date) and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP (through the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated.
In connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our combined consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a
result of these changes, our combined consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our combined financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.
On the Plan Effective Date, we determined that Titan is a VIE based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions.
Throughout this section, when we refer to “our” combined consolidated financial statements, we are referring to the combined consolidated results for us, our wholly-owned subsidiaries and the consolidated results of ARP and AGP, adjusted for non-controlling interests in ARP and AGP.
GENERAL TRENDS AND OUTLOOK
We expect our and our subsidiaries’ businesses to be affected by the following key trends. Our expectations are based on assumptions made by us and our subsidiaries and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our and our subsidiaries’ actual results may vary materially from our expected results.
The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines since the fourth quarter of 2014 and have continued to remain low in 2016. The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.
Our subsidiaries’ future gas and oil reserves, production, cash flow, the ability to make payments on debts and the ability to make distributions to unitholders, including AGP’s ability to make distributions to us, depend on our subsidiaries’ success in producing current reserves efficiently, developing existing acreage and acquiring additional proved reserves economically. Our subsidiaries face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decrease. Our subsidiaries attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than produced. To the extent our subsidiaries do not have sufficient capital, our subsidiaries’ ability to drill and acquire more reserves will be negatively impacted.
RESULTS OF OPERATIONS
Gas and Oil Production
We deconsolidated ARP for financial reporting purposes as of the date of the Chapter 11 Filings and therefore our 2016 combined consolidated financial statements will not be comparable to our 2015 and 2014 combined financial statements.
Production Profile. Currently, our gas and oil production revenues and expenses consist of our gas and oil production activities derived from our wells drilled in the Eagle Ford, Marble Falls and Mississippi Lime plays. We have established production positions in the following operating areas:
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the Eagle Ford Shale in southern Texas, an oil-rich area, in which we acquired acreage in November 2014;
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the Marble Falls play in the Fort Worth Basin in northern Texas, in which we own acreage and producing wells, contains liquids rich natural gas and oil, and;
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the Mississippi Lime play in northwestern Oklahoma, an oil and NGL-rich area.
The following table presents the number of wells our subsidiaries drilled and the number of wells our subsidiaries turned in line, both gross and for our respective interests, during the periods indicated:
(1)
Includes (i) ARP’s percentage interest in the wells in which it has a direct ownership interest and (ii) ARP’s percentage interest in the wells based on its percentage ownership in its Drilling Partnerships.
(2)
Includes AGP’s percentage interest in the wells in which it has a direct ownership interest.
(3)
Wells turned in line refers to wells that have been drilled, completed, and connected to a gathering system.
(4)
Neither ARP nor AGP drilled any exploratory wells during the periods presented; neither ARP nor AGP had any gross or net dry wells within their operating areas during the periods presented.
(5)
The drilling activity related to AGP’s Eagle Ford operating area was included effective November 5, 2014, the date of acquisition. Ten wells were drilled by the prior owner but not yet turned in line, at the date of acquisition.
(6)
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.
Production Volumes. The following table presents total net natural gas, crude oil and NGL production volumes and production per day for the periods indicated:
(1)
Production quantities consist of the sum of (i) the proportionate share of production from wells in which our subsidiaries have a direct interest, based on the proportionate net revenue interest in such wells, and (ii) ARP’s proportionate share of production from wells owned by the Drilling Partnerships in which it has an interest, based on ARP’s equity interest in each such Drilling Partnership and based on each Drilling Partnership’s proportionate net revenue interest in these wells.
(2)
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.
Production Revenues, Prices and Costs. Production revenues and estimated gas and oil reserves are substantially dependent on prevailing market prices for natural gas and oil. The following table presents production revenues and average sales prices for AGP’s and ARP’s natural gas, oil, and NGLs production for each of the periods indicated, along with average production costs, which include lease operating expenses, taxes, and transportation and compression costs, in each of the reported periods:
(1)
Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for each of the periods presented. Including the effect of this subordination, ARP’s average realized gas sales price was $3.41 per Mcf ($1.66 per Mcf before the effects of financial hedging), $3.36 per Mcf ($2.19 per Mcf before the effects of financial hedging) and $3.67 per Mcf ($3.84 per Mcf before the effects of financial hedging) for the years ended December 31, 2016, 2015 and 2014, respectively.
(2)
Includes the impact of $0.2 million and $0.5 million of cash settlements for the years ended December 31, 2016 and 2015, respectively, on AGP’s oil derivative contracts which were entered into subsequent to our decision to discontinue hedge accounting beginning on January 1, 2015. Includes the impact of cash settlements on ARP’s commodity derivative contracts not previously included within accumulated other comprehensive income following ARP’s decision to de-designate hedges beginning on January 1, 2015. Cash settlements on ARP’s commodity derivative contracts excluded from production revenues consisted of $62.6 million and $48.6 million associated with natural gas derivative contracts, and $26.5 million and $35.8 million associated with crude oil derivative contracts for the years ended December 31, 2016 and 2015, respectively. Cash settlements on ARP’s natural gas liquids derivative contracts excluded from production revenues were $8.3 million for the year ended December 31, 2015 (see “Item 8. Financial Statements and Supplementary Data - Note 7”).
(3)
Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for each of the periods presented. Including the effects of these costs, ARP’s total lease operating expenses per Mcfe were $1.16 per Mcfe ($1.58 per Mcfe for total production costs), $1.32 per Mcfe ($1.74 per Mcfe for total production costs) and $1.25 per Mcfe ($1.77 per Mcfe for total production costs) for the years ended December 31, 2016, 2015 and 2014, respectively. Including the effects of these costs, total lease operating expenses per Mcfe were $1.14 per Mcfe ($1.56 per Mcfe for total production costs), $1.31 per Mcfe ($1.73 per Mcfe for total production costs) and $1.26 per Mcfe ($1.78 per Mcfe for total production costs) for the years ended December 31, 2016, 2015 and 2014, respectively.
(4)
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 results will not be comparable to our 2015 and 2014 results.
The $238.9 million decrease in our production revenues for the year ended December 31, 2016 as compared to the prior year period consisted primarily of decreases in all ARP operating areas attributable to lower production volumes and decreases in oil and NGL commodity prices compared to the prior year period. In addition, we deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented. AGP’s gas and oil production revenues for the year ended December 31, 2016 were comparable to the prior year period consisting of a $0.9 million increase attributable to production from AGP’s Eagle Ford operations, primarily related to two more wells being turned in line during 2016 and a full year of production for the wells that were turned in line during 2015, partially offset by an $0.8 million decrease attributable to AGP’s Marble Falls operations primarily related to lower volumes and a $0.1 million decrease attributable to AGP’s Mississippi Lime operations primarily related to lower volumes.
The $93.8 million decrease in our production costs for the year ended December 31, 2016 as compared to the prior year period was primarily a result of ARP’s efforts to reduce operating costs in each of its areas of production. In addition, we deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented. AGP’s gas and oil production expenses for the year ended December 31, 2016 were comparable to the prior year period consisting of a $1.1 million increase attributable to AGP’s Eagle Ford operations, partially offset by a decrease of $0.7 million attributable to AGP’s Marble Falls operations. Total production costs per Mcfe decreased to $1.60 per Mcfe for the year ended December 31, 2016 from $1.75 per Mcfe for the comparable prior year period primarily as a result of continued efforts to reduce operating costs in each of our areas of production.
The $106.9 million decrease in our production revenues for the year ended December 31, 2015 as compared to the prior year period principally consisted of a $76.5 million decrease attributable to ARP’s Barnett Shale/Marble Falls operations, a $39.6 million decrease attributable to ARP’s coal-bed methane assets, a $39.3 million decrease attributable to ARP’s Appalachia assets and a $19.6 million decrease attributable to ARP’s Mississippi Lime/Hunton assets, partially offset by a $29.6 million increase attributable to ARP’s Rangely assets acquired during the year ended December 31, 2014, a $28.1 million increase attributable to ARP’s Eagle Ford assets acquired during the year ended December 31, 2014 and a $4.2 million decrease in gas revenues subordinated to the investor partners within ARP’s Drilling Partnerships. AGP’s $6.1 million increase in gas and oil production revenues for the year ended December 31, 2015 as compared to the prior year period consisted of a $10.4 million increase attributable to production from AGP’s
Eagle Ford acquisition, partially offset by a $4.1 million decrease attributable to AGP’s Marble Falls operations and a $0.2 million decrease attributable to AGP’s Mississippi Lime operations.
The $12.4 million decrease in our production costs for the year ended December 31, 2015 as compared to the prior year period primarily consisted of a $16.1 million decrease attributable to ARP’s Barnett Shale/Marble Falls assets, a $7.9 million decrease attributable to ARP’s coal-bed methane assets, a $7.5 million decrease attributable to ARP’s Appalachia operations and a $1.1 million decrease attributable to ARP’s Mississippi Lime/Hunton assets, partially offset by a $13.1 million increase attributable to ARP’s Rangely assets acquired during the year ended December 31, 2014, a $6.4 million increase attributable to ARP’s Eagle Ford assets acquired during the year ended December 31, 2014 and a $0.6 million decrease in the credit received against lease operating expenses pertaining to the subordination of ARP’s revenue within its Drilling Partnerships. The increase in AGP’s gas and oil production expenses for the year ended December 31, 2015 as compared to the prior year period consisted of $1.2 million attributable to AGP’s Eagle Ford assets, partially offset by a decrease of $1.1 million attributable to AGP’s Marble Falls assets. Total production costs per Mcfe decreased to $1.75 per Mcfe for the year ended December 31, 2015 from $1.81 per Mcfe for the comparable prior year period primarily as a result of continued efforts to reduce operating costs in each of our areas of production.
ARP’s Partnership Management
The following table presents the amounts of revenues and the related costs associated with these revenues during the periods indicated (dollars in thousands). We deconsolidated ARP for financial reporting purposes as of the date of the Chapter 11 Filings and therefore our 2016 combined consolidated financial statements will not be comparable to our 2015 and 2014 combined financial statements.
Well Construction and Completion. For the year ended December 31, 2016, our well construction and completion revenues and expenses consisted solely of ARP’s activities. We deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented. The number of wells ARP drills varied within ARP’s partnership management segment depending on the amount of capital it raised through its Drilling Partnerships, the cost of each well, the depth or type of each well, the estimated recoverable reserves attributable to each well and accessibility to the well site. Well construction and completion revenues and costs and expenses incurred represented the billings and costs associated with the completion of wells for Drilling Partnerships ARP sponsored. As ARP’s drilling contracts with the Drilling Partnerships were on a “cost-plus” basis, an increase or decrease in its average cost per well also resulted in a proportionate increase or decrease in its average revenue per well, which directly affected the number of wells ARP drilled.
ARP’s decrease in well construction and completion gross profit margin for the year ended December 31, 2016 as compared to the year ended December 31, 2015 consisted of decreases in the number of ARP’s Drilling Partnership wells for which completion activities were being performed related to timing and the economics of such activities during the challenging commodity price environment along with a downward revision to ARP’s estimated total costs to complete wells, which resulted in an unfavorable adjustment to ARP’s gross profit margin recognized on ARP’s “cost-plus” basis for the wells in progress.
Administration and Oversight. For the year ended December 31, 2016, our administration and oversight revenues and expenses consisted solely of ARP’s activities. We deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented. Administration and oversight fee revenues represented supervision and administrative fees earned for the drilling and subsequent ongoing management of wells for ARP’s Drilling Partnerships. Typically, ARP received a lower administration and oversight fee related to shallow, vertical wells it drilled within the Drilling Partnerships, such as those in the Marble Falls play, as compared to deep, horizontal wells, such as those drilled in the Marcellus Shale and the Utica Shales. There were no exploratory wells
drilled during the years ended December 31, 2016, 2015 and 2014. The decrease in administration and oversight fee revenues for the year ended December 31, 2016 as compared to the year ended December 31, 2015 was due to the decrease in the number of wells spud within the current year period compared with the prior year period. The decrease in administration and oversight fee revenues for the year ended December 31, 2015 as compared to the prior year period was primarily due to a decrease in the number of wells spud as compared with the prior year period, particularly within the Marble Falls and the Mississippi Lime plays.
Well Services. For the year ended December 31, 2016, our well services revenues and expenses consisted solely of ARP’s activities. We deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented. Well services revenue and expenses represented the monthly operating fees ARP charged and the work ARP’s service company performed, including work performed for ARP’s Drilling Partnership wells during the drilling and completing phase as well as ongoing maintenance of these wells and other wells for which ARP served as operator. The decrease in well services revenue for the year ended December 31, 2016 as compared to the prior year period was primarily related to lower fee revenue associated with ARP’s salt water gathering and disposal systems within the Mississippi Lime and Marble Falls operating areas, which are utilized by ARP’s Drilling Partnership wells, and an increased number of wells having been shut in, which results in a reduction of the monthly operating fees which ARP charges the Drilling Partnerships and due to certain Drilling Partnerships consolidated in the current year. The decrease in well services expense for the year ended December 31, 2016 as compared to the prior year period is primarily related to lower labor costs. The decrease in well services revenue for the year ended December 31, 2015 as compared to the prior year period was primarily related to ARP’s continued efforts to increase production through intermittent operation of certain legacy wells which resulted in a reduction of the monthly operating fees which ARP charged, partially offset by the increased utilization of ARP’s salt water gathering and disposal systems within the Mississippi Lime and Marble Falls plays by ARP’s Drilling Partnership wells. The decrease in well services expense for the year ended December 31, 2015 as compared to the prior year period was primarily related to lower labor and other employee costs.
Gathering and Processing. For the year ended December 31, 2016, our gathering and processing margin consisted solely of ARP’s activities. We deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented. Gathering and processing revenues and expenses included gathering fees ARP charged to its Drilling Partnership wells and the related expenses and gross margin for ARP’s processing plants in the New Albany Shale and the Chattanooga Shale. Generally, ARP charged a gathering fee to its Drilling Partnership wells equivalent to the fees it remitted. In Appalachia, a majority of ARP’s Drilling Partnership wells are subject to a gathering agreement, whereby ARP remitted a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charged its Drilling Partnership wells a 13% gathering fee. As a result, some of its gathering expenses, specifically those in the Appalachian Basin, would generally exceed the revenues collected from the Drilling Partnerships by approximately 3%. The favorable movement in net gathering and processing expense for the year ended December 31, 2016 as compared to the prior year period was principally due to higher oil prices in Appalachia and lower gathering fees, particularly from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which were utilizing ARP’s gathering pipeline, as compared to the prior year. The unfavorable movement in our net gathering and processing expense for the year ended December 31, 2015 as compared to the prior year period was principally due to lower gathering fees from ARP’s Marcellus Shale Drilling Partnership wells in Northeastern Pennsylvania, which were utilizing ARP’s gathering pipeline, as compared to the prior year.
Other Revenues and Expenses
Gain (Loss) on Mark-to-Market Derivatives. Since January 1, 2015 ARP and AGP recognize changes in the fair value of their derivatives immediately within gain (loss) on mark-to-market derivatives on our combined consolidated statements of operations. The recognized losses and gains during the years ended December 31, 2016 and 2015, respectively, are related to the changes in oil prices during the years ended December 31, 2016 and 2015 as compared to the prior year periods. In addition, we deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented.
General and Administrative. Our $25.3 million decrease in general and administrative expenses for the year ended December 31, 2016 is primarily due to a $17.1 million decrease in non-recurring transaction costs attributable to our spin-off from Atlas Energy during the prior year period, a $6.2 million decrease in salaries, wages and benefits, a $1.3 million decrease in other corporate activities and a $0.7 million increase in stock compensation expense. ARP’s $25.0 million decrease in general and administrative expenses for the year ended December 31, 2016 as compared to the prior year period is due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented. AGP’s decrease in general and administrative expenses for the year ended December 31, 2016 as compared to the prior year period was due to a $2.8 million decrease in salaries, wages and other corporate activity costs allocated by us and ARP/Titan to AGP in connection with the completion of AGP’s private placement offering in June 2015.
Our $24.5 million increase in general and administrative expenses for the year ended December 31, 2015 as compared to the prior year period is primarily due to a $17.7 million increase in non-recurring transaction costs due to our spin-off from Atlas Energy, a $5.7 million increase in stock compensation expense, and a $1.1 million increase in other corporate activities. AGP’s $1.0 million increase in general and administrative expenses for the year ended December 31, 2015 as compared to the prior year period is related to an increase in salaries, wages, and other corporate activities due to the growth of its business. ARP’s $6.4 million decrease in general and administrative expenses for the year ended December 31, 2015 as compared to the prior year period was primarily due to an $8.8 million decrease in the year ended December 31, 2015 in non-recurring transaction costs related to the acquisitions of assets and a $3.1 million decrease in non-cash stock compensation, partially offset by a $5.3 million increase in syndication expenses.
Depreciation, Depletion and Amortization. ARP’s $90.5 million decrease in depreciation, depletion and amortization for the year ended December 31, 2016 as compared to the prior year period is due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented. AGP’s increase in depreciation, depletion and amortization for the year ended December 31, 2016 as compared to the prior year period was primarily due to a $5.9 million increase in AGP’s depletion expense.
The $75.2 million decrease in depreciation, depletion and amortization for the year ended December 31, 2015 compared with the prior year period was primarily due to a $77.7 million decrease in AGP’s and ARP’s depletion expense. The following table presents our subsidiaries’ depletion expense per Mcfe for AGP’s and ARP’s operations for the respective periods (in thousands, except per Mcfe data):
ARP’s decrease in depletion expense and depletion expense per Mcfe for the year ended December 31, 2016 as compared to the prior year period is due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented. AGP’s increases in depletion expense, depletion expenses as a percentage of gas and oil revenues and depletion expenses per Mcfe for the year ended December 31, 2016 as compared to the prior year period were primarily due to an increase in AGP’s depletion expense associated with the expansion of AGP’s Eagle Ford operations, partially offset by a decrease in oil volumes from AGP’s Marble Falls operations.
ARP’s decreases in depletion expense, depletion expense as a percentage of gas and oil production revenues, and depletion expense per Mcfe for the year ended December 31, 2015 when compared with the prior year period are the result of the asset impairments recognized at September 30, 2015 and December 31, 2014. AGP’s increases in depletion expense, depletion expenses as a percentage of gas and oil revenues and depletion expenses per Mcfe for the year ended December 31, 2015 as compared to the prior year period were primarily due to an increase in AGP’s depletion expense associated with the expansion of AGP’s Eagle Ford operations, partially offset by a decrease in oil volumes from AGP’s Marble Falls operations.
Asset Impairment. ARP’s $966.6 million of asset impairment for the year ended December 31, 2015 related to oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income. ARP’s $573.8 million of asset impairment for the year ended December 31, 2014 primarily consisted of $555.7 million of oil and gas impairment within ARP’s Appalachian and mid-continent operations, which was net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. In addition, $18.1 million of ARP’s asset impairment in 2014 was due to goodwill impairment. ARP’s asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. For the year ended December 31, 2016, AGP recognized $25.4 million and $16.5 million of asset impairment related to its proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, AGP recognized $7.3 million of asset impairment related to its proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. For the year ended December 31, 2014, AGP recognized $6.9 million of asset impairment related to its proved oil and gas properties in the Marble Falls operating area, which was impaired due to lower forecasted commodity prices.
Interest Expense. The decrease in our interest expense for the year ended December 31, 2016 as compared to the prior year period consisted of $5.7 million of accelerated amortization of the deferred financing costs associated with the portion of Atlas Energy’s Term Loan Facility allocated to us in February 2015, a $6.1 million decrease in interest on outstanding term loans primarily resulting from lower outstanding borrowings and the refinancing of the Deutsche Bank Term Loan in 2015 to the Riverstone Term Loan Facilities in March 2016 that among other things decreased the interest rate by approximately 6% per annum, $3.2 million of discount amortization for Atlas Energy’s Term Loan Facility allocated to us in the prior year period, $2.9 million of accelerated amortization of the discount of Atlas Energy’s Term Loan Facility allocated to us resulting from repayments made to reduce the outstanding balance during the prior year period, $2.3 million of discount amortization for our Term Loan Facilities with Deutsche Bank during the year ended December 31, 2015, $0.5 million accelerated amortization associated with a paydown of the Riverstone Term Loan and $0.3 million for amortization of our deferred financing costs in the prior year period, partially offset by the $11.7 million of paid-in-kind interest on our current Riverstone Credit Agreements and $0.6 million of amortization of warrants that were issued in connection with the Second Lien Credit Agreement. ARP’s $33.3 million decrease interest expense for the year ended December 31, 2016 as compared to the prior year period is due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented.
Our $12.3 million increase in our interest expense for the year ended December 31, 2015 as compared to the prior period was primarily related to $5.5 million of discount amortization for our Term Loan Facilities, $5.2 million of accelerated amortization of the deferred financing costs associated with the portion of Atlas Energy’s Term Loan Facility allocated to us, $2.9 million of accelerated amortization of the discount of our Term Loan Facilities resulting from repayments made to reduce the outstanding balance prior to paying off the loan through refinancing and $0.5 million of accelerated amortization of the deferred financing costs associated with the retirement of a portion of First Lien Term Loan Facility, partially offset by a $1.6 million decrease in interest expense related to outstanding borrowings and a $0.1 million decrease in amortization of deferred financing costs. The $40.0 million increase in ARP’s interest expense for the year ended December 31, 2015 compared to the prior year period consisted of a $23.1 million increase associated with ARP’s Predecessor’s Old Term Loan Facility, an $8.7 million increase associated with interest expense on ARP’s Senior Notes, $5.6 million in accelerated amortization charges related to ARP’s reduced credit facility borrowing base and a $3.0 million increase associated with amortization of ARP’s deferred financing costs, partially offset by a $0.4 million decrease associated with outstanding borrowings under ARP’s revolving credit facility. The increase associated with ARP’s Senior Notes is primarily due to the issuance of an additional $100.0 million of ARP’s 7.75% Senior Notes in June 2014 and an additional $75.0 million of ARP’s 9.25% Senior Notes in October 2014. The increase in interest expense for ARP’s Old Term Loan Facility related to ARP’s entry into ARP’s Old Term Loan Facility in February 2015.
Gain (Loss) on Early Extinguishment of Debt. The gain on early extinguishment of debt for the year ended December 31, 2016 represents a $26.5 million gain related to the repurchase of a portion of ARP’s 7.75% and 9.25% Senior Notes, partially offset by $3.7 million of accelerated amortization of deferred financing costs and $2.4 million of prepayment penalties related to the restructuring of our Term Loan Facility with Riverstone. Of ARP’s $26.5 million gain, $27.4 million related to the gain from the redemption of the principal values and accrued interest, partially offset by $0.9 million related to the accelerated amortization of the related deferred financing costs. Loss on early extinguishment of debt of $4.7 million for the year ended December 31, 2015 represents $4.4 million of accelerated amortization of the discount and $0.3 million of accelerated deferred financing costs related to the early retirement of our Term Loan Facilities with Deutsche Bank.
Reorganization Items, Net. The $21.6 million reorganization items, net for the year ended December 31, 2016 represent incremental costs incurred as a result of ARP’s Chapter 11 Filings in our combined consolidated statement of operations.
Gain on deconsolidation of Atlas Resource Partners, L.P. As a result of deconsolidating ARP and recording our equity method investment in ARP at a fair value of zero on the date of the Chapter 11 Filings, we recognized a $47.0 million non-cash gain, which is recorded in gain on deconsolidation of ARP on our combined consolidated statements of operations for the year ended December 31, 2016.
Other loss. AGP’s $5.3 million loss for the year ended December 31, 2016 was due to AGP’s write-off of issuer costs in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. ARP’s $6.2 million other loss for the year ended December 31, 2016 was due to a non-cash loss, net of consolidation and transfer adjustments, of certain Drilling Partnerships’ consolidation and transfer of oil and gas properties and asset retirement obligations to ARP.
(Income) Loss Attributable to Non-Controlling Interests. The movement in loss attributable to non-controlling interests for the year ended December 31, 2016 and the prior year comparable period was primarily due to the deconsolidation of ARP as of July 27, 2016, which affects the comparability of the periods presented.
The movement in loss attributable to non-controlling interests between the year ended December 31, 2015, and the prior year period was primarily due to an increase in ARP’s net loss between periods primarily related to the $392.9 million increase in impairment primarily for ARP’s oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas during the year ended December 31, 2015 and the decrease in our ownership interests in ARP during the year ended December 31, 2015, partially offset by the $264.4 million increase in the gain on mark-to-market derivatives during the year ended December 31, 2015.
Liquidity, Capital Resources and Ability to Continue as a Going Concern
Our primary sources of liquidity are cash distributions received with respect to our ownership interests in AGP, Lightfoot, and Titan and AGP’s annual management fee. However, neither Titan nor AGP is currently paying distributions. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures. In addition, the obligations under our first lien credit agreement mature in September 2017. Accordingly, our sources of liquidity are currently not sufficient to satisfy our obligations under our credit agreements.
The significant risks and uncertainties related to our primary sources of liquidity raise substantial doubt about our ability to continue as a going concern. If we are unable to remain in compliance with the covenants under our credit agreements, absent relief from our lenders, we maybe be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit agreements could elect to declare all amounts outstanding immediately due and payable and could terminate all commitments to extend further credit. If an event of default occurs, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. In addition to the $38 million of indebtedness due on September 30, 2017, we classified the remaining $44.6 million of outstanding indebtedness under our credit agreements as a current liability, based on the uncertainty regarding future covenant compliance. In total, we have $81.1 million of outstanding indebtedness under our credit agreements, which is net of $1.2 million of debt discounts and $0.2 million of deferred financing costs, as current portion of long term debt, net within our combined consolidated balance sheet as of December 31, 2016.
We continually monitor our capital markets and capital structures and may make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets. Please see “Risk Factors-Tax Risks to Unitholders- We expect to engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.”
Our combined consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our combined consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.
Atlas Growth Partners - Liquidity, Capital Resources, and Ability to Continue as a Going Concern
AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its private placement offering completed in 2015. AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position.
AGP was not a party to the Restructuring Support Agreement, and ARP’s Restructuring did not materially impact AGP.
On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. In addition, AGP’s board of directors suspended its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets. Accordingly, these decisions raise substantial doubt about AGP’s ability to continue as a going concern. Management determined that substantial doubt is alleviated through management’s plans to reduce general and administrative expenses, the majority of which represent allocations from ATLS.
Cash Flows
Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015
We deconsolidated ARP for financial reporting purposes as of July 27, 2016 (the date of ARP’s Chapter 11 Filings) and therefore our 2016 cash flows will not be comparable to our 2015 cash flows.
The change in cash flows provided by operating activities when compared with the comparable prior year period was primarily due to:
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an increase of $243.5 million from the sale of substantially all of ARP’s commodity hedge positions on July 25, 2016 and July 26, 2016 pursuant to ARP’s Restructuring Support Agreement; and
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a decrease of $96.3 million in distributions paid to non-controlling interests; partially offset by
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a decrease of $65.1 million net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production and ARP’s partnership management revenues, and collections net of payments for our royalties, ARP’s well construction and completion activities, ARP’s Drilling Partnership administrative and oversight and well services activities, lease operating expenses, ARP’s gathering, processing and transportation expenses, severance taxes, general and administrative expenses, and interest payments;
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a decrease of cash settlement receipts of $80.1 million on commodity derivative contracts;
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an increase in ARP’s reorganization costs of $21.6 million representing incremental costs incurred as a result of ARP’s Chapter 11 Filings; and
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a $1.0 million decrease in net cash distributions from our equity investment in Lightfoot.
The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to:
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a decrease of $128.6 million in capital expenditures resulting from ARP’s $106.0 million and AGP’s $22.6 million in lower capital expenditures related to our drilling activities; and
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a decrease of $120.3 million in net cash paid for acquisitions primarily due to ARP’s $77.8 million and AGP’s $42.5 million in deferred purchase price payments and working capital settlements for ARP’s and AGP’s Eagle Ford acquisition in 2015.
The change in cash flows (used in) provided by financing activities when compared with the comparable prior year period was primarily due to:
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a decrease of $242.5 million in net borrowings under ARP’s second lien term loan facility due to the second lien term loan proceeds of $242.5 million, net of $7.5 million in discount, issued early 2015;
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a decrease of $200.4 million in net proceeds primarily from the issuance of $107.0 million of AGP’s common limited partner units under its private placement offering during the year ended December 31, 2015 and the $93.4 million issuance of ARP’s common limited partner units in the year ended December 31, 2015 under ARP’s equity distribution program;
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a $77.0 million decrease in net borrowings on our credit agreements with Riverstone;
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an increase of $52.0 million in net repayments on ARP’s revolving credit facilities;
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a decrease of $40.0 million related to the issuance of our Series A preferred units during the year ended December 31, 2015;
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a decrease of $6.8 million in net proceeds from the issuance of ARP’s preferred limited partner units in the year ended December 31, 2015, primarily related to less funds required for acquisitions during 2015; and
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a decrease of $5.5 million related to ARP’s senior note repurchases in the first quarter of 2016; partially offset by
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a $127.8 million decrease in net repayments on our Term Loan Facilities with Deutsche Bank, which was replaced with our First Lien Term Loan Facility with Riverstone in August 2015;
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a decrease of $32.3 million in net repayments on Atlas Energy, LP’s Term Loan Facility during the year ended December 31, 2016, resulting from our $148.1 million payment to Atlas Energy, LP in connection with Atlas Energy, LP’s merger with Targa to repay the then existing Term Loan Facility in full in the first quarter of 2015, which was partially funded by the $115.8 million interim and term loan A facilities, net of $12.5 million of discount, entered into in the first quarter of 2015;
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a decrease of $29.6 million in deferred financing costs and discounts on the second lien term loan, primarily related to the issuance of ARP’s $250.0 million second lien term loan in the first quarter of 2015;
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a decrease of $19.8 million of distributions to Atlas Energy related to the Arkoma transaction adjustment in the first quarter of 2015; and
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a decrease of $1.7 million in distributions paid to preferred unitholders primarily due to the suspension of distributions for the Series A preferred units in the first quarter of 2015.
Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014
The change in cash flows provided by operating activities when compared with the comparable prior year period was primarily due to:
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A decrease of $269.4 million in net cash provided by operating activities for cash receipts and disbursements attributable to our normal monthly operating cycle for gas and oil production and ARP’s partnership management revenues, and collections net of payments for our royalties, ARP’s well construction and completion activities, ARP’s Drilling Partnership administrative and oversight and well services activities, our lease operating expenses, ARP’s gathering, processing and transportation expenses, our severance taxes, our general and administrative expenses, and our interest payments; partially offset by
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a decrease of $27.4 million in distributions paid to non-controlling interests;
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an increase of cash settlement receipts of $171.8 million primarily on ARP’s commodity derivative contracts; and
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a $1.2 million increase in net cash distributions from our equity investment in Lightfoot.
The change in cash flows used in investing activities when compared with the comparable prior year period was primarily due to:
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a decrease of $621.2 million in net cash paid for acquisitions primarily due to the $608.9 million decrease in ARP’s Eagle Ford acquisition in 2014, partially offset by the adjustments in working capital settlements for ARP’s Eagle Ford acquisition and the Arkoma acquisition in 2015 and a decrease of $12.3 million in net cash paid for acquisitions related to the funding of AGP’s Eagle Ford asset acquisition in 2015; and
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a decrease of $69.3 million in capital expenditures due to $85.7 million in lower capital expenditures related to ARP’s drilling activities, partially offset by $16.4 million in higher AGP capital expenditures.
The change in cash flows provided by financing activities when compared with the comparable prior year period was primarily due to:
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an increase of $381.2 million in net repayments on ARP’s revolving credit facility;
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a $305.8 million decrease in net proceeds from the issuance of our subsidiaries’ common limited partner units in the year ended December 31, 2015, primarily due to a $332.6 million decrease in net proceeds from the issuance of common limited partner units in the year ended December 31, 2015 under ARP’s equity distribution programs, partially offset by an increase of $26.8 million in net proceeds from issuance of AGP common limited partner units and warrants due to AGP’s Private Placement Offering funds raised in 2015;
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a decrease of $170.6 million related to ARP’s senior note issuances during the year ended December 31, 2014;
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a $126.3 million increase in net repayments on our Term Loan Facilities with Deutsche Bank;
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a decrease of $70.5 million in net proceeds from the issuance of ARP’s preferred limited partner units in the year ended December 31, 2015, primarily related to less funds required for acquisitions during 2015;
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an increase of $32.3 million in net repayments on Atlas Energy, LP’s Term Loan Facility during the year ended December 31, 2015, resulting from repaying the Term Loan Facility in full in connection with Atlas Energy, LP’s merger with Targa;
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an increase of $22.8 million in our deferred financing costs, distribution equivalent rights and other, primarily due to an $18.2 million increase in ARP’s deferred financing costs, distribution equivalent rights and other, primarily related to the issuance of ARP’s $250.0 million second lien term loan during the year ended December 31, 2015 and our $4.6 million increase; and
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a $2.7 million increase in net distributions to our and ARP’s preferred unitholders; partially offset by
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an increase of $242.5 million in net borrowings under ARP’s second lien term loan facility due to the second lien term loan proceeds of $242.5 million, net of $7.5 million in discount, issued in the first half of 2015;
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a $72.7 million increase in net borrowings on our Term Loan Facilities with Riverstone;
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a $66.0 million decrease in distributions to owner; and
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a $40.0 million increase in our proceeds from the issuance of our Series A Preferred Units.
Capital Requirements
At December 31, 2016, our capital expenditures primarily relate to our well drilling and leasehold acquisition costs. The following table summarizes consolidated maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):
Atlas Resource Partners. During the year ended December 31, 2016, ARP’s $21.2 million of total capital expenditures consisted primarily of $11.2 million for wells drilled exclusively for ARP’s own account compared with $51.2 million for the comparable prior year period, $0.6 million of investments in its Drilling Partnerships compared with $32.4 million for the prior year comparable period, $2.1 million of leasehold acquisition costs compared with $11.9 million for the prior year comparable period and $7.3 million of corporate and other costs compared with $31.6 million for the prior year comparable period. We deconsolidated ARP as of July 27, 2016 which affects the comparability of the periods presented.
During the year ended December 31, 2015, ARP’s $127.1 million of total capital expenditures consisted primarily of $51.2 million for wells drilled exclusively for ARP’s own account compared with $82.2 million for the comparable prior year period, $32.4 million of investments in its Drilling Partnerships compared with $72.4 million for the prior year comparable period, $11.9 million of leasehold acquisition costs compared with $25.5 million for the prior year comparable period and $31.6 million of corporate and other costs compared with $32.6 million for the prior year comparable period.
Atlas Growth Partners. During the year ended December 31, 2016, AGP’s $6.6 million of total capital expenditures consisted primarily of $6.2 million for wells drilled compared with $29.2 million for the comparable prior year period, $0.1 million of leasehold acquisition costs compared with no costs for the prior year comparable period and $0.3 million of gas and gathering costs compared with no costs for the prior year comparable period.
During the year ended December 31, 2015, AGP’s $29.2 million of total capital expenditures consisted primarily of its wells drilled and leasehold acquisition costs.
During the year ended December 31, 2014, AGP’s $12.9 million of total capital expenditures consisted primarily of the wells drilled and leasehold acquisition costs.
As of December 31, 2016, our subsidiaries did not have any commitments for drilling and completion and capital expenditures, excluding acquisitions.
Off-Balance Sheet Arrangements
As of December 31, 2016, we did not have any off-balance sheet commitment arrangements for our drilling and completion and capital expenditures.
CREDIT FACILITIES
As of December 31, 2016, we had not guaranteed any of our subsidiaries’ obligations or debt instruments.
Credit Agreements
First Lien Credit Agreement. On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).
The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.25 million of the outstanding principal, which was classified as current portion of long-term debt on our combined consolidated balance sheet at December 31, 2015, and $0.5 million of interest. As a result of these transactions, we recognized $6.1 million as a loss on early extinguishment of debt, consisting of the $2.4 million prepayment penalty and $3.7 million of accelerated amortization of deferring financing costs, on our combined consolidated statement of operations for the year ended December 31, 2016. The Third Amendment amended the First Lien Credit Agreement to, among other things:
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provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);
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shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;
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modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;
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allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;
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provide that the First Lien Credit Agreement may be prepaid without premium;
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replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in ARP’s credit agreement, beginning with the quarter ending June 30, 2016;
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prohibit the payment of cash distributions on our common and preferred units;
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require the receipt of quarterly distributions from Atlas Growth Partners, GP, LLC and Lightfoot; and
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add a cross-default provision for defaults by ARP.
On October 6, 2016, we entered into a fourth amendment to the First Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.
Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The First Lien
Credit Agreement combined with Second Lien Credit Agreement is presented in the table above net of an unamortized discount of $1.6 million as of December 31, 2016, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement.
The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.
Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.
The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.
The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.
As a result of the cross-default, on July 11, 2016, we entered into waiver agreements (the “Waivers”) with Riverstone and the Lenders in connection with the First Lien Credit Agreement and the Second Lien Credit Agreement. Pursuant to the Waivers, Riverstone and the Lenders agreed to waive under the First Lien Credit Agreement and the Second Lien Credit Agreement:
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the cross-defaults relating to ARP’s default, for so long as the forbearing parties continue to forbear from exercising their rights and remedies; and
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the potential default relating to ARP’s ongoing negotiations with its lenders and noteholders to the extent any resulting restructuring is completed prior to October 31, 2016
On October 6, 2016, we entered into a first amendment to the Second Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.
In connection with the First Lien Credit Agreement and Second Lien Credit Agreement, the lenders thereunder continued their syndicated participation in the underlying loans consistent with the original term loan facilities and therefore certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication.
ATLAS GROWTH PARTNERS SECURED CREDIT FACILITY
On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of December 31, 2016, the lenders under the credit facility have no commitment to lend to AGP under the credit facility and AGP has a zero dollar borrowing base, but AGP and its subsidiaries have the ability to enter into derivative contracts to manage their exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on AGP’s oil and gas properties and first priority security interests in substantially all of its assets. The credit facility may be amended in the future if AGP and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit AGP and its subsidiaries ability to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. AGP was in compliance with these covenants as of December 31, 2016. In addition, AGP’s credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following tables summarize our and our subsidiaries contractual obligations at December 31, 2016 (in thousands):
(1)
Interest expense on total debt includes our estimated cash and paid-in-kind interest for the next nine months on our First Lien Credit Agreement and twelve months on our Second Lien Credit Agreement as both of our debts are classified as current liabilities. Actual interest expense may be different than our estimates depending upon the timing and outcome of transactions related to our debts.
ISSUANCE OF UNITS
We recognize gains or losses on AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on our combined consolidated balance sheets rather than as income or loss on our combined consolidated statements of operations. These gains or losses represent our portion of the excess or the shortage of the net offering price per unit of AGP’s common units as compared to the book carrying amount per unit.
In connection with the Second Lien Credit Agreement, on April 27, 2016, we issued to the Lenders, warrants (the “Warrants”) to purchase up to 4,668,044 common units representing limited partner interests at an exercise price of $0.20 per unit. The Warrants expire on March 30, 2026 and are subject to customary anti-dilution provisions. On April 27, 2016, we entered into a registration rights agreement pursuant to which we agreed to register the offer and resale of our common units underlying the Warrants as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement. The Warrants include a cashless exercise provision entitling the Lenders to surrender a portion of the underlying common units that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant. As a result of issuance of the Warrants, we recognized a $1.9 million debt discount on the Second Lien Credit Agreement, which will be amortized over the term of the debt, and a corresponding $1.9 million increase to unitholders’ equity - warrants on our combined consolidated balance sheet at the time of the transaction.
On February 27, 2015 we issued and sold an aggregate of 1.6 million of our newly created Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of our management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the of the private placement, respectively, or (ii) the monthly equivalent of any cash distribution declared by us to holders of our common units, as well as Series A Preferred Units at a rate equal to 2% of the liquidation preference per annum. All or a portion of the Series A Preferred Units will be convertible into our units at the option of the holder at any time following the later of (i) the one-year anniversary of the distribution and (ii) receipt of unitholder approval. The conversion price will be equal to the greater of (i) $8.00 per common unit; and (ii) the lower of (a) 110.0% of the volume weighted average price for our common units over the 30 trading days following the distribution date; and (b) $16.00 per common unit. We sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million payment by us to Atlas Energy related to the repayment of Atlas Energy’s term loan. The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.
On August 26, 2015, at a special meeting of our unitholders, the unitholders approved changes to the terms of the Series A Preferred Units to provide that each Series A Preferred Unit will be convertible into common units at the option of the holder.
On January 7, 2016, we were notified by the NYSE that we were not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had been less than $1.00 for 30 consecutive trading days. We also were notified by the NYSE on December 23, 2015, that we were not in compliance with the NYSE’s continued listing criteria under Section 802.01B of the NYSE Listed Company Manual because our average market capitalization had been less than $50 million for 30 consecutive trading days and our stockholders’ equity had been less than $50 million. On March 18, 2016, we were notified by the NYSE that it determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of
the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of our common units at the close of trading on March 18, 2016. Our common units began trading on the OTCQX on Monday, March 21, 2016 under the ticker symbol: ATLS.
On February 20, 2017, our Board of Directors authorized the deferral until March 1, 2018 of the vesting of all phantom units granted to officers and employees under the 2015 LTIP that had previously been scheduled to vest during 2017. As consideration for the deferral, we made a deferred vesting payment to all employees (including the officers) equal to approximately 25% of the value of affected phantom units.
On May 12, 2016, due to the income tax ramifications of potential options we were considering, the Board of Directors delayed the vesting of approximately 911,900 units granted, under our long-term incentive plan, to employees, directors and officers, until March 2017. The phantom units were set to vest between June 8, 2016 and September 1, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on the consolidated statement of operations for the year ended December 31, 2016 or our remaining unrecognized compensation expense related to such awards.
Atlas Growth Partners
On April 5, 2016, we announced that AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the SEC.
Under the terms of AGP’s initial offering, AGP offered in a private placement $500.0 million of its common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that it had not sold $500.0 million of common units at any extension date. AGP exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which AGP gives the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of AGP’s assets.
Through the completion of AGP’s private placement offering on June 30, 2015, AGP issued $233.0 million, or 23,300,410 of its common limited partner units, in exchange for proceeds to AGP, net of dealer manager fees and commissions and expenses, of $203.4 million. We purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase AGP’s common units at an exercise price of $10.00 per unit.
During the year ended December 31, 2015, AGP sold an aggregate of 12,623,500 of its common limited partner units at a gross offering price of $10.00 per unit. Of such amount, we purchased $2.7 million, or 300,000 common units, during the year ended December 31, 2015. In connection with the issuance of its common limited partner units, unitholders received 1,262,350 warrants to purchase its common limited partner units at an exercise price of $10.00 per unit.
During the year ended December 31, 2014, AGP sold an aggregate of 9,581,900 of its common limited partner units at a gross offering price of $10.00 per unit, resulting in proceeds of $81.6 million to AGP, net of dealer manager fees and commissions and expenses of $14.0 million. We did not purchase common units during the year ended December 31, 2014. In connection with the issuance of common limited partner units in 2014, unitholders received 958,190 warrants to purchase AGP’s common limited partner units at an exercise price of $10.00 per unit.
As a result of AGP’s management’s decision to temporarily suspend its current primary offering efforts, AGP reclassified $5.3 million of offering costs to other loss on our consolidated statements of operations. These offering costs were previously capitalized within noncontrolling interest on our consolidated balance sheet as an offset to any proceeds raised in its current primary offering and include $1.5 million that were previously capitalized within noncontrolling interest on our consolidated balance sheet as of December 31, 2015.
In connection with the issuance of ARP’s unit offerings during the year ended December 31, 2016, we recorded gains of $0.2 million within unitholders’ equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheet and combined consolidated statement of unitholders’ equity. In connection with the issuance of ARP’s and AGP’s unit offerings for the year ended December 31, 2015, we recorded gains of $4.3 million within equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheets and combined consolidated statement of unitholders’ equity.
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion and impairment of gas and oil properties, and fair value of derivative instruments. We summarize our significant accounting policies within our consolidated financial statements included in “Item 8: Financial Statements and Supplementary Data - Notes 2, 3 and 6” included in this report. The critical accounting policies and estimates we have identified are discussed below.
Gas and Oil Properties - Depletion and Impairment
We follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed.
Our depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. Capitalized costs of developed producing properties in each field are aggregated to include our costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by us for our interests, properties purchased and working interests with other outside operators.
We review our gas and oil properties for impairment whenever events or changes in circumstances indicate that the net carrying amount of an asset may not be recoverable. Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions. Additional factors impacting the economic viability of long-lived assets are discussed under “Item 1A: Risk Factors” in this report. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
Our unproved properties are assessed individually based on several factors including if a dry hole has been drilled in the area, other wells drilled in the area and operating results, remaining months in the lease’s primary term, and management’s future plans to drill and develop the area. As exploration and development work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depletion. If exploration activities are unsuccessful, the capitalized costs of the properties related to the unsuccessful work is charged to exploration expense. The timing of impairment of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results.
The review of our proved oil and gas properties is done on a field-by-field basis by determining if the net carrying value of proved properties is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on management’s plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. We estimate prices based upon current contracts in place, adjusted for basis differentials and market related information including published future prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected undiscounted future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of
economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Our reserve estimates are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. Reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. We cannot predict what reserve revisions may be required in future periods. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in “General Trends and Outlook” within this section, recent increases in natural gas and oil drilling have driven an increase in the supply of natural gas and oil and put a downward pressure on domestic prices. Further declines in commodity prices may result in additional impairment charges in future periods.
For the year ended December 31, 2015, ARP recognized $966.6 million of asset impairment related to oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income. ARP’s $573.8 million of asset impairment for the year ended December 31, 2014 primarily consisted of $555.7 million of oil and gas impairment within ARP’s Appalachian and mid-continent operations, which was net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income. In addition, $18.1 million of ARP’s asset impairment in 2014 was due to goodwill impairment. ARP’s asset impairments for the year ended December 31, 2014 principally resulted from the decline in forward commodity prices during the fourth quarter of 2014. For the year ended December 31, 2016, AGP recognized $25.4 million and $16.5 million of asset impairment related to its proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, AGP recognized $7.3 million of asset impairment related to its proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. For the year ended December 31, 2014, AGP recognized $6.9 million of asset impairment related to its proved oil and gas properties in the Marble Falls operating area, which was impaired due to lower forecasted commodity prices
Fair Value Measurements
We have established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1 - Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3 - Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
Derivatives. We use a market approach fair value methodology to value the assets and liabilities for our outstanding derivative contracts. Our commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.
Warrants. The fair value of the warrants associated with the issuance of AGP’s common limited partner units in 2015 was measured using a Black-Scholes pricing model which was based on Level 3 inputs including an exercise price of $10.00, discount rate of 0.5%, an expected term of 1.5 years, expected dividend yield of 7.0% and estimated volatility rate of 50%. The volatility rate used was consistent with that of ARP at the time the warrants were issued. The estimated fair value per warrant was $1.47, which includes a $0.37 liquidity adjustment.
The fair value of the warrants associated with the issuance of AGP’s common limited partner units in 2014 was measured using a Black-Scholes pricing model which is based on Level 3 inputs including an exercise price of $10.00, discount rate of 0.3%, an expected term of 1 year, expected dividend yield of 7.0% and estimated volatility rate of 45%. The volatility rate used is consistent with that of ARP at the time the warrants were issued. The estimated fair value per warrant was $1.20, which includes a $0.21 liquidity adjustment.
Asset Impairments. We estimate the fair value of our gas and oil properties in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances based on a discounted cash flow model, which considers the estimated remaining lives of the wells based on reserve estimates, our future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. See “Gas and Oil Properties - Depletion and Impairment” above for disclosure of impairments of our gas and oil properties. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.
Acquisitions. During the year ended December 31, 2014, we completed acquisitions of oil and gas properties and related assets. The fair value measurements of assets acquired and liabilities assumed were based on inputs that were not observable in the market and therefore represented Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under our methodology for recognizing an estimated liability for the plugging and abandonment of our gas and oil wells. These inputs required significant judgments and estimates by management at the time of the valuation. All purchase price allocations were finalized within one year from the acquisition date.
Reserve Estimates
Our estimates of proved natural gas, oil and natural gas liquids reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and natural gas liquids prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. We engaged independent third-party reserve engineers to prepare annual reports of our proved reserves (see “Item 2: Properties”).
Any significant variance in the assumptions utilized in the calculation of our reserve estimates could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas, oil and natural gas liquids reserves are inherently imprecise. Actual future production, natural gas, oil and natural gas liquids prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and natural gas liquids reserves may vary substantially from our estimates or estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas, oil and natural gas liquids prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of oil and gas properties. Adjustments to quarterly depletion rates, which are based upon a units of production method, are made concurrently with changes to reserve estimates. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.
ITEM 7A:
ITEM 7A:
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our and our subsidiaries’ potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and commodity prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we and our subsidiaries view and manage our ongoing market risk exposures. All of the market risk-sensitive instruments were entered into for purposes other than trading.
General
All of our and our subsidiaries’ assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.
We and our subsidiaries are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. Our subsidiaries manage these risks through regular operating and financing activities and periodic use of derivative financial instruments such as forward contracts and interest rate cap and swap agreements. The following analysis presents the effect on our results of operations, cash flows and financial position
as if the hypothetical changes in market risk factors occurred on December 31, 2016. Only the potential impact of hypothetical assumptions was analyzed. The analysis does not consider other possible effects that could impact our and our subsidiaries’ business.
We are subject to the risk of loss on our derivative instruments that would occur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize their overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords them netting or set off opportunities to mitigate exposure risk; and (v) when appropriate, requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. AGP’s liabilities related to derivatives as of December 31, 2016 represent financial instruments from two counterparties; both of which are a financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with AGP’s secured credit facility. Subject to the terms of AGP’s secured credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the secured credit facility.
Interest Rate Risk. As of December 31, 2016, we had $82.6 million of outstanding borrowings under our credit agreements. Holding all other variables constant, a hypothetical 100 basis-point or 1% change in variable interest rates would change our combined consolidated interest expense for the year ending December 31, 2017 by $0.8 million.
Commodity Price Risk. Our subsidiaries’ market risk exposures to commodities are due to the fluctuations in the commodity prices and the impact those price movements have on our subsidiaries’ financial results. To limit the exposure to changing commodity prices, AGP uses financial derivative instruments, including financial swap and option instruments, to hedge portions of future production. The swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under these swap agreements, AGP receives or pays a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. Option instruments are contractual agreements that grant the right, but not the obligation, to purchase or sell commodities at a fixed price for the relevant period.
Holding all other variables constant, including the effect of commodity derivatives, a 10% change in average commodity prices would result in a change to our consolidated operating income for the year ending December 31, 2017 of approximately $26,000, net of non-controlling interests.
Realized pricing of natural gas, oil, and natural gas liquids production is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas, oil and natural gas liquids production. Pricing for natural gas, oil and natural gas liquids production has been volatile and unpredictable for many years. To limit AGP’s exposure to changing natural gas, oil and natural gas liquids prices, AGP enters into natural gas and oil swap, put option and costless collar option contracts. At any point in time, such contracts may include regulated NYMEX futures and options contracts and non-regulated over-the-counter (“OTC”) futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. OTC contracts are generally financial contracts which are settled with financial payments or receipts and generally do not require delivery of physical hydrocarbons. Crude oil contracts are based on a West Texas Intermediate (“WTI”) index. Natural gas liquids fixed price swaps are priced based on a WTI crude oil index, while other natural gas liquids contracts are based on an OPIS Mt. Belvieu index.
As of December 31, 2016, AGP had the following commodity derivatives:
(1)
Volumes for crude oil are stated in barrels.
ITEM 8:
ITEM 8:
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index
Page
Report of Independent Registered Public Accounting Firm
Combined Consolidated Balance Sheets
Combined Consolidated Statements of Operations
Combined Consolidated Statements of Changes in Unitholders’/Owner’s Equity
Combined Consolidated Statements of Cash Flows
Notes to Combined Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Unitholders
Atlas Energy Group, LLC
We have audited the accompanying combined consolidated balance sheets of Atlas Energy Group, LLC (a Delaware limited liability company) and subsidiaries and affiliates as defined in Note 1 (the “Company”) as of December 31, 2016 and 2015, and the related combined consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Energy Group, LLC and subsidiaries and affiliates as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.
The accompanying combined consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the combined consolidated financial statements, the Company has a net working capital deficiency as its sources of liquidity are currently not sufficient to satisfy its obligations under its credit agreements. These conditions, along with other matters as set forth in Note 2, raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The combined consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
April 17, 2017
ATLAS ENERGY GROUP, LLC
COMBINED CONSOLIDATED BALANCE SHEETS
(in thousands)
See accompanying notes to combined consolidated financial statements.
ATLAS ENERGY GROUP, LLC
COMBINED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
See accompanying notes to combined consolidated financial statements.
ATLAS ENERGY GROUP, LLC
COMBINED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
See accompanying notes to combined consolidated financial statements.
ATLAS ENERGY GROUP, LLC
COMBINED CONSOLIDATED STATEMENT OF CHANGES IN UNITHOLDERS’ EQUITY (DEFICIT)
(in thousands, except unit data)
See accompanying notes to combined consolidated financial statements.
ATLAS ENERGY GROUP, LLC
COMBINED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
See accompanying notes to combined consolidated financial statements.
ATLAS ENERGY GROUP, LLC
NOTES TO COMBINED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1-ORGANIZATION
We are a publicly traded (OTCQX: ATLS) Delaware limited liability company formed in October 2011. Unless the context otherwise requires, references to “Atlas Energy Group, LLC,” “the Company,” “we,” “us,” “our” and “our company,” refer to Atlas Energy Group, LLC, and our combined and consolidated subsidiaries.
On February 27, 2015, our former owner, Atlas Energy, L.P. (“Atlas Energy”), transferred its assets and liabilities, other than those related to its midstream assets, to us, and effected a pro rata distribution of our common units representing a 100% interest in us, to Atlas Energy’s unitholders (the “Separation”). Concurrently with the distribution of our units, Atlas Energy and its remaining midstream interests merged with Targa Resources Corp. (“Targa”; NYSE: TRGP) and ceased trading.
Our operations primarily consisted of our ownership interests in the following:
•
During the period September 1, 2016 to December 31, 2016, Titan Energy, LLC (“Titan”), an independent developer and producer of natural gas, crude oil and natural gas liquids (“NGL”) with operations in basins across the United States. Titan Energy Management, LLC, our wholly owned subsidiary (“Titan Management”), holds the Series A Preferred Share of Titan, which entitles us to receive 2% of the aggregate of distributions paid to shareholders (as if we held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors. Titan sponsors and manages tax-advantaged investment partnerships (the “Drilling Partnerships”), in which it coinvests, to finance a portion of its natural gas, crude oil and NGL production activities. As discussed further below, Titan is the successor to the business and operations of Atlas Resource Partners, L.P. (“ARP”);
•
Through August 31, 2016, 100% of the general partner Class A units, all of the incentive distribution rights, and an approximate 23.3% limited partner interest (consisting of 24,712,471 common limited partner units) in ARP. As discussed further below, ARP was the predecessor to the business and operations of Titan;
•
All of the incentive distribution rights, an 80.0% general partner interest and a 2.1% limited partner interest in Atlas Growth Partners, L.P. (“AGP”), a Delaware limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations primarily focused in the Eagle Ford Shale in South Texas; and
•
12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of the Company’s board of directors, is the Chairman of the board of directors. Lightfoot focuses its investments primarily on incubating new MLPs and providing capital to existing MLPs in need of additional equity or structured debt.
At December 31, 2016, we had 26,044,592 common units issued and outstanding. The common units are a class of limited liability company interests in us. The holders of common units are entitled to participate in company distributions and exercise the rights or privileges available to holders of common units as outlined in the LLC Agreement.
The Company will continue as a limited liability company until dissolved under the LLC Agreement. The LLC Agreement specifies the manner in which the Company will make cash distributions to holders of common units and other partnership securities (see Note 12).
The following is a summary of the voting requirements specified for certain matters under the LLC Agreement:
•
Election of the directors to the Company’s board of directors - plurality of votes cast by the Company’s unitholders.
•
Issuance of additional company securities - no approval right, subject to the rules of any national securities exchange on which the Company’s securities are listed.
•
Amendment of the Company’s LLC Agreement - certain amendments may be made by the Company’s board of directors without the approval of the unitholders. Other amendments generally require the approval of a majority of the Company’s outstanding voting units.
•
Merger of the Company or the sale of all or substantially all of the Company’s assets - majority of the Company’s outstanding voting units in certain circumstances.
•
Dissolution of the Company - majority of the Company’s outstanding voting units.
•
Continuation of the Company upon dissolution - majority of the Company’s outstanding voting units.
•
The outstanding voting units consist of the Company’s common units and the Company’s Series A preferred units, which have voting rights identical to those of the Company’s common units on a “as converted” basis.
ARP Restructuring and Emergence from Chapter 11 Proceedings
On July 25, 2016, we, solely with respect to certain sections thereof, along with ARP and certain of its subsidiaries, entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) lenders holding 100% of ARP’s senior secured revolving credit facility (the “First Lien Lenders”), (ii) lenders holding 100% of ARP’s second lien term loan (the “Second Lien Lenders”) and (iii) holders (the “Consenting Noteholders” and, collectively with the First Lien Lenders and the Second Lien Lenders, and their respective successors or permitted assigns that become party to the Restructuring Support Agreement, the “Restructuring Support Parties”) of approximately 80% of the aggregate principal amount outstanding of the 7.75% Senior Notes due 2021 (the “7.75% Senior Notes”) and the 9.25% Senior Notes due 2021 (the “9.25% Senior Notes” and, together with the 7.75% Senior Notes, the “Notes”) of ARP’s subsidiaries, Atlas Resource Partners Holdings, LLC and Atlas Resource Finance Corporation (together, the “Issuers”). Under the Restructuring Support Agreement, the Restructuring Support Parties agreed, subject to certain terms and conditions, to support ARP’s Restructuring (the “Restructuring”) pursuant to a pre-packaged plan of reorganization (the “Plan”).
On July 27, 2016, ARP and certain of its subsidiaries filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code (“Chapter 11”) in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court,” and the cases commenced thereby, the “Chapter 11 Filings”). The cases commenced thereby were jointly administered under the caption “In re: ATLAS RESOURCE PARTNERS, L.P., et al.”
ARP operated its businesses as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of Chapter 11 and the orders of the Bankruptcy Court. Under the Plan, all suppliers, vendors, employees, royalty owners, trade partners and landlords were unimpaired by the Plan and were satisfied in full in the ordinary course of business, and ARP’s existing trade contracts and terms were maintained. To assure ordinary course operations, ARP obtained interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions seeking authority to use cash collateral on a consensual basis, pay wages and benefits for individuals who provide services to ARP, and pay vendors, oil and gas obligations and other creditor claims in the ordinary course of business.
On August 26, 2016, an order confirming the Plan was entered by the Bankruptcy Court. On September 1, 2016, (the “Plan Effective Date”), pursuant to the Plan, the following occurred:
•
the First Lien Lenders received cash payment of all obligations owed to them by ARP pursuant to the senior secured revolving credit facility (other than $440 million of principal and face amount of letters of credit) and became lenders under Titan’s first lien exit facility credit agreement, composed of a $410 million conforming reserve-based tranche and a $30 million non-conforming tranche.
•
the Second Lien Lenders received a pro rata share of Titan’s second lien exit facility credit agreement with an aggregate principal amount of $252.5 million. In addition, the Second Lien Lenders received a pro rata share of 10% of the common equity interests of Titan, subject to dilution by a management incentive plan.
•
Holders of the Notes, in exchange for 100% of the $668 million aggregate principal amount of Notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 Filings, received 90% of the common equity interests of Titan, subject to dilution by a management incentive plan.
•
all of ARP’s preferred limited partnership units and common limited partnership units were cancelled without the receipt of any consideration or recovery.
•
ARP transferred all of its assets and operations to Titan as a new holding company and ARP dissolved. As a result, Titan became the successor issuer to ARP for purposes of and pursuant to Rule 12g-3 of the Securities Exchange Act of 1934, as amended.
•
Titan Management received a Series A Preferred Share of Titan, which entitles Titan Management to receive 2% of the aggregate of distributions paid to shareholders (as if it held 2% of Titan’s members’ equity, subject to potential dilution in the event of future equity interests) and to appoint four of seven directors and certain other rights. Four of the seven initial members of the board of directors of Titan are designated by Titan Management (the “Titan Class A Directors”). For so long as Titan Management holds such preferred share, the Titan Class A Directors will be appointed by a majority of the Titan Class A Directors then in office. Titan has a continuing right to purchase the preferred share at fair market value (as determined pursuant to the methodology provided for in Titan’s limited liability company agreement), subject to the
receipt of certain approvals, including the holders of at least 67% of the outstanding common shares of Titan unaffiliated with Titan Management voting in favor of the exercise of the right to purchase the preferred share.
We were not a party to ARP’s Restructuring. We remain controlled by the same ownership group and management team and thus, ARP’s Restructuring did not have a material impact on the ability of management to operate us or our other businesses.
NOTE 2-BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation and Combination
Our combined consolidated financial statements for the years ended December 31, 2016 and 2015, subsequent to the transfer of assets on February 27, 2015, include our accounts and accounts of our subsidiaries. Our combined consolidated financial statements for the portion of 2015 that was prior to the transfer of assets on February 27, 2015, and the consolidated financial statements for the year ended December 31, 2014 were derived from the separate records maintained by Atlas Energy and may not necessarily be indicative of the conditions or results of operations that would have existed if we had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities we comprise, Atlas Energy’s net investment in us is shown as equity in the combined consolidated financial statements. U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the combined consolidated balance sheets and related combined consolidated statements of operations. Such estimates included allocations made from the historical accounting records of Atlas Energy, based on management’s best estimates, in order to derive our financial statements for the portion of 2015 that was prior to the transfer of assets on February 27, 2015, and the consolidated financial statements for the year ended December 31, 2014. Actual balances and results could be different from those estimates. We have identified our transactions with other Atlas Energy operations in the combined consolidated financial statements as transactions between affiliates.
In connection with Atlas Energy’s merger with Targa and the concurrent Separation, we were required to repay $150.0 million of Atlas Energy’s term loan credit facility, which was issued in July 2013 for $240.0 million. In accordance with U.S. GAAP, we included $150.0 million of Atlas Energy’s original term loan at the time of issuance, and the related interest expense, within our historical financial statements for the portion of 2015 that was prior to the transfer of assets on February 27, 2015, and the consolidated financial statements for the year ended December 31, 2014. Atlas Energy’s other historical borrowings were allocated to our historical financial statements in the same ratio. We used proceeds from the issuance of our Series A preferred units (see Note 11) and borrowings under our term loan credit facilities to fund the $150.0 million payment.
We determined that ARP (through the Plan Effective Date, as discussed further below) and AGP are variable interest entities (“VIE’s”) based on their respective partnership agreements, our power, as the general partner, to direct the activities that most significantly impact each of their respective economic performance, and our ownership of each of their respective incentive distribution rights. Accordingly, we consolidated the financial statements of ARP (until the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP into our combined consolidated financial statements. Our consolidated VIE’s operating results and asset balances are presented separately in Note 14 - Operating Segment Information. As the general partner for both ARP (through the Plan Effective Date) and AGP, we have unlimited liability for the obligations of ARP (through the Plan Effective Date) and AGP except for those contractual obligations that are expressly made without recourse to the general partner. The non-controlling interests in ARP (through the date of ARP’s Chapter 11 Filings, as discussed further below) and AGP are reflected as (income) loss attributable to non-controlling interests in the combined consolidated statements of operations and as a component of unitholders’ equity on the combined consolidated balance sheets. All material intercompany transactions have been eliminated.
In connection with ARP’s Chapter 11 Filings on July 27, 2016, we deconsolidated ARP’s financial statements from our combined consolidated financial statements, as we no longer had the power to direct the activities that most significantly impacted ARP’s economic performance; however, we retained the ability to exercise significant influence over the operating and financial decisions of ARP and therefore applied the equity method of accounting for our investment in ARP up to the Plan Effective Date. As a result of these changes, our combined consolidated financial statements subsequent to ARP’s Chapter 11 Filings will not be comparable to our combined financial statements prior to ARP’s Chapter 11 Filings. Our financial results for future periods following the application of equity method accounting will be different from historical trends and the differences may be material.
In accordance with established practice in the oil and gas industry, our combined consolidated financial statements include our pro-rata share of assets, liabilities, income and lease operating and general and administrative costs and expenses of the Drilling Partnerships in which ARP has an interest through the date of ARP’s Chapter 11 Filings. Such interests generally approximate 30%. Our combined consolidated financial statements do not include proportional consolidation of the depletion or impairment expenses of the Drilling Partnerships through the date of ARP’s Chapter 11 Filings. Rather, ARP calculated these items specific to its own economics through the date of ARP’s Chapter 11 Filings.
On the Plan Effective Date, we determined that Titan is a VIE based on its limited liability company agreement and the delegation of management and omnibus agreements between Titan and Titan Management, which provide us the power to direct activities that most significantly impact Titan’s economic performance, but we do not have a controlling financial interest. As a result, we do not consolidate Titan but rather apply the equity method of accounting as we have the ability to exercise significant influence over Titan’s operating and financial decisions.
On June 5, 2015, ARP completed the acquisition of our coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price using proceeds from the issuance of 6,500,000 common limited partner units. The Arkoma Acquisition had an effective date of January 1, 2015. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control in its standalone consolidated financial statements.
Liquidity, Capital Resources, and Ability to Continue as a Going Concern
Our primary sources of liquidity are cash distributions received with respect to our ownership interests in AGP, Lightfoot, and Titan and AGP’s annual management fee. However, neither Titan nor AGP are currently paying distributions. Our primary cash requirements, in addition to normal operating expenses, are for debt service and capital expenditures, which we expect to fund through operating cash flow, and cash distributions received. Accordingly, our sources of liquidity are currently not sufficient to satisfy our obligations under our credit agreements.
The significant risks and uncertainties related to our primary sources of liquidity raise substantial doubt about our ability to continue as a going concern. If we are unable to remain in compliance with the covenants under our credit agreements (as described in Note 6), absent relief from our lenders, we maybe be forced to repay or refinance such indebtedness. Upon the occurrence of an event of default, the lenders under our credit agreements could elect to declare all amounts outstanding immediately due and payable and could terminate all commitments to extend further credit. If an event of default occurs, we will not have sufficient liquidity to repay all of our outstanding indebtedness, and as a result, there would be substantial doubt regarding our ability to continue as a going concern. In addition to the $38 million of indebtedness due on September 30, 2017, we classified the remaining $44.6 million of outstanding indebtedness under our credit agreements as a current liability, based on the uncertainty regarding future covenant compliance. In total, we have $81.1 million of outstanding indebtedness under our credit agreements, which is net of $1.2 million of debt discounts and $0.2 million of deferred financing costs, as current portion of long term debt, net on our combined consolidated balance sheet as of December 31, 2016.
We continually monitor our capital markets and capital structures and may make changes from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening the balance sheet, meeting debt service obligations and/or achieving cost efficiency. For example, we could pursue options such as refinancing or reorganizing our indebtedness or capital structure or seek to raise additional capital through debt or equity financing to address our liquidity concerns and high debt levels. There is no certainty that we will be able to implement any such options, and we cannot provide any assurances that any refinancing or changes to our debt or equity capital structure would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all, and such options may result in a wide range of outcomes for our stakeholders, including cancellation of debt income (“CODI”) which would be directly allocated to our unitholders and reported on such unitholders’ separate returns. It is possible additional adjustments to our strategic plan and outlook may occur based on market conditions and our needs at that time, which could include selling assets or seeking additional partners to develop our assets.
Our combined consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Our combined consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.
Atlas Growth Partners - Liquidity, Capital Resources, and Ability to Continue as a Going Concern
AGP has historically funded its operations, acquisitions and cash distributions primarily through cash generated from operations and financing activities, including its private placement offering completed in 2015. AGP’s future cash flows are subject to a number of variables, including oil and natural gas prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of 2014 and have continued to decline and remain low in 2016. These lower commodity prices have negatively impacted AGP’s revenues, earnings and cash flows. Sustained low commodity prices will have a material and adverse effect on AGP’s liquidity position.
AGP was not a party to the Restructuring Support Agreement, and ARP’s Restructuring did not materially impact AGP.
On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues. In addition, AGP’s board of directors suspended its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets. Accordingly, these decisions raise substantial doubt about AGP’s ability to continue as a going concern. Management determined that substantial doubt is alleviated through management’s plans to reduce AGP’s general and administrative expenses, the majority of which represent allocations from ATLS.
Use of Estimates
The preparation of our combined consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of our combined consolidated financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. Our combined consolidated financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion and impairment of gas and oil properties, fair value of derivative and other financial instruments, fair value of certain gas and oil properties and asset retirement obligations, fair value of assets and liabilities in connection with accounting for business combinations, and fair value of equity method investments. In addition, such estimates included estimated allocations made from the historical accounting records of Atlas Energy in order to derive our historical financial statements, for the portion of 2015 that was prior to the transfer of assets on February 27, 2015, and the consolidated financial statements for the year ended December 31, 2014. The natural gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery. Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices. Actual results could differ from those estimates.
Cash Equivalents
We consider all highly liquid investments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. These cash equivalents consist principally of temporary investments of cash in short-term money market instruments.
Receivables
Accounts receivable on the combined consolidated balance sheets consist primarily of the trade accounts receivable associated with our operations. We perform ongoing credit evaluations of customers and adjust credit limits based upon payment history and the customers’ current creditworthiness. We extend credit on sales on an unsecured basis to many of our customers. At December 31, 2016 and 2015, we had recorded no allowance for uncollectible accounts receivable on our combined consolidated balance sheets.
Inventory
We had $8.0 million of inventory at December 31, 2015, which was included within prepaid expenses and other current assets on our combined consolidated balance sheet. We did not have any inventory at December 31, 2016. We value inventories at the lower of cost or market. Our inventory, which consisted primarily of ARP’s materials, pipes, supplies and other inventories, was principally determined using the average cost method. During the year ended December 31, 2015, we recognized a $1.2 million loss on asset sales and disposal on our combined consolidated statement of operations, related to the obsolescence of ARP’s pipe, pump units and other inventory in the New Albany Shale and Black Warrior basin.
Subscriptions Receivable
We received contributions from limited partner investors of ARP’s Drilling Partnerships, which were used to fund well drilling activities within the programs. Limited partner investors in the Drilling Partnerships executed an investment agreement with Anthem Securities, Inc. (“Anthem”), a registered broker dealer and wholly owned subsidiary of ARP, through third-party broker dealers, which was then delivered to Anthem. The investor contributions were then remitted to Anthem at a later date. Limited partner investor contributions were non-refundable upon the execution of an investment agreement. We recognized the contributions associated with executed investment agreements but for which contributions have not yet been received at the respective balance sheet date as subscriptions receivable.
Property, Plant and Equipment
Property, plant and equipment are stated at cost or, upon acquisition of a business, at the fair value of the assets acquired. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for
two years or more through the replacement of critical components are capitalized. Depreciation and amortization expense is based on cost less the estimated salvage value primarily using the straight-line method over the asset’s estimated useful life. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.
We follow the successful efforts method of accounting for oil and gas producing activities. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs to enhance or evaluate development of proved fields or areas are capitalized. All other geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. “Mcf” is defined as one thousand cubic feet.
Our depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for leasehold acquisition costs are based on estimated proved reserves, and depletion rates for well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of undeveloped and developed producing properties. We also consider the estimated salvage value in the calculation of depreciation, depletion and amortization. Capitalized costs of developed producing properties in each field were aggregated to include ARP’s costs of property interests in proportionately consolidated Drilling Partnerships, joint venture wells, wells drilled solely by ARP for its interests, properties purchased and working interests with other outside operators.
Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to our combined consolidated statement of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within our combined consolidated balance sheet. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in our combined consolidated statement of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained.
Support equipment and other are carried at cost and consist primarily of pipelines, processing and compression facilities, and gathering systems and related support equipment. We compute depreciation of support equipment and other using the straight-line balance method over the estimated useful life of each asset category as follows: Pipelines, processing and compression facilities: 15-20 years; Buildings and land improvements: 3-40 years; Other support equipment: 3-10 years.
See Note 4 for additional disclosures regarding property, plant and equipment.
Impairment of Long-Lived Assets
We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
Our unproved properties are assessed individually based on several factors including if a dry hole has been drilled in the area, other wells drilled in the area and operating results, remaining months in the lease’s primary term, and management’s future plans to drill and develop the area. As exploration and development work progresses and the reserves on properties are proven, capitalized costs of these properties are subject to depletion. If exploration activities are unsuccessful, the capitalized costs of the properties related to the unsuccessful work is charged to exploration expense. The timing of impairment of any significant unproved properties depends upon the nature, timing and extent of future exploration and development activities and their results.
The review of oil and gas properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion, depreciation and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on our plans to continue to produce and develop proved reserves. Expected future cash flows from the sale of production of reserves are calculated based on estimated future prices. We estimate prices based upon current contracts in place, adjusted for basis differentials and market-related information including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected undiscounted future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets.
The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, ARP’s reserve estimates for its investment in the Drilling Partnerships were based on its own assumptions rather than its proportionate share of the Drilling Partnerships’ reserves. These assumptions included ARP’s actual capital contributions and a disproportionate share of salvage value upon plugging of the wells and lower operating and administrative costs.
ARP’s lower operating and administrative costs resulted from the limited partners in the Drilling Partnerships paying to ARP operating and administrative fees in addition to their proportionate share of external operating expenses. These assumptions resulted in ARP’s calculation of depletion and impairment being different than its proportionate share of the Drilling Partnerships’ calculations for these items. In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. We cannot predict what reserve revisions may be required in future periods.
ARP’s method of calculating its reserves resulted in reserve quantities and values which were greater than those which would be calculated by the Drilling Partnerships. ARP’s reserve quantities included reserves in excess of its proportionate share of reserves in Drilling Partnerships, which ARP may have been unable to recover due to the Drilling Partnerships’ legal structure.
See Note 4 for additional disclosures regarding impairment of property, plant and equipment.
Capitalized Interest
We capitalize interest on ARP’s borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average interest rates used to capitalize interest on combined borrowed funds by ARP were 6.6%, 6.5% and 5.6% for the years ended December 31, 2016, 2015 and 2014, respectively. The aggregate amounts of interest capitalized were $5.4 million, $15.8 million and $13.0 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Intangible Assets
We recorded our intangible assets with finite lives in connection with partnership management and operating contracts acquired through prior consummated acquisitions. We amortize contracts acquired on a declining balance method over their respective estimated useful lives. We evaluate intangible assets for impairment annually or whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value.
We had a $0.5 million net carrying amount of intangible assets recorded within goodwill and intangible assets, net on our consolidated balance sheet at December 31, 2015. Amortization expense on our intangible assets during the years ended December 31, 2016, 2015 and 2014 was $0.3 million, $0.2 million, and $0.3 million, respectively. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2 - Basis of Presentation and Principles of Consolidation and Combination), which included ARP’s remaining $0.1 million of intangible assets, net.
Goodwill
We evaluate goodwill for impairment annually or whenever impairment indicators arise by comparing our reporting units’ estimated fair values to their carrying values. Because quoted market prices for the reporting units are not available, we must apply judgment in determining the estimated fair value of our reporting units. We use all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in our assets. A key component of these fair value determinations is a reconciliation of the sum of the fair value calculations to our market capitalization. The observed market prices of individual trades of an entity’s equity securities (and thus its computed market capitalization) may not be representative of the fair value of the entity as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of that entity on a stand-alone basis. In most industries, including ours, an acquiring entity typically is willing to pay more for equity securities that give it a controlling interest than an investor would pay for a number of equity securities representing less than a controlling interest.
Therefore, once the fair value calculations have been determined, we also consider the inclusion of a control premium within the calculations. This control premium is judgmental and is based on, among other items, observed acquisitions in our industry. The resultant fair values calculated for the reporting units are compared to observable metrics on large mergers and acquisitions in our industry to determine whether those valuations appear reasonable in management’s judgment.
As a result of our goodwill impairment evaluation at December 31, 2014, ARP recognized an $18.1 million non-cash impairment charge within asset impairments on our combined consolidated statement of operations for the year ended December 31, 2014. The goodwill impairment resulted from the reduction in ARP’s estimated fair value of its gas and oil production reporting unit in comparison to its carrying amount at December 31, 2014. ARP’s estimated fair value of its gas and oil production reporting unit was impacted by a decline in overall commodity prices during the fourth quarter of 2014. The $13.6 million remaining goodwill at December 31, 2014 and 2015 was attributable to ARP’s well construction and completion and other partnership management reporting units that was recorded in connection with prior consummated acquisitions. No changes in the carrying amount of goodwill were recorded during the years ended December 31, 2016 and 2015. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2 - Basis of Presentation and Principles of Consolidation and Combination), which included ARP’s remaining $13.6 million of goodwill.
Derivative Instruments
We enter into certain financial contracts to manage our exposure to movement in commodity prices. The derivative instruments recorded in the consolidated balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in our consolidated statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, we discontinued hedge accounting through de-designation for all of our existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives were recognized immediately within gain (loss) on mark-to-market derivatives in our consolidated statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 were reclassified to the consolidated statement of operations in the periods in which the respective derivative contracts settled. Prior to discontinuance of hedge accounting, the fair value of commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within unitholders’ equity on our consolidated balance sheet and reclassified to the consolidated statement of operations at the time the originally hedged physical transactions affected earnings. See Note 7 for additional disclosures regarding derivative instruments.
Other Assets
In April 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs. The updated accounting guidance requires that debt issuance costs be presented as a direct deduction from the associated debt obligation. We adopted this accounting guidance upon its effective date of January 1, 2016. The retrospective effect of the reclassification resulted in the following changes to our consolidated balance sheet:
Deferred financing costs related to revolving credit facility (line-of-credit) arrangements are recorded at cost, amortized over the term of the arrangement, and are presented net of accumulated amortization within other assets, net on our combined consolidated balance sheet. We had revolving credit facility deferred financing costs of $0.2 million and $20.1 million, respectively, which were net of $0.1 million and $29.1 million of accumulated amortization, recorded within other assets, net on our combined consolidated balance sheets at December 31, 2016 and 2015, respectively. For the years ended December 31, 2016, 2015 and 2014, amortization expense of revolving credit facility deferred financing costs was $10.0 million, $14.2 million and $7.5 million, respectively, which was recorded within interest expense on our consolidated statements of operations. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2 - Basis of Presentation and Principles of Consolidation and Combination), which included ARP’s $15.5 million of revolving credit facility deferred financing costs, net.
At December 31, 2015, we had $3.7 million of notes receivable with certain investors of ARP’s Drilling Partnerships, which were included within other assets, net on our combined consolidated balance sheet. The notes have a maturity date of March 31, 2022, and a 2.25% per annum interest rate. The maturity date of the notes can be extended to March 31, 2027, subject to certain conditions, including an extension fee of 1.0% of the outstanding principal balance On the date of the Chapter 11 Filings, we deconsolidated ARP
for financial reporting purposes (see Note 2 - Basis of Presentation and Principles of Consolidation and Combination), which included ARP’s $3.7 million of notes receivable with certain investors of the Drilling Partnerships.
Equity Method Investments
Investment in ARP. As a result of deconsolidating ARP and recording our equity method investment in ARP at fair value of zero on the date of the Chapter 11 Filings, we recognized a $46.4 million non-cash gain, which was recorded in gain on deconsolidation of ARP on our combined consolidated statements of operations for the year ended December 31, 2016, and includes a $61.7 million gain related to the remeasurement of our retained noncontrolling investment to fair value. During the period after the Chapter 11 Filings through August 31, 2016, ARP generated a net loss, and therefore we did not record any equity method income/(loss) based on our 25% proportionate share because such loss exceeded our investment, and we had no obligation to fund such loss. Due to the cancellation of ARP’s preferred limited partnership units and common limited partnership units without the receipt of any consideration or recovery on the Plan Effective Date, we no longer hold an equity method investment in ARP.
Investment in Titan. On the Plan Effective Date, we recorded our equity method investment in Titan at fair value of $0.6 million, which was recorded in gain on deconsolidation of ARP on our combined consolidated statements of operations for the year ended December 31, 2016. For the period from the Plan Effective Date to December 31, 2016, we recorded an equity method loss of $0.6 million based on our 2% proportionate share of Titan’s net loss, which was recorded in other, net on our combined consolidated statements of operations for the year ended December 31, 2016, and which reduced our equity investment balance to zero at December 31, 2016.
Investment in Lightfoot. At December 31, 2016, we had an approximate 12.0% interest in Lightfoot L.P. and an approximate 15.9% interest in Lightfoot G.P., the general partner of Lightfoot L.P. We account for our investment in Lightfoot under the equity method of accounting due to our ability to exercise significant influence. As of December 31, 2016 and 2015, the net carrying amount of our investment in Lightfoot was $18.7 million and $19.3 million, respectively. During the years ended December 31, 2016, 2015 and 2014, we recognized equity income of $1.2 million, $0.7 million and $1.1 million, respectively, within other, net on our combined consolidated statements of operations. During the years ended December 31, 2016, 2015 and 2014, we received net cash distributions of approximately $1.9 million, $2.8 million and $1.7 million, respectively.
Rabbi Trust
In 2011, we established an excess 401(k) plan relating to certain executives. In connection with the plan, we established a “rabbi” trust for the contributed amounts. At December 31, 2016 and 2015, we reflected $4.2 million and $5.6 million, respectively, related to the value of the rabbi trust within other assets, net on our consolidated balance sheets, and recorded corresponding liabilities of $4.2 million and $5.6 million as of those same dates, respectively, within asset retirement obligations and other on our consolidated balance sheets. During the years ended December 31, 2016 and 2014, we distributed $2.3 million and $1.9 million, respectively, to certain executives related to the rabbi trust. During the year ended December 31, 2015, no distributions were made to certain executives related to the rabbi trust.
Asset Retirement Obligations
We recognize an estimated liability for the plugging and abandonment of gas and oil wells and related facilities. We recognize a liability for future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. See Note 5 for additional disclosures regarding asset retirement obligations.
Accrued Liabilities
We had $10.6 of accrued payroll and benefit items at December 31, 2016, which was included within accrued liabilities at on our combined consolidated balance sheet.
Other Non-current Liabilities
We have two lease agreements in AGP’s Eagle Ford operating area that require us to perform certain drilling and development activities by a specified date or pay liquidated damages to maintain the leases. As of December 31, 2016, we determined the liquidated damages were a probable loss contingency and estimated the value of the liquidated damages enforceable under Texas law, resulting in a recognition of $0.5 million as a non-current liability on our consolidated balance sheet.
ARP Preferred Units
In connection with ARP’s acquisition of certain proved reserves and associated assets from Titan Operating, L.L.C. in July 2012, ARP issued 3.8 million convertible Class B ARP preferred units (“Class B ARP Preferred Units”). While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 and (ii) the quarterly common unit distribution. On December 23, 2014, 3,796,900 of Class B ARP Preferred Units were converted into common units, while the remaining 39,654 Class B ARP Preferred Units were converted into common units on July 25, 2015.
In connection with ARP’s acquisition of certain proved reserves and associated assets from EP Energy, Inc. in July 2013, ARP issued 3.7 million convertible Class C ARP preferred units to Atlas Energy (“Class C ARP Preferred Units”). While outstanding, the Class C ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.51 and (ii) the quarterly common unit distribution.
In October 2014, in connection with ARP’s acquisition of assets in the Eagle Ford Shale (see Note 3), ARP issued 3.2 million of 8.625% Class D cumulative redeemable perpetual preferred units (“Class D ARP Preferred Units”) and in March 2015, issued an additional 800,000 Class D ARP Preferred Units (see Note 12). The initial quarterly distribution on the Class D ARP Preferred Units was $0.616927 per unit, representing the distribution for the period from October 2, 2014 through January 14, 2015. Subsequent to January 14, 2015, ARP paid quarterly distributions on the Class D ARP Preferred Units at an annual rate of $2.15625 per unit, or 8.625% of the liquidation preference.
In April 2015, ARP issued 255,000 of 10.75% Class E cumulative redeemable perpetual preferred units (“Class E ARP Preferred Units”). The initial quarterly distribution on the Class E ARP Preferred Units was $0.6793 per unit, representing the distribution for the period from April 14, 2015 through July 14, 2015. Subsequent to July 15, 2015, ARP paid quarterly distributions on the Class E Preferred Units at an annual rate of $2.6875 per unit, or 10.75% of the liquidation preference.
At December 31, 2015, $103.3 million related to ARP’s preferred units, is included within non-controlling interests on our combined consolidated statement of unitholders’ equity. See Note 12 for the distributions paid related to ARP’s Preferred Units during the years ended December 31, 2016, 2015, and 2014.
Income Taxes
We and our consolidated subsidiaries are not subject to U.S. federal and most state income taxes. Our unitholders and the limited partners of our subsidiaries are liable for income tax in regard to their distributive share of the entities’ taxable income. Such taxable income may vary substantially from net income (loss) reported in the combined consolidated financial statements. Certain corporate subsidiaries of ARP were subject to federal and state income tax and were immaterial to our combined consolidated financial statements for each year presented and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in our combined consolidated financial statements.
We evaluate tax positions taken or expected to be taken in the course of preparing the respective tax returns and disallow the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. We do not believe we have any tax positions taken within our combined consolidated financial statements that would not meet this threshold. Our policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. We have not recognized any such potential interest or penalties in our combined consolidated financial statements for the years ended December 31, 2016, 2015 and 2014.
We file Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, we are no longer subject to income tax examinations by major tax authorities for years prior to 2013 and are not currently being examined by any jurisdiction and are not aware of any potential examinations as of December 31, 2016.
Unit-Based Compensation
We recognize all unit-based payments to employees, including grants of employee unit options, in the combined consolidated financial statements based on their fair values (see Note 13).
Net Income (Loss) Per Common Unit
Basic net income (loss) attributable to common unitholders per unit is computed by dividing net income (loss) attributable to common unitholders, which is determined after the deduction of net income attributable to participating securities and the preferred unitholders’ interests, if applicable, by the weighted average number of common units outstanding during the period.
Unvested unit-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities. A portion of our phantom unit awards, which consist of common units issuable under the terms of our long-term incentive plans and incentive compensation agreements, contain non-forfeitable rights to distribution equivalents. The participation rights result in a non-contingent transfer of value each time we declare a distribution or distribution equivalent right during the award’s vesting period. However, unless the contractual terms of the participating securities require the holders to share in the losses of the entity, net loss is not allocated to the participating securities. As such, the net income utilized in the calculation of net income (loss) per unit must be after the allocation of only net income to the phantom units on a pro-rata basis.
The following is a reconciliation of net income (loss) allocated to the common unitholders for purposes of calculating net income (loss) attributable to common unitholders per unit (in thousands, except unit data):
(1)
Net income (loss) attributable to common unitholders for the net income (loss) attributable to common unitholders per unit calculation is net income (loss) attributable to common unitholders, less income allocable to participating securities. For the years ended December 31, 2016 and 2015, net loss attributable to common unitholder’s ownership interest was not allocated to approximately 330,000 and 68,000 phantom units, respectively, because the contractual terms of the phantom units as participating securities do not require the holders to share in the losses of the entity.
Diluted net income (loss) attributable to common unitholders per unit is calculated by dividing net income (loss) attributable to common unitholders, less income allocable to participating securities, by the sum of the weighted average number of common unitholder units outstanding and the dilutive effect of unit option awards and convertible preferred units, as calculated by the treasury stock or if converted methods, as applicable. Unit options consist of common units issuable upon payment of an exercise price by the participant under the terms of our long-term incentive plan.
The following table sets forth the reconciliation of our weighted average number of common units used to compute basic net loss attributable to common unitholders per unit with those used to compute diluted net loss attributable to common unitholders per unit (in thousands):
(1)
For the years ended December 31, 2016 and 2015, approximately 2,986,000 and 1,817,000 phantom units, respectively, were excluded from the computation of diluted net income (loss) attributable to common unitholders per unit, because the inclusion of such units would have been anti-dilutive.
(2)
Our warrants issued in connection with the Second Lien Credit Agreement in 2016 and our convertible Series A Preferred Units were excluded from the computation of diluted earnings attributable to common unitholders per unit, because the inclusion of such warrants and units would have been anti-dilutive.
Concentration of Credit Risk
Financial instruments, which potentially subject us to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. We place our temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At December 31, 2016 and 2015, we had $13.9 million and $41.1 million, respectively, in deposits at various banks, of which $12.2 million and $38.3 million, respectively, were over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments to date. Cash on deposit at various banks may differ from the balance of cash and cash equivalents at period end due to certain reconciling items, including any outstanding checks as of period end.
We sell natural gas, oil, NGLs and condensate under contract to various purchasers in the normal course of business. For the year ended December 31, 2016, ARP had three customers, Tenaska Marketing Ventures, Interconn Resources LLC, and Chevron, that individually accounted for approximately 29%, 15% and 14%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, ARP had four customers, Tenaska Marketing Ventures, Chevron, Enterprise and Interconn Resources LLC, that individually accounted for approximately 21%, 15%, 11% and 11%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, ARP had four customers, Tenaska Marketing Ventures, Chevron, Enterprise and Interconn Resources LLC, within its gas and oil production segment that individually accounted for approximately 25%, 15%, 14% and 13%, respectively, of its natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2016, AGP had two customers, Shell Trading Co. and Enterprise Crude Oil, LLC, within its gas and oil production segment that individually accounted for approximately 64% and 29% respectively, of AGP’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2015, AGP had three customers, Enterprise Crude Oil, LLC, Shell Trading Co. and Midcoast Energy Partners, within its gas and oil production segment that individually accounted for approximately 59%, 28% and 12% respectively, of AGP’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, AGP had two customers, Enterprise Crude Oil, LLC and Midcoast Energy Partners, within its gas and oil production segment that individually accounted for approximately 67% and 33% of AGP’s natural gas, oil and NGL consolidated revenues, excluding the impact of all financial derivative activity.
We are subject to the risk of loss on our derivative instruments that would occur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We maintain credit policies with regard to our counterparties to minimize their overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the quarterly monitoring of our oil, natural gas and NGLs counterparties’ credit exposures; (iii) comprehensive credit reviews on significant counterparties from physical and financial transactions on an ongoing basis; (iv) the utilization of contractual language that affords them netting or set off opportunities to mitigate exposure risk; and (v) when appropriate, requiring counterparties to post cash collateral, parent guarantees or letters of credit to minimize credit risk. AGP’s liabilities related to derivatives as of December 31, 2016 represent financial instruments from two counterparties; both of which are a financial institutions that have an “investment grade” (minimum Standard & Poor’s rating of BBB+ or better) credit rating and are lenders associated with AGP’s secured credit facility. Subject to the terms of AGP’s secured credit facility, collateral or other securities are not exchanged in relation to derivatives activities with the parties in the secured credit facility.
Revenue Recognition
Natural gas and oil production. Our gas and oil production operations generally sell natural gas, crude oil and NGLs at prevailing market prices. Typically, sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of the natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil and NGLs, in which we have an interest with other producers, are recognized on the basis of the entity’s percentage ownership of the working interest and/or overriding royalty.
ARP’s Drilling Partnerships. Certain energy activities were conducted by ARP through, and a portion of its revenues were attributable to, sponsorship of the Drilling Partnerships. Drilling Partnership investor capital raised by ARP was deployed to drill and complete wells included within the partnership. As ARP deployed Drilling Partnership investor capital, it recognized certain management fees it was entitled to receive, including well construction and completion revenue and a portion of administration and oversight revenue. At each period end, if ARP had Drilling Partnership investor capital that had not yet been deployed, it would recognize a current liability titled “Liabilities Associated with Drilling Contracts” on our combined consolidated balance sheets. After the Drilling Partnership well was completed and turned in line, ARP was entitled to receive additional operating and management fees, which were included within well services and administration and oversight revenue, respectively, on a monthly basis while the well was operating. In addition to the management fees it was entitled to receive for services provided, ARP was also entitled to its pro-rata share of Drilling Partnership gas and oil production revenue, which was generally between 10-30%. ARP recognized its Drilling Partnership management fees in the following manner:
•
Well construction and completion. For each well that was drilled by a Drilling Partnership, ARP received a 15% mark-up on those costs incurred to drill and complete wells included within the partnership. Such fees were earned, in accordance with the partnership agreement, and recognized as the services were performed, typically between 60 and 270 days.
•
Administration and oversight. For each well drilled by a Drilling Partnership, ARP received a fixed fee between $100,000 and $500,000, depending on the type of well drilled, which was earned, in accordance with the partnership agreement, and recognized at the initiation of the well. Additionally, the Drilling Partnership paid ARP a monthly per well administrative fee of $75 for the life of the well. The well administrative fee was earned on a monthly basis as the services were performed.
•
Well services. Each Drilling Partnership paid ARP a monthly per well operating fee, $1,000 to $2,000, depending on the type of well, for the life of the well. Such fees were earned on a monthly basis as the services were performed.
While the historical structure varied, ARP generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of cumulative unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they have received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. ARP periodically compared the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment fell below the agreed upon rate, ARP recognized subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that would achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP has recognized subordination in a historical period, if projected investment returns subsequently reflected that the agreed upon limited partner investment return would be achieved during the subordination period, ARP would recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized.
ARP’s gathering and processing revenue. Gathering and processing revenue included gathering fees ARP charges to the Drilling Partnership wells for ARP’s processing plants in the New Albany and the Chattanooga shales. Generally, ARP charged a gathering fee to the Drilling Partnership wells equivalent to the fees ARP remitted. In Appalachia, a majority of the Drilling Partnership wells were subject to a gathering agreement, whereby ARP remitted a gathering fee of 16%. However, based on the respective Drilling Partnership agreements, ARP charged the Drilling Partnership wells a 13% gathering fee. As a result, some of ARP’s gathering expenses, specifically those in the Appalachian Basin, would generally exceed the revenues collected from the Drilling Partnerships by approximately 3%.
Our gas and oil production operations accrue unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate and the receipt of a delivery statement. These revenues are recorded based upon volumetric data and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices. We had unbilled revenues at December 31, 2016 and 2015 of $0.8 million and $39.9 million, respectively, which were included in accounts receivable within our combined consolidated balance sheets.
Comprehensive Income (Loss)
Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on our combined consolidated financial statements, and for all periods presented, only include changes in the fair value of unsettled derivative contracts accounted for as cash flow hedges (see Note 7). We do not have any other type of transaction which would be included within other comprehensive income (loss).
Recently Issued Accounting Standards
In February 2016, the Financial Accounting Standards Board (“FASB”) updated the accounting guidance related to leases. The updated accounting guidance requires lessees to recognize a lease asset and liability at the commencement date of all leases (with the exception of short-term leases), initially measured at the present value of the lease payments. The updated guidance is effective for us as of January 1, 2019 and requires a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest period presented. We are currently in the process of determining the impact that the updated accounting guidance will have on our combined consolidated financial statements.
In August 2015, the FASB updated the accounting guidance related to the balance sheet presentation of debt issuance costs specific to line-of-credit arrangements. The updated accounting guidance allows the option of presenting deferred debt issuance costs related to line-of-credit arrangements as an asset, and subsequently amortizing over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings. We adopted the updated accounting guidance effective January 1, 2016, and it did not have a material impact on our combined consolidated financial statements.
In February 2015, the FASB updated the accounting guidance related to consolidation under the variable interest entity and voting interest entity models. The updated accounting guidance modifies the consolidation guidance for variable interest entities, limited partnerships and similar legal entities. We adopted this accounting guidance upon its effective date of January 1, 2016, and it did not have a material impact on our combined consolidated financial statements.
In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary. We adopted this accounting guidance on January 1, 2016, and provided enhanced disclosures, as applicable, within our combined consolidated financial statements.
In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. We are evaluating the impact of this updated accounting guidance on our consolidated financial statements, and based on the continuing evaluation of our revenue streams, this accounting guidance is not expected to have a material impact on our net income (loss). This accounting guidance will require that our revenue recognition policy disclosures include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. We are still in the process of determining whether or not we will use the retrospective method or the modified retrospective approach to implementation.
NOTE 3-ACQUISITIONS
ARP’s Rangely Acquisition
On June 30, 2014, ARP completed an acquisition of a 25% non-operated net working interest in oil and natural gas liquids producing assets in the Rangely field in northwest Colorado from Merit Management Partners I, L.P., Merit Energy Partners III, L.P. and Merit Energy Company, LLC (collectively, “Merit Energy”) for approximately $408.9 million in cash, net of purchase price adjustments (the “Rangely Acquisition”). The purchase price was funded through borrowings under ARP’s revolving credit facility, the issuance of an additional $100.0 million of ARP’s 7.75% Senior Notes and the issuance of 15,525,000 of ARP’s common limited partner units (see Note 11). The Rangely Acquisition had an effective date of April 1, 2014. The Company’s combined consolidated financial statements reflected the operating results of the acquired business commencing June 30, 2014 with the transaction closing.
ARP accounted for this transaction under the acquisition method of accounting. Accordingly, ARP evaluated the identifiable assets acquired and liabilities assumed at their respective acquisition date fair values. In conjunction with the issuance of ARP’s
common limited partner units associated with the acquisition, ARP recorded $11.6 million of transaction fees which were included within non-controlling interests at December 31, 2014 on our combined consolidated balance sheet. All other costs associated with the acquisition of assets were expensed as incurred.
The following table presents the values assigned to the assets acquired and liabilities assumed in the acquisition, based on their estimated fair values at the date of the acquisition (in thousands):
Assets:
Prepaid expenses and other
$
4,041
Property, plant and equipment
405,416
Other assets, net
2,888
Total assets acquired
$
412,345
Liabilities:
Accrued liabilities
2,117
Asset retirement obligation
1,305
Total liabilities assumed
3,422
Net assets acquired
$
408,923
Other Acquisitions
ARP’s Arkoma Acquisition
On June 5, 2015, ARP completed the acquisition of the Company’s coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma for approximately $31.5 million, net of purchase price adjustments (the “Arkoma Acquisition”). ARP funded the purchase price through the issuance of 6,500,000 common limited partner units. The Arkoma Acquisition had an effective date of January 1, 2015. ARP accounted for the Arkoma Acquisition as a transaction between entities under common control in its standalone consolidated financial statements.
Our Subsidiaries’ Eagle Ford Acquisition
On November 5, 2014, our ARP and AGP subsidiaries completed an acquisition of oil and natural gas liquid interests in the Eagle Ford Shale in Atascosa County, Texas from Cima Resources, LLC and Cinco Resources, Inc. (together “Cinco”) for $342.0 million, net of purchase price adjustments (the “Eagle Ford Acquisition”). Approximately $183.1 million was paid in cash by ARP and $19.9 million was paid by AGP at closing, and approximately $139.0 million was to be paid in four quarterly installments beginning December 31, 2014. On December 31, 2014, AGP made its first installment payment of $35.0 million. Prior to the March 31, 2015 installment, ARP, AGP, and Cinco amended the purchase and sale agreement to alter the timing and amount of the quarterly payments beginning with the March 31, 2015 payment and ending December 31, 2015, with no change to the overall purchase price. On March 31, 2015, AGP paid $28.3 million and ARP issued $20.0 million of its Class D ARP Preferred Units (see Note 11) to satisfy the second installment. On June 30, 2015, AGP paid $16.0 million and ARP paid $0.6 million to satisfy the third installment. On July 8, 2015, AGP sold to ARP, for a purchase price of $1.4 million, AGP’s interest in a portion of the acreage AGP acquired in the Eagle Ford Acquisition, which represented AGP’s cost basis for the properties. The transaction was approved by both AGP’s and ARP’s respective conflicts committees. On September 21, 2015, ARP agreed with AGP to have AGP transfer its remaining $36.3 million of deferred purchase obligation, along with the related undeveloped natural gas and oil properties, to ARP. On October 1, 2015, ARP paid $17.5 million to satisfy the fourth installment. On December 31, 2015, ARP paid the $21.6 million final deferred portion of the purchase price. The Eagle Ford Acquisition had an effective date of July 1, 2014. ARP’s issuance of Class D ARP Preferred Units in March 2015 represented a non-cash transaction for statement of cash flow purposes during the year ended December 31, 2015.
ARP’s GeoMet Acquisition
On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. (“GeoMet”) (OTCQB: GMET) for approximately $97.9 million in cash, net of purchase price adjustments (the “GeoMet Acquisition”), with an effective date of January 1, 2014. The assets included coal-bed methane producing natural gas assets in West Virginia and Virginia.
NOTE 4-PROPERTY, PLANT AND EQUIPMENT
The following is a summary of property, plant and equipment at the dates indicated (in thousands):
For the years ended December 31, 2016, 2015 and 2014, we recognized $0.4 million, $21.5 million and $36.8 million, respectively, of non-cash investing activities capital expenditures, which were reflected within the changes in accounts payable and accrued liabilities on our combined consolidated statements of cash flows. For the year ended December 31, 2016, we recognized $7.7 million of non-cash investing activities capital expenditures related to ARP’s consolidation of certain Drilling Partnerships (see Note 9), which was reflected within the changes to adjustments to reconcile net loss to net cash provided by operating activities - other (income) loss on our consolidated statement of cash flows.
Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment charges are recorded if conditions indicate we will not explore the acreage prior to expiration of the applicable leases or if it is determined that the carrying value of the properties is above their fair value. As of December 31, 2016, we classified $63.3 million of AGP’s natural gas and oil properties as unproved properties due to challenges in capital fundraising. For the year ended December 31, 2016, we recognized $16.5 million of asset impairment related to AGP’s unproved oil and gas properties in the Eagle Ford operating area, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, we recognized $6.6 million of asset impairments in unproved gas and oil properties related to ARP’s unproved acreage in the New Albany Shale, which was impaired due to expiring acerage and no intention to pursue development. There were no impairments of unproved gas and oil properties recorded for the year ended December 31, 2014.
Proved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. Asset impairments and offsetting hedge gains, if any, are included in asset impairment expense in our combined consolidated statements of operations. For the year ended December 31, 2016, we recognized $25.4 million of asset impairment related to AGP’s proved oil and gas properties in our Eagle Ford operating area, which was impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. For the year ended December 31, 2015, we recognized $967.4 million of asset impairment of which $960 million related to ARP’s proved oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future hedge gains reclassified from accumulated other comprehensive income, and $7.4 million related to AGP’s proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. For the year ended December 31, 2014, we recognized $562.6 million of asset impairment of which $555.7 related to ARP’s proved oil and gas properties in Appalachian and Mid-Continent operations, which were impaired due to lower forecasted commodity prices, net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, and $6.9 million related to AGP’s proved oil and gas properties in the Marble Falls operating area, which was impaired due to lower forecasted commodity prices.
During the year ended December 31, 2015, we recognized a $1.2 million loss on asset sales and disposal related to ARP’s plugging and abandonment costs for certain wells in the New Albany Shale. During the year ended December 31, 2014, we recognized $1.9 million of loss on asset sales and disposal primarily pertaining to ARP’s sale of producing wells in the Niobrara Shale in connection with the settlement of a third party farmout agreement.
NOTE 5-ASSET RETIREMENT OBLIGATIONS
The estimated liability for asset retirement obligations was based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we determined there were no other material retirement obligations associated with tangible long-lived assets.
ARP proportionately consolidated its ownership interest of the asset retirement obligations of its Drilling Partnerships. At December 31, 2015, the Drilling Partnerships had $44.2 million of aggregate asset retirement obligation liabilities recognized on their combined balance sheets allocable to the limited partners, exclusive of ARP’s proportional interest in such liabilities. Under the terms of the respective partnership agreements, ARP maintained the right to retain a portion or all of the distributions to the limited partners of its Drilling Partnerships to cover the limited partners’ share of the plugging and abandonment costs up to a specified amount per month. As of December 31, 2015, ARP had withheld approximately $5.2 million of limited partner distributions related to the asset retirement obligations of certain Drilling Partnerships. ARP’s historical practice was to retain distributions from the limited partners as the wells within each Drilling Partnership near the end of their useful life. On a partnership-by-partnership basis, ARP assessed its right to withhold amounts related to plugging and abandonment costs based on several factors, including commodity price trends, the natural decline in the production of the wells, and current and future costs. Generally, ARP’s intention was to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approached the fair value of the future plugging and abandonment cost. Upon ARP’s decision to retain all future distributions to the limited partners of its Drilling Partnerships, ARP would assume the related asset retirement obligations of the limited partners. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2), which included the above activities related to the Drilling Partnerships.
A reconciliation of the Company’s subsidiaries’ liability for well plugging and abandonment costs for the periods indicated is as follows (in thousands):
The above accretion expense was included in depreciation, depletion and amortization in our combined consolidated statements of operations. The above liabilities incurred during the year ended December 31, 2016 were primarily additions to ARP’s asset retirement obligations due to the consolidation of some of ARP’s Drilling Partnerships which was also included in the deconsolidation of ARP amount.
NOTE 6-DEBT
Total debt consists of the following at the dates indicated (in thousands):
Cash Interest. Cash payments for interest were $55.8 million, $106.7 million and $68.5 million for the years ended December 31, 2016, 2014 and 2014, respectively.
Deferred financing costs and related amortization. Deferred financing costs related to other debt arrangements (non-revolving credit facility arrangements) are recorded at cost, amortized over the term of the respective debt agreements, and are presented net of accumulated amortization as a direct deduction from the associated debt obligation on our consolidated balance sheets. For the years ended December 31, 2016, 2015 and 2014, amortization expense of non-revolving credit facility deferred financing costs was $4.4 million, $10.6 million and $3.0 million, respectively, which was recorded within interest expense on our combined consolidated statements of operations.
Credit Agreements
First Lien Credit Agreement. On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower”) and Atlas Lightfoot, LLC, entered into a third amendment (the “Third Amendment”) to our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).
The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (defined below), with $35.0 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.3 million of the outstanding principal, which was classified as current portion of long-term debt on our combined consolidated balance sheet at December 31, 2015, and $0.5 million of interest. As a result of these transactions, we recognized $6.1 million as a loss on early extinguishment of debt, consisting of the $2.4 million prepayment penalty and $3.7 million of accelerated amortization of deferring financing costs, on our combined consolidated statement of operations for the year ended December 31, 2016. The Third Amendment amended the First Lien Credit Agreement to, among other things:
•
provide the ability for us and the Borrower to enter into the new Second Lien Credit Agreement (defined below);
•
shorten the maturity date of the First Lien Credit Agreement to September 30, 2017, subject to an optional extension to September 30, 2018 by the Borrower, assuming certain conditions are met, including a First Lien Leverage Ratio (as defined in the First Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee;
•
modify the applicable cash interest rate margin for ABR Loans and Eurodollar Loans to 0.50% and 1.50%, respectively, and add a pay-in-kind interest payment of 11% of the principal balance per annum;
•
allow the Borrower to make mandatory pre-payments under the First Lien Credit Agreement or the new Second Lien Credit Agreement, in its discretion, and add additional mandatory pre-payment events, including a monthly cash sweep for balances in excess of $4 million;
•
provide that the First Lien Credit Agreement may be prepaid without premium;
•
replace the existing financial covenants with (i) the requirement that we maintain a minimum of $2 million in EBITDA on a trailing twelve-month basis, beginning with the quarter ending June 30, 2016, and (ii) the incorporation into the First Lien Credit Agreement of the financial covenants included in Titan’s credit agreement, beginning with the quarter ending June 30, 2016;
•
prohibit the payment of cash distributions on our common and preferred units;
•
require the receipt of quarterly distributions from Atlas Growth Partners, GP, LLC and Lightfoot; and
•
add a cross-default provision for defaults by ARP.
On October 6, 2016, we entered into a fourth amendment to the First Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.
Second Lien Credit Agreement. Also on March 30, 2016, we and the Borrower entered into a new second lien credit agreement (the “Second Lien Credit Agreement”) with Riverstone and the Lenders. As described above, $35.8 million of the indebtedness previously outstanding under the First Lien Credit Agreement was moved under the Second Lien Credit Agreement. The Second Lien Credit Agreement also has an unamortized discount of $1.2 million as of December 31, 2016, related to the 4,668,044 warrants issued in connection with the Second Lien Credit Agreement (see Note 11).
The Second Lien Credit Agreement matures on March 30, 2019, subject to an optional extension (the “Extension Option”) to March 30, 2020, assuming certain conditions are met, including a Total Leverage Ratio (as defined in the Second Lien Credit Agreement) of not more than 6:00 to 1:00 and a 5% extension fee. Borrowings under the Second Lien Credit Agreement are secured on a second priority basis by security interests in the same collateral that secures borrowings under the First Lien Credit Agreement.
Borrowings under the Second Lien Credit Agreement bear interest at a rate of 30%, payable in-kind through an increase in the outstanding principal. If the First Lien Credit Agreement is repaid in full prior to March 30, 2018, the rate will be reduced to 20%. If the Extension Option is exercised, the rate will again be increased to 30%. If our market capitalization is greater than $75 million, we can issue common units in lieu of increasing the principal to satisfy the interest obligation.
The Borrower may prepay the borrowings under the Second Lien Credit Agreement without premium at any time. The Second Lien Credit Agreement includes the same mandatory prepayment events as the First Lien Credit Agreement, subject to the Borrower’s discretion to prepay either the First Lien Credit Agreement or the Second Lien Credit Agreement.
The Second Lien Credit Agreement contains the same negative and affirmative covenants and events of default as the First Lien Credit Agreement, including customary covenants that limit the Borrower’s ability to incur additional indebtedness, grant liens, make loans or investments, make distributions if a default exists or would result from the distribution, merge into or consolidate with other persons, enter into swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions. In addition, the Second Lien Credit Agreement requires that we maintain an Asset Coverage Ratio (as defined in the Second Lien Credit Agreement) of not less than 2.00 to 1.00 as of September 30, 2017 and each fiscal quarter ending thereafter.
In connection with the First Lien Credit Agreement and Second Lien Credit Agreement, the lenders thereunder continued their syndicated participation in the underlying loans consistent with the Term Loan Facilities (as defined below) and therefore certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and warrants and a foundation affiliated with a 5% or more unitholder participated in approximately 12% of the loan syndication.
As a result of the cross-default, on July 11, 2016, we entered into waiver agreements (the “Waivers”) with Riverstone and the Lenders in connection with the First Lien Credit Agreement and the Second Lien Credit Agreement. Pursuant to the Waivers, Riverstone and the Lenders agreed to waive under the First Lien Credit Agreement and the Second Lien Credit Agreement:
•
the cross-defaults relating to ARP’s default, for so long as the forbearing parties continue to forbear from exercising their rights and remedies; and
•
the potential default relating to ARP’s ongoing negotiations with its lenders and noteholders to the extent any resulting restructuring is completed prior to October 31, 2016
On October 6, 2016, we entered into a first amendment to the Second Lien Credit Agreement with Riverstone and the Lenders, effective as of September 1, 2016, that makes conforming changes to reflect the status of Titan as the successor to ARP following the consummation of the Chapter 11 Filings and also removes the financial covenants and related cross-defaults that had previously been incorporated from ARP’s credit agreement.
In addition to the $38 million of amounts outstanding under our First Lien Credit Agreement due on September 30, 2017, we classified the $44.6 million of amounts outstanding our Second Lien Credit Agreement as a current liability, based on the uncertainty regarding future covenant compliance. In total, we have $81.1 million of outstanding indebtedness under our credit agreements, which is net of $1.2 million of debt discounts and $0.2 million of deferred financing costs, as current portion of long term debt, net on our combined consolidated balance sheet as of December 31, 2016.
Term Loan Facilities
On February 27, 2015, we entered into a credit agreement with Deutsche Bank AG New York Branch, as administrative agent, and the lenders party thereto (the “Credit Agreement”). The Credit Agreement provided for a Secured Senior Interim Term Loan Facility in an aggregate principal amount of $30.0 million (the “Interim Term Loan Facility”) and a Secured Senior Term Loan A Facility in an aggregate principal amount of approximately $97.8 million (the “Term Loan A Facility” and together with the Interim Term Loan Facility, the “Term Loan Facilities”). In connection with the Term Loan Facilities, the lenders thereunder syndicated participations in loans underlying the facilities and certain of the Company’s current and former officers participated in approximately 12% of the loan syndication and a 5% or more unitholder participated in approximately 12% of the loan syndication.
The proceeds from the issuance of the Term Loan Facilities were used to fund a portion of our $150.0 million payment to Atlas Energy in connection with the repayment of Atlas Energy’s then existing term loan (see Note 2). In June 2015, we prepaid $33.1 million on the Term Loan Facilities in connection with the proceeds from the Arkoma Acquisition (see Note 3).
On August 10, 2015, we entered into the First Lien Credit Agreement with Riverstone Credit Partners, L.P., as administrative agent, New Atlas Holdings, LLC, and the lenders party thereto, for a new term loan facility (the “First Lien Term Loan Facility”) in an aggregate principal amount of $82.7 million maturing in August 2020. The borrowings under the First Lien Term Loan Facility were used to repay in full the remaining $82.7 million outstanding under the Term Loan Facilities. As a result of this transaction, we recognized $4.7 million as a loss on early extinguishment of debt, which consisted of $4.4 million of accelerated amortization of the Term Loan Facilities debt discount and $0.3 million of accelerated amortization of deferred financing costs, on our combined consolidated statement of operations for the year ended December 31, 2015. At December 31, 2015, the weighted average interest rate on outstanding borrowings under the First Lien Term Loan Facility was 8.0%.
ARP First Lien Credit Facility
ARP was party to a Second Amended and Restated Credit Agreement, dated as of July 31, 2013 by and among ARP, the lenders from time to time party thereto, and Wells Fargo Bank (“Wells Fargo”), National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP First Lien Credit Facility”), which provided for a senior secured revolving credit facility with a maximum borrowing base of $1.5 billion and was scheduled to mature in July 2018.
Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility. Accordingly, approximately $440 million remained outstanding under the ARP First Lien Credit Facility as of July 27, 2016, the date of ARP’s Chapter 11 Filings.
As of the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
ARP Second Lien Term Loan
ARP was party to a Second Lien Credit Agreement, dated as of February 23, 2015 by and among ARP, the lenders from time to time party thereto, and Wilmington Trust, National Association, as administrative agent, as amended, supplemented or modified from time to time (the “ARP Second Lien Term Loan”), which provided for a second lien term loan in an original principal amount of $250.0 million. The ARP Second Lien Term Loan was scheduled to mature on February 23, 2020.
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
ARP Senior Notes
In January and February 2016, ARP executed transactions to repurchase $20.3 million of its 7.75% Senior Notes and $12.1 million of its 9.25% Senior Notes for $5.5 million, which included $0.6 million of interest. As a result of these transactions, we recognized $26.5 million as gain on early extinguishment of debt, net of accelerated amortization of deferred financing costs of $0.9 million, in the consolidated statement of operations for the year ended December 31, 2016.
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
The aggregate amount of our debt maturities, excluding the effect of future paid in kind interest to be accrued in accordance with the terms of the First and Second Lien Credit Agreements, is as follows (in thousands):
Years Ended December 31:
$
82,555
-
-
-
-
Thereafter
-
Total principal maturities
82,555
Deferred financing costs and debt discounts, net of accumulated amortization
(1,455
)
Total debt
$
81,100
NOTE 7-DERIVATIVE INSTRUMENTS
We use a number of different derivative instruments, principally swaps and options, in connection with our commodity price risk management activities. We enter into financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, we receive or pay a fixed price and receive or remit a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, we occasionally enter into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to the New York Mercantile Stock Exchange (“NYMEX”), we receive or pay a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike, price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged.
On January 1, 2015, we discontinued the use of hedge accounting for our qualified commodity derivatives. As such, changes in fair value of these derivatives after December 31, 2014 were recognized immediately within gain (loss) on mark-to-market derivatives in our combined consolidated statements of operations. The fair values of these commodity derivative instruments at December 31, 2014, which were recognized in accumulated other comprehensive income within unitholders’ equity on our combined consolidated balance sheet, were being reclassified to our combined consolidated statements of operations at the time the originally hedged physical transactions settled.
We enter into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on our consolidated balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on our combined consolidated balance sheets as the initial value of the options. We recorded net derivative liabilities on our combined consolidated balance sheets of $0.6 million at December 31, 2016 and net derivative assets of $358.1 million at December 31, 2015.
Pursuant to the ARP Restructuring Support Agreement, ARP completed the sale of substantially all of its commodity hedge positions on July 25, 2016 and July 26, 2016 and used the proceeds to repay $233.5 million of borrowings outstanding under the ARP First Lien Credit Facility. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
The following table summarizes the commodity derivative activity and presentation in our combined consolidated statement of operations for the periods indicated (in thousands):
(1)
Recognized in gas and oil production revenue.
(2)
Excludes the effects of the $235.3 million, net of $8.2 million in ARP’s hedge monetization fees, paid directly to ARP’s First Lien Credit Facility lenders upon the sale of substantially all of ARP’s commodity hedge positions on July 25, 2016 and July 26, 2016.
(3)
Recognized in gain (loss) on mark-to-market derivatives.
During the year ended December 31, 2015, we received approximately $4.9 million in net proceeds from the early termination of our remaining natural gas and oil derivative positions for production periods from 2015 through 2018. The net proceeds from the early termination of these derivatives were used to reduce indebtedness under our Term Loan Facilities.
Atlas Growth Partners
On May 1, 2015, AGP entered into a secured credit facility agreement with a syndicate of banks. As of December 31, 2016, the lenders under the credit facility have no commitment to lend to AGP under the credit facility and AGP has a zero dollar borrowing base, but AGP and its subsidiaries have the ability to enter into derivative contracts to manage their exposure to commodity price movements which will benefit from the collateral securing the credit facility. Obligations under the credit facility are secured by mortgages on AGP’s oil and gas properties and first priority security interests in substantially all of its assets. The credit facility may be amended in the future if AGP and the lenders agree to increase the borrowing base and the lenders’ commitments thereunder. The secured credit facility agreement contains covenants that limit AGP and its subsidiaries ability to incur indebtedness, grant liens, make loans or investments, make distributions, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets. AGP was in compliance with these covenants as of December 31, 2016. In addition, AGP’s credit facility includes customary events of default, including failure to timely pay, breach of covenants, bankruptcy, cross-default with other material indebtedness (including obligations under swap agreements in excess of any agreed upon threshold amount), and change of control provisions.
The following table summarizes the gross fair values of AGP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our combined consolidated balance sheets as of the dates indicated (in thousands):
At December 31, 2016, AGP had the following commodity derivatives:
(1)
Volumes for crude oil are stated in barrels.
(2)
Fair value of crude oil fixed price swaps are based on forward West Texas Intermediate (“WTI”) crude oil prices, as applicable.
Atlas Resource Partners
The following table summarizes the gross fair values of ARP’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our combined consolidated balance sheets as of December 31, 2015 (in thousands):
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
Secured Hedge Facility
ARP had a secured hedge facility agreement with a syndicate of banks under which certain Drilling Partnerships had the ability to enter into derivative contracts to manage their exposure to commodity price movements. Under ARP’s revolving credit facility, ARP was required to utilize this secured hedge facility for future commodity risk management activity for its equity production volumes within the participating Drilling Partnerships. ARP, as the former general partner of the Drilling Partnerships, administers the commodity price risk management activity for the Drilling Partnerships under the secured hedge facility and guarantees their obligations under it. Before executing any hedge transaction, a participating Drilling Partnership is required to, among other things, provide mortgages on its oil and gas properties and first priority security interests in substantially all of its assets to the collateral agent for the benefit of the counterparties. The secured hedge facility agreement contains covenants that limit each of the participating Drilling Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions, including a sale of all or substantially all of its assets.
An event of default occurred under the secured hedging facility agreement upon ARP’s filing of voluntary petitions for relief under Chapter 11. The lenders under the secured hedge facility agreed to forbear from exercising remedies in respect of such event of default while the Chapter 11 Filings were pending and, upon occurrence of the effective date of the Plan contemplated by ARP’s Restructuring Support Agreement, such event of default was no longer be deemed to exist or to continue under the secured hedge facility.
NOTE 8-FAIR VALUE OF FINANCIAL INSTRUMENTS
We have established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources; whereas, unobservable inputs reflect our own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:
Level 1 - Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.
Level 3 - Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
We use a market approach fair value methodology to value the assets and liabilities for our outstanding derivative instruments (see Note 7). We manage and report derivative assets and liabilities on the basis of our exposure to market risks and credit risks by counterparty. Commodity derivative instruments are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. These derivative values were calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and pricing formula utilized in the derivative instrument.
Information for our financial instruments measured at fair value were as follows (in thousands):
Other Financial Instruments
We and our subsidiaries’ other current assets and liabilities on our combined consolidated balance sheets are considered to be financial instruments. The estimated fair values of these instruments approximate their carrying amounts due to their short-term nature and thus are categorized as Level 1. The estimated fair values of our debt at December 31, 2016 and 2015, was $82.6 million and $929.2 million, respectively, compared with the carrying amounts of $82.6 million and $1,614.7 million, respectively. The carrying value of our First Lien Credit Agreement, Second Lien Credit Agreement, and Term Loan Facilities bear interest at variable rates and approximated their estimated fair value at December 31, 2016 and 2015, respectively. The carrying values of outstanding borrowings under ARP’s First Lien Credit Facility bear interest at variable interest rates and approximated their estimated fair value at December 31, 2015. The estimated fair values of ARP’s Senior Notes and Second Lien Term Loan at December 31, 2015 were based upon the market approach and were calculated using the yields of the ARP senior notes and term loan facility as provided by financial institutions and thus were categorized as Level 3 values.
Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis
Acquisitions. We estimated the fair values of ARP’s natural gas and oil properties transferred to ARP upon consolidation of certain Drilling Partnerships (see Note 9) based on a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, ARP’s future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves, and estimated salvage values using ARP’s historical experience and external estimates of recovery values. We used a discount rate of 10%, which is consistent with ARP’s weighted average cost of capital at the time of the transaction. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.
We estimated the fair value of asset retirement obligations transferred to ARP upon consolidation of certain Drilling Partnerships (see Note 5) based on a discounted cash flow projections using ARP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future considering inflation rates, federal and state regulatory requirements, and ARP’s assumed credit-adjusted risk-free interest rate. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.
During the year ended December 31, 2014, ARP and AGP completed the Eagle Ford acquisition and ARP completed the Rangely and GeoMet acquisitions (see Note 3). The fair value measurements of assets acquired and liabilities assumed for these acquisitions were based on inputs that were not observable in the market and therefore represented Level 3 inputs. The fair values of natural gas and oil properties were measured using a discounted cash flow model, which considered the estimated remaining lives of the wells based on reserve estimates, future operating and development costs of the assets, as well as the respective natural gas, oil and
natural gas liquids forward price curves. The fair values of the asset retirement obligations were measured under our existing methodology for recognizing an estimated liability for the plugging and abandonment of our gas and oil wells (see Note 5). These inputs required significant judgments and estimates by our management at the time of the valuations, which were finalized in 2015.
Warrants. We estimated the fair value of the warrants associated the Second Lien Credit Agreement (see Note 9) using a Black-Scholes pricing model which was based on Level 3 inputs including a unit price on the date of issuance of $0.50, exercise price of $0.20, risk free rate of 1.8%, a term of 10 years, and estimated volatility rate of 57%. The volatility rate used was consistent with that of ARP and similar sized entities within the industry at the time of issuance. The estimated fair value per warrant was $0.40.
Equity Method Investments. We estimated the fair value of our equity method investment in ARP as of the date of the Chapter 11 Filings based on market data including ARP’s unit price and announcement of restructuring, which were Level 1 measurements as they were based on observable inputs. We estimated the fair value of our equity method investment in Titan at September 1, 2016 based on its estimated enterprise value and reorganizational value of assets and liabilities upon emergence from bankruptcy through fresh-start accounting utilizing the discounted cash flow method for both its gas and oil production business and its partnership management business based on the financial projections in ARP’s disclosure statement. The resulting fair value of Titan’s equity was used to value our equity method investment. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.
Asset Impairments. We estimated the fair value of our gas and oil properties in connection with reviewing these assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, using estimates, assumptions and judgments regarding such events or circumstances based on a discounted cash flow model, which considers the estimated remaining lives of the wells based on reserve estimates, our future operating and development costs of the assets, the respective natural gas, oil and natural gas liquids forward price curves and estimated salvage values using our historical experience and external estimates of recovery values. See Note 4 for disclosure of impairments of our gas and oil properties. These estimates of fair value are Level 3 measurements as they are based on unobservable inputs.
NOTE 9-CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Relationship with ARP. ARP did not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
Relationship with Titan. Other than its named executive officers, Titan does not directly employ any persons to manage or operate its business. These functions were provided by employees of us and/or our affiliates. On September 1, 2016, Titan entered into a Delegation of Management Agreement (the “Delegation Agreement”) with Titan Management, our wholly owned subsidiary. Pursuant to the Delegation Agreement, Titan has delegated to Titan Management all of Titan’s rights and powers to manage and control the business and affairs of Titan Energy Operating, LLC (“Titan Operating”), a wholly owned subsidiary of Titan. However, Titan’s board of directors retains management and control over certain non-delegated duties. In addition, Titan also entered into an Omnibus Agreement (the “Omnibus Agreement”) dated September 1, 2016 with Titan Management, Atlas Energy Resource Services, Inc. (“AERS”), our wholly owned subsidiary, and Titan Operating. Pursuant to the Omnibus Agreement, Titan Management and AERS will provide Titan and Titan Operating with certain financial, legal, accounting, tax advisory, financial advisory and engineering services (including cash management services) and Titan and Titan Operating will reimburse Titan Management and AERS for their direct and allocable indirect expenses incurred in connection with the provision of the services, subject to certain approval rights in favor of Titan’s Conflicts Committee. As of December 31, 2016, we had a $3.3 million payable to Titan related to the timing of funding cash accounts related to general and administrative expenses, such as payroll and benefits, which was recorded in advances from affiliates in our combined consolidated balance sheet.
Relationship with AGP. AGP does not directly employ any persons to manage or operate its business. These functions are provided by employees of us and/or our affiliates. Atlas Growth Partners, GP, LLC (“AGP GP”) receives an annual management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During the years ended December 31, 2016 and 2015, AGP paid $2.3 million and $1.8 million related to AGP GP for this management fee, respectively. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, to AGP by us based on the number of its employees who devoted substantially all of their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP will reimburse all necessary and reasonable costs allocated by the general partner. AGP was required to pay AGP GP an amount equal to any actual, out-of-pocket expenses related to its private placement offering and the formation and financing of AGP, including legal costs incurred by AGP GP, which payments were approximately 2% of the gross proceeds of its private placement offering.
Relationship with Drilling Partnerships. ARP conducted certain activities through, and a portion of its revenues are attributable to, sponsorship of the Drilling Partnerships. Through the Plan Effective Date, ARP served as the ultimate general partner and operator
of the Drilling Partnerships and assumed customary rights and obligations for the Drilling Partnerships. As the ultimate general partner, ARP was liable for the Drilling Partnerships’ liabilities and could have been liable to limited partners of the Drilling Partnerships if it breached its responsibilities with respect to the operations of the Drilling Partnerships. ARP was entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Drilling Partnership’s revenue and costs and expenses according to the respective partnership agreements.
In March 2016, ARP transferred $36.7 million of investor capital raised and $13.3 million of accrued well drilling and completion costs incurred by ARP to the Atlas Eagle Ford 2015 L.P. private drilling partnership for activities directly related to their program. In June 2016, ARP transferred $5.2 million of funds to certain of the Drilling Partnerships that were projected to make monthly or quarterly distributions to their limited partners over the next several months and/or quarter to ensure accessible distribution funding coverage in accordance with the respective Drilling Partnerships’ operations and partnership agreements in the event ARP experienced a prolonged restructuring period as ARP performed all administrative and management functions for the Drilling Partnerships. On July 26, 2016, ARP adopted certain amendments to the Drilling Partnerships’ partnership agreements, in accordance with ARP’s ability to amend the Drilling Partnerships’ partnership agreements to cure an ambiguity in or correct or supplement any provision of the Drilling Partnerships’ partnership agreements as may be inconsistent with any other provision, to provide that bankruptcy and insolvency events, such as the Chapter 11 Filings, with respect to the managing general partner would not cause the managing general partner to cease to serve as the managing general partner of the Drilling Partnerships nor cause the termination of the Drilling Partnerships.
Through the date of the Chapter 11 Filings, ARP had recorded $7.2 million and $12.4 million of gas and oil properties and asset retirement obligations, respectively, transferred to ARP as a result of certain Drilling Partnership consolidations. The gas and oil properties and asset retirement obligations were recorded at their fair values on the respective dates of the Drilling Partnerships’ consolidation and transfer to ARP (see Note 8) and resulted in a non-cash loss of $6.1 million, net of consolidation and transfer adjustments, for the year ended December 31, 2016, which was recorded in other income/(loss) in our combined consolidated statement of operations.
As of December 31, 2015, ARP had trade receivables of $6.6 million from certain of the Drilling Partnerships which were recorded in accounts receivable in the combined consolidated balance sheet. As of December 31, 2015, ARP had trade payables of $3.0 million to certain of the Drilling Partnerships, which were recorded in accounts payable in the combined consolidated balance sheet.
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2), which includes the direct relationship with the Drilling Partnerships and the above activities. As of the Plan Effective Date, Titan serves as the ultimate general partner and operator of the Drilling Partnerships and assumed customary rights and obligations for the Drilling Partnerships.
AGP’s Relationship with Titan. At our direction, AGP reimburses Titan for direct costs, such as salaries and wages, charged to AGP based on our employees who incurred time to activities on AGP’s behalf and indirect costs, such as rent and other general and administrative costs, allocated to AGP based on the number of our employees who devoted their time to activities on AGP’s behalf. In addition, Anthem Securities, Inc. (“Anthem”), a wholly owned subsidiary of Titan is currently acting as the dealer manager for AGP’s issuance and sale in a continuous offering of up to a maximum agreement amount of 100,000,000 common units representing limited partner interests in AGP as further described AGP’s registration statement on Form S-1. AGP will pay Anthem (1) compensation equal to 3.00% of the gross proceeds of the offering (Anthem may reallow up to 1.50% of gross offering proceeds it receives as dealer manager fees to participating broker-dealers, but expects to reallow 1.25% of gross offering proceeds to participating broker-dealers); (2) 7.00% and 3.00% of aggregate gross proceeds from the sale of Class A common units and Class T common units, respectively, as sales commissions; (3) with respect to Class T common units, a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. As disclosed in Note 2, AGP’s management decided to temporarily suspend its primary offering efforts.
As of December 31, 2016, AGP had a $0.8 million payable to Titan related to the direct costs, indirect cost allocation, and timing of funding of cash accounts, which was recorded in advances from affiliates in the combined consolidated balance sheet.
Other Relationships. We have other related party transactions with regard to our First Lien Credit Agreement, Second Lien Credit Agreement, and Term Loan Facilities (see Note 6), our Series A preferred units (Note 11) and our general partner and limited partner interest in Lightfoot (see Notes 1 and 2).
NOTE 10-COMMITMENTS AND CONTINGENCIES
General Commitments
We lease office space and equipment under leases with varying expiration dates. Our rental expense was $7.0 million, $16.2 million and $17.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016, we did not have any future rental commitments, firm transportation or gas gathering commitments, or commitments related to our drilling and completion and capital expenditures. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
ARP’s Drilling Partnership Commitments
ARP was the ultimate managing general partner of the Drilling Partnerships and had agreed to indemnify each investor partner from any liability that exceeded such partner’s share of Drilling Partnership assets. ARP had structured certain Drilling Partnerships to allow limited partners to have the right to present their interests for purchase. Generally, for Drilling Partnerships with this structure, ARP was not obligated to purchase more than 5% to 10% of the units in any calendar year, no units may be purchased during the first five years after closing for the Drilling Partnership, and ARP could immediately suspend the presentment structure for a Drilling Partnership by giving notice to the limited partners that it did not have adequate liquidity for redemptions. In accordance with the Drilling Partnership agreement, the purchase price for limited partner interests would generally be based upon a percentage of the present value of future cash flows allocable to the interest, discounted at 10%, as of the date of presentment, subject to estimated changes by ARP to reflect current well performance, commodity prices and production costs, among other items. Based on historical experience, as of the date of the Chapter 11 Filings, ARP’s estimated liability for such redemptions of limited partner interests in the Drilling Partnerships which allow such transactions was not material.
While its historical structure has varied, ARP had generally agreed to subordinate a portion of its share of Drilling Partnership gas and oil production revenue, net of corresponding production costs and up to a maximum of 50% of unhedged revenue, from certain Drilling Partnerships for the benefit of the limited partner investors until they had received specified returns, typically 10% to 12% per year determined on a cumulative basis, over a specified period, typically the first five to eight years, in accordance with the terms of the partnership agreements. Titan periodically compares the projected return on investment for limited partners in a Drilling Partnership during the subordination period, based upon historical and projected cumulative gas and oil production revenue and expenses, with the return on investment subject to subordination agreed upon within the Drilling Partnership agreement. If the projected return on investment fells below the agreed upon rate, ARP recognized subordination as an estimated reduction of its pro-rata share of gas and oil production revenue, net of corresponding production costs, during the current period in an amount that would achieve the agreed upon investment return, subject to the limitation of 50% of unhedged cumulative net production revenues over the subordination period. For Drilling Partnerships for which ARP had recognized subordination in a historical period, if projected investment returns subsequently reflected that the agreed upon limited partner investment return would be achieved during the subordination period, ARP would recognize an estimated increase in its portion of historical cumulative gas and oil net production, subject to a limitation of the cumulative subordination previously recognized. For the years ended December 31, 2016, 2015 and 2014, $0.8 million, $1.7 million and $5.3 million, respectively, of ARP’s gas and oil production revenues, net of corresponding production costs, from certain Drilling Partnerships were subordinated, which reduced gas and oil production revenues and expenses.
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2), which includes the direct relationship with the Drilling Partnerships and the above activities.
Subsequent to the Plan Effective Date, Titan is the ultimate managing general partner of the Drilling Partnerships and performs the above responsibilities and evaluations.
Environmental Matters
We are subject to various federal, state and local laws and regulations relating to the protection of the environment. We have established procedures for the ongoing evaluation of our and our subsidiaries’ operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. We maintain insurance which may cover in whole or in part certain environmental expenditures. We had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2016, 2015 and 2014.
Legal Proceedings
We are party to various routine legal proceedings arising out of the ordinary course of our business. We believe that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.
NOTE 11-ISSUANCES OF UNITS
We recognize gains or losses on ARP’s and AGP’s equity transactions as credits or debits, respectively, to unitholders’ equity on our combined consolidated balance sheets rather than as income or loss on our combined consolidated statements of operations. These gains or losses represent our portion of the excess or the shortage of the net offering price per unit of each of ARP’s and AGP’s common units as compared to the book carrying amount per unit.
In connection with the Second Lien Credit Agreement, on April 27, 2016, we issued to the Lenders, warrants (the “Warrants”) to purchase up to 4,668,044 common units representing limited partner interests at an exercise price of $0.20 per unit. The Warrants expire on March 30, 2026 and are subject to customary anti-dilution provisions. On April 27, 2016, we entered into a registration rights agreement pursuant to which we agreed to register the offer and resale of our common units underlying the Warrants as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement. The Warrants include a cashless exercise provision entitling the Lenders to surrender a portion of the underlying common units that has a value equal to the aggregate exercise price in lieu of paying cash upon exercise of a warrant. As a result of issuance of the Warrants, we recognized a $1.9 million debt discount on the Second Lien Credit Agreement, which will be amortized over the term of the debt, and a corresponding $1.9 million increase to unitholders’ equity - warrants on our combined balance sheet as of December 31, 2016.
On January 7, 2016, we were notified by the NYSE that we were not in compliance with NYSE’s continued listing criteria under Section 802.01C of the NYSE Listed Company Manual because the average closing price of our common units had been less than $1.00 for 30 consecutive trading days. We also were notified by the NYSE on December 23, 2015, that we were not in compliance with the NYSE’s continued listing criteria under Section 802.01B of the NYSE Listed Company Manual because our average market capitalization had been less than $50 million for 30 consecutive trading days and our stockholders’ equity had been less than $50 million. On March 18, 2016, we were notified by the NYSE that it determined to commence proceedings to delist our common units from the NYSE as a result of our failure to comply with the continued listing standard set forth in Section 802.01B of the NYSE Listed Company Manual to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15 million. The NYSE also suspended the trading of our common units at the close of trading on March 18, 2016. Our common units began trading on the OTCQX on March 21, 2016 under the ticker symbol: ATLS.
On August 26, 2015, at a special meeting of our unitholders, the unitholders approved changes to the terms of the Series A Preferred Units to provide that each Series A Preferred Unit will be convertible into common units at the option of the holder.
On February 27, 2015, we issued and sold an aggregate of 1.6 million of Series A convertible preferred units, with a liquidation preference of $25.00 per unit (the “Series A Preferred Units”), at a purchase price of $25.00 per unit to certain members of our management, two management members of the Board, and outside investors. Holders of the Series A Preferred Units are entitled to monthly distributions of cash at a rate equal to the greater of (i) 10% of the liquidation preference per annum, increasing to 12% per annum, 14% per annum and 16% per annum on the first, second and third anniversaries of the of the private placement, respectively, or (ii) the monthly equivalent of any cash distribution declared by us to holders of our common units, as well as Series A Preferred Units at a rate equal to 2% of the liquidation preference per annum. All or a portion of the Series A Preferred Units were convertible into our units at the option of the holder at any time following the later of (i) the one-year anniversary of the distribution and (ii) prior to August 26, 2015, receipt of unitholder approval. The conversion price will be equal to the greater of (i) $8.00 per common unit; and (ii) the lower of (a) 110.0% of the volume weighted average price for our common units over the 30 trading days following the distribution date; and (b) $16.00 per common unit. We sold the Series A Preferred Units in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act. The Series A Preferred Units resulted in proceeds to us of $40.0 million. We used the proceeds to fund a portion of the $150.0 million payment by us to Atlas Energy related to the repayment of Atlas Energy’s term loan (see Note 2). The Series A Purchase Agreement contains customary terms for private placements, including representations, warranties, covenants and indemnities.
Atlas Resource Partners
On July 12, 2016, ARP received notification from the New York Stock Exchange that the NYSE commenced proceedings to delist ARP’s common units as a result of ARP’s failure to comply with the continued listed standards set forth in Section 802.01C of the NYSE Listed Company Manual to maintain an average closing price of $1.00 per unit over a consecutive 30 day period. The Class D ARP Preferred Units and Class E ARP Preferred Units were also delisted from the NYSE. ARP’s common units, Class D ARP Preferred Units, and Class E ARP Preferred Units began trading on the OTCQX market on July 13, 2016 with the ticker symbol “ARPJ” for ARP’s common units, “ARPJP” for Class D ARP Preferred Units, and “ARPJN” for Class E ARP Preferred Units.
ARP had an equity distribution agreement with Deutsche Bank Securities Inc., as representative of the several banks named therein (the “Agents”). Pursuant to the equity distribution agreement, ARP sold from time to time through the Agents common units representing limited partner interests of ARP having an aggregate offering price of up to $100.0 million. Sales of common units, if any, were made in negotiated transactions or transactions that are deemed to be “at-the-market” offerings as defined in Rule 415 of the Securities Act, including sales made directly on the New York Stock Exchange, the former trading market for the common units, or sales made to or through a market maker other than on an exchange or through an electronic communications network. ARP paid each of the Agents a commission, which in each case was not be more than 2.0% of the gross sales price of common units sold through such Agent. Under the terms of the equity distribution agreement, ARP sold common units from time to time to any Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to an Agent as principal was pursuant to the terms of a separate agreement between ARP and such Agent. During the year ended December 31, 2016, ARP issued 245,175 common limited partner units under the equity distribution program for net proceeds of $0.2 million, net of $4,000 in commissions and offering expenses paid. During the year ended December 31, 2015, ARP issued 9,803,451 common limited partner units under the equity distribution agreement for net proceeds of $44.2 million, net of $1.1 million in commissions and offering expenses paid.
In August 2015, ARP entered into a distribution agreement with MLV & Co. LLC (“MLV”) which ARP terminated and replaced in November 2015, when ARP entered into a distribution agreement with MLV and FBR Capital Markets & Co. pursuant to which ARP sold its 8.625% Class D Cumulative Redeemable Perpetual Preferred Units (“Class D ARP Preferred Units”) and 10.75% Class E Cumulative Redeemable Perpetual Preferred Units (“Class E ARP Preferred Units”). ARP did not issue any Class D Preferred Units nor Class E Preferred Units under the August 2015 and November 2015 preferred equity distribution programs for the period ended July 27, 2016. During the year ended December 31, 2015, ARP issued 90,328 Class D ARP Preferred Units and 1,083 Class E ARP Preferred Units under its preferred equity distribution program for net proceeds of $0.9 million, net of $0.3 million in commissions and offering expenses paid. Under the November 2015 ATM Agreement, our Predecessor did not issue any Class D Preferred Units nor Class E Preferred Units under the preferred equity distribution program, but incurred $0.1 million of net offering expenses.
In May 2015, in connection with the Arkoma Acquisition, ARP issued 6,500,000 of its common limited partner units in a public offering at a price of $7.97 per unit, yielding net proceeds of $49.7 million (see Note 3). ARP used a portion of the net proceeds to fund the Arkoma Acquisition and to reduce borrowings outstanding under ARP’s First Lien Credit Facility.
In April 2015, ARP issued 255,000 of its 10.75% Class E ARP Preferred Units at a public offering price of $25.00 per unit for net proceeds of $6.0 million.
In October 2014, ARP issued 3,200,000 8.625% Class D ARP Preferred Units at a public offering price of $25.00 per Class D ARP Preferred Unit, yielding net proceeds of approximately $77.3 million from the offering, after deducting underwriting discounts and estimated offering expenses. ARP used the net proceeds from the offering to fund a portion of the Eagle Ford Acquisition (see Note 3). On March 31, 2015, to partially pay its portion of the quarterly installment related to the Eagle Ford Acquisition, ARP issued an additional 800,000 Class D ARP Preferred Units to the seller at a value of $25.00 per unit. On January 15, 2015, ARP paid an initial quarterly distribution of $0.616927 per unit for the extended period from October 2, 2014 through January 14, 2015 to holders of record as of January 2, 2015 (see Note 12). ARP paid distributions on a quarterly basis, at an annual rate of $2.15625 per unit, or 8.625% of the $25.00 liquidation preference.
The Class D and Class E ARP Preferred Units ranked senior to ARP’s common units and Class C ARP Preferred Units with respect to the payment of distributions and distributions upon a liquidation event.
In May 2014, in connection with the Rangely Acquisition (see Note 3), ARP issued 15,525,000 of its common limited partner units (including 2,025,000 units pursuant to an over-allotment option) in a public offering at a price of $19.90 per unit, yielding net proceeds of approximately $297.3 million.
In March 2014, in connection with the GeoMet Acquisition (see Note 3), ARP issued 6,325,000 of its common limited partner units (including 825,000 units pursuant to an over-allotment option) in a public offering at a price of $21.18 per unit, yielding net proceeds of approximately $129.0 million.
Atlas Growth Partners
On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets.
On April 5, 2016, we announced that AGP’s registration statement on Form S-1 (Registration Number: 333-207537) was declared effective by the SEC. On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts in light
of new regulations and the challenging fund raising environment until such time as market participants have had an opportunity to ascertain the impact of such issues.
As a result of AGP’s decision to temporarily suspend its current primary offering efforts (see Note 2), AGP reclassified $5.3 million of offering costs to other loss on our consolidated statement of operations for the year ended December 31, 2016. These offering costs were previously capitalized within noncontrolling interest on our consolidated balance sheet as an offset to any proceeds raised in AGP’s current primary offering and include $1.5 million that were previously capitalized within noncontrolling interest on our consolidated balance sheet as of December 31, 2015.
Under the terms of AGP’s initial offering, AGP offered in a private placement $500.0 million of its common limited partner units. The termination date of the private placement offering was December 31, 2014, subject to two 90 day extensions to the extent that it had not sold $500.0 million of common units at any extension date. AGP exercised each of such extensions. Under the terms of the offering, an investor received, for no additional consideration, warrants to purchase additional common units in an amount equal to 10% of the common units purchased by such investor. The warrants are exercisable at a price of $10.00 per common unit being purchased and may be exercised from and after the warrant date (generally, the date upon which AGP gives the holder notice of a liquidity event) until the expiration date (generally, the date that is one day prior to the liquidity event or, if the liquidity event is a listing on a national securities exchange, 30 days after the liquidity event occurs). Under the warrant, a liquidity event is defined as either (i) a listing of the common units on a national securities exchange, (ii) a business combination with or into an existing publicly-traded entity, or (iii) a sale of all or substantially all of AGP’s assets.
Through the completion of AGP’s private placement offering on June 30, 2015, AGP issued $233.0 million, or 23,300,410 of its common limited partner units, in exchange for proceeds to AGP, net of dealer manager fees and commissions and expenses, of $203.4 million. We purchased 500,010 common units for $5.0 million during the offering. In connection with the issuance of common limited partner units, unitholders received 2,330,041 warrants to purchase AGP’s common units at an exercise price of $10.00 per unit.
During the year ended December 31, 2015, AGP sold an aggregate of 12,623,500 of its common limited partner units at a gross offering price of $10.00 per unit. Of such amount, we purchased $2.7 million, or 300,000 common units, during the year ended December 31, 2015. In connection with the issuance of its common limited partner units, unitholders received 1,262,350 warrants to purchase its common limited partner units at an exercise price of $10.00 per unit.
During the year ended December 31, 2014, AGP sold an aggregate of 9,581,900 of its common limited partner units at a gross offering price of $10.00 per unit, resulting in proceeds of $81.6 million to AGP, net of dealer manager fees and commissions and expenses of $14.0 million. We did not purchase common units during the year ended December 31, 2014. In connection with the issuance of common limited partner units in 2014, unitholders received 958,190 warrants to purchase AGP’s common limited partner units at an exercise price of $10.00 per unit.
In connection with the issuance of ARP’s unit offerings during the year ended December 31, 2016, we recorded gains of $0.2 million within unitholders’ equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheet and combined consolidated statement of unitholders’ equity. In connection with the issuance of ARP’s and AGP’s unit offerings for the year ended December 31, 2015, we recorded gains of $4.3 million within equity and a corresponding decrease in non-controlling interests on our combined consolidated balance sheets and combined consolidated statement of unitholders’ equity.
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
NOTE 12-CASH DISTRIBUTIONS
Our Cash Distributions. We have a cash distribution policy under which we distribute, within 50 days following the end of each calendar quarter, all of our available cash (as defined in our LLC Agreement) for that quarter to our unitholders. As a result of the First Lien Credit Agreement and Second Lien Credit Agreement entered into on March 30, 2016 (see Note 6), we are prohibited from paying future cash distributions on our common and preferred units.
During the year ended December 31, 2016, we paid a distribution of $1.0 million to Class A preferred unitholders. During the year ended December 31, 2015, we paid a distribution of $2.7 million to Class A preferred unitholders.
ARP Cash Distributions. ARP had a monthly cash distribution program whereby ARP distributed all of its available cash (as defined in the partnership agreement) for that month to its unitholders within 45 days from the month end. If ARP’s common unit distributions in any quarter exceeded specified target levels, we received between 13% and 48% of such distributions in excess of the specified target levels.
While outstanding, the Class B ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.40 (or $0.1333 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. In July 2015, the remaining 39,654 Class B Preferred Units were converted into ARP common limited partner units.
The Class C ARP Preferred Units received regular quarterly cash distributions equal to the greater of (i) $0.51 (or $0.17 per unit paid on a monthly basis) and (ii) the quarterly common unit distribution. On May 5, 2016, ARP’s Board of Directors elected to suspend ARP’s common unit and Class C preferred distributions, beginning with the month of March of 2016, due to the continued lower commodity price environment.
ARP paid quarterly distributions on its Class D ARP Preferred Units at an annual rate of $2.15625 per unit, $0.5390625 per unit paid on a quarterly basis, or 8.625% of the $25.00 liquidation preference. ARP paid quarterly distributions on its Class E ARP Preferred Units at an annual rate of $2.6875 per unit, or $0.671875 per unit on a quarterly basis, or 10.75% of the $25.00 liquidation preference. On June 16, 2016, ARP’s Board of Directors elected to suspend the distributions on the Class D ARP Preferred Units and the Class E ARP Preferred Units, beginning with the second quarter 2016 distribution, due to the continued lower commodity price environment. The Class D ARP Preferred Units and Class E ARP Preferred Units accrued distributions of $3.4 million and $0.3 million, respectively, from April 15, 2016 through August 31, 2016. However, due to the distribution suspension and ARP’s Chapter 11 Filings, these amounts were not earned as the preferred units were cancelled without receipt of any consideration on the Plan Effective Date.
During the year ended December 31, 2016, ARP paid four monthly cash distributions totaling $5.1 million to common limited partners ($0.0125 per unit per month); $2.5 million to Preferred Class C limited partners ($0.0125 per unit per month); and $0.2 million to the General Partner Class A holder ($0.0125 per unit per month). During the year ended December 31, 2015, ARP paid twelve monthly cash distributions totaling $126.3 million to common limited partners ($0.1966 per unit in both January and February 2015, $0.1083 per unit in March through November 2015 and $0.0125 per unit in December 2015); $7.8 million to Preferred Class C limited partners ($0.1966 per unit in both January and February 2015 and $0.17 per unit in March through December 2015); approximately $42,000 to Preferred Class B limited partners ($0.1966 per unit in both January and February 2015 and $0.1333 per unit in March through July 2015); and $4.8 million to the General Partner Class A holder ($0.1966 per unit in both January and February 2015, $0.1083 per unit in March through November 2015 and $0.0125 per unit in December 2015). During the year ended December 31, 2014, ARP paid one quarterly and ten monthly cash distributions totaling $184.3 million to its common limited partners, $9.5 million to its Preferred Class C limited partners, $9.7 million to its Preferred Class B limited partners and $4.8 million to its General Partner Class A holder. The amount per unit paid for all 2014 distributions was $0.58 for the quarterly distribution paid in February 2014, $0.1933 per unit for monthly distributions in March through July 2014 and $0.1966 per unit for monthly distributions in August through December 2014.
During the year ended December 31, 2016, ARP paid two distributions totaling $4.4 million to Class D Preferred Units ($0.5390625 per unit) for the period October 15, 2015 through April 14, 2016. During the year ended December 31, 2015, ARP paid three distributions totaling $8.5 million to Class D Preferred Units ($0.6169270 per unit for the period October 2, 2014 through January 14, 2015 and $0.539063 per unit for the period January 15, 2015 through October 14, 2015).
During the year ended December 31, 2016, ARP paid two distributions totaling $0.3 million to Class E Preferred Units ($0.671875 per unit) for the period October 15, 2015 through April 14, 2016. During the year ended December 31, 2015, ARP paid two $0.3 million distribution to Class E Preferred Units ($0.6793 per unit) for the period April 14, 2015 through October 14, 2015.
On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
AGP Cash Distributions. AGP has a cash distribution policy under which it distributes to holders of common units and Class A units on a quarterly basis a distribution of $0.175 per unit, or $0.70 per unit per year, to the extent AGP has sufficient available cash after establishing appropriate reserves and paying fees and expenses, including reimbursements of expenses to the general partner and its affiliates. Distributions are generally paid within 45 days of the end of the quarter to unitholders of record on the applicable record date. Unitholders are entitled to receive distributions from AGP beginning with the quarter following the quarter in which AGP first admits them as limited partners. On November 2, 2016, AGP’s Board of Directors determined to suspend its quarterly common unit distributions, beginning with the three months ended September 30, 2016, in order to retain its cash flow and reinvest in its business and assets.
During the year ended December 31, 2016, AGP paid a distribution of $12.2 million to common limited partners ($0.1750 per unit per quarter for the distributions paid from January 1, 2016 through June 30, 2016) and $0.3 million to the general partner’s Class A units ($0.1750 per unit per quarter for the distributions paid from January 1, 2016 through June 30, 2016). During the year ended December 31, 2015, AGP paid a distribution of $10.5 million to common limited partners ($0.1750 per unit per quarter) and $0.2 million to the general partner’s Class A units ($0.1750 per unit per quarter). During the year ended December 31, 2014, AGP paid
distributions of $1.5 million to common limited partners ($0.1750 per unit per quarter for the distributions paid from April 1, 2014 through December 31, 2014 and $0.1167 per unit per quarter for the distributions paid from January 1, 2014 through March 31, 2014) and approximately $31,000 to the general partner’s Class A units ($0.1750 per unit per quarter for the distributions paid from April 1, 2014 through December 31, 2014 and $0.1167 per unit per quarter for the distributions paid from January 1, 2014 through March 31, 2014).
NOTE 13- SHARE BASED COMPENSATION PLANS
2015 Long-Term Incentive Plan
Our Board of Directors approved and adopted the 2015 Long-Term Incentive Plan (“2015 LTIP”) effective February 2015. The 2015 LTIP provides equity incentive awards to our officers, employees and managing board members and our affiliates, consultants and joint-venture partners (collectively, the “Participants”) who perform services for us. The 2015 LTIP is administered by a committee consisting of the Board of Directors or committee of the Board of Directors or board of an affiliate appointed by the Board of Directors (the “LTIP Committee”). Under the 2015 LTIP, the LTIP Committee may grant awards of phantom units, restricted units or unit options for an aggregate of 5,250,000 units. At December 31, 2016, we had 3,995,214 phantom units and unit options outstanding under the 2015 LTIP, with 1,220,960 phantom units and unit options available for grant. Share based payments to non-employee directors, which have a cash settlement option, are recognized within liabilities in the consolidated financial statements based upon their current fair market value.
In the case of awards held by eligible employees, following a “change in control”, as defined in the 2015 LTIP, upon the eligible employee’s termination of employment without “cause”, as defined in the 2015 LTIP, or upon any other type of termination specified in the eligible employee’s applicable award agreement(s), any unvested award will immediately vest in full and, in the case of options, become exercisable for the one-year period following the date of termination of employment, but in any case not later than the end of the original term of the option. Upon a change in control, all unvested awards held by directors will immediately vest in full.
In connection with a change in control, the LTIP Committee, in its sole and absolute discretion and without obtaining the approval or consent of the unitholders or any Participant, subject to the terms of any award agreements and employment agreements to which we (or any affiliate) and any Participant are party, may take one or more of the following actions (with discretion to differentiate between individual Participants and awards for any reason):
•
cause awards to be assumed or substituted by the surviving entity (or a parent, subsidiary or affiliate of such surviving entity);
•
accelerate the vesting of awards as of immediately prior to the consummation of the transaction that constitutes the change in control so that awards shall vest (and, with respect to options, become exercisable) as to the units that otherwise would have been unvested so that Participants (as holders of awards granted under the new equity plan) may participate in the transaction;
•
provide for the payment of cash or other consideration to Participants in exchange for the cancellation of outstanding awards (in an amount equal to the fair market value of such cancelled awards);
•
terminate all or some awards upon the consummation of the change-in-control transaction, but only if the LTIP Committee provides for full vesting of awards immediately prior to the consummation of such transaction; and
•
make such other modifications, adjustments or amendments to outstanding awards as the LTIP Committee deems necessary or appropriate.
2015 Phantom Units. A phantom unit entitles a Participant to receive a common unit or its then-fair market value in cash or other securities or property, upon vesting of the phantom unit. In tandem with phantom unit grants, the LTIP Committee may grant Distribution Equivalent Rights (“DERs”), which are the right to receive cash, securities, or property per phantom unit in an amount equal to, and at the same time as, the cash distributions or other distributions of securities or property we make on a common unit during the period such phantom unit is outstanding. Of the phantom units outstanding under the 2015 LTIP at December 31, 2016, there were 2,160,342 units that will vest within the following twelve months. The director phantom units outstanding under the 2015 LTIP at December 31, 2016 include DERs. No amounts were paid during the years ended December 31, 2016, 2015, and 2014 with respect to DERs.
On February 20, 2017, our Board of Directors authorized the deferral until March 1, 2018 of the vesting of all phantom units granted to officers and employees under the 2015 LTIP that had previously been scheduled to vest during 2017. As consideration for the deferral, we made a deferred vesting payment to all employees (including the officers) equal to approximately 25% of the value of affected phantom units.
On May 12, 2016, due to the income tax ramifications of potential options we were considering, the Board of Directors delayed the vesting of approximately 911,900 units granted, under our long-term incentive plan, to employees, directors and officers, until March 2017. The phantom units were set to vest between June 8, 2016 and September 1, 2016. The delayed vesting schedule did not have a significant impact on the compensation expense recorded in general and administrative expenses on our combined consolidated statement of operations for the year ended December 31, 2016 or our remaining unrecognized compensation expense related to such awards.
The following table sets forth the 2015 LTIP phantom unit activity for the periods indicated:
(1)
The intrinsic value of phantom awards vested during the year ended December 31, 2016 was approximately $31,000. No phantom unit awards vested during the years ended December 31, 2015 and 2014.
(2)
The aggregate intrinsic value of phantom unit awards outstanding at December 31, 2016 was approximately $2.9 million.
(3)
There was $0.4 million recognized as liabilities on our consolidated balance sheet at December 31, 2016 representing 351,684 units, due to the option of the Participants to settle in cash instead of units. The respective weighted average grant date fair value for these units was $2.01 at December 31, 2016.
At December 31, 2016, we had approximately $5.3 million of unrecognized compensation expense related to unvested phantom units outstanding under the 2015 LTIP based upon the fair value of the awards which is expected to be recognized over a weighted average period of 1.4 years.
2015 Unit Options. A unit option entitles a Participant to receive our common unit upon payment of the exercise price for the option after completion of vesting of the unit option. The exercise price of the unit option shall not be less than the fair market value of our common unit on the date of grant of the option. The LTIP Committee also determines how the exercise price may be paid by the Participant. The LTIP Committee will determine the vesting and exercise period for unit options. Unit option awards expire 10 years from the date of grant. Generally, unit options to be granted under the 2015 LTIP will vest over a designated period of time. There are no unit options outstanding under the 2015 LTIP at December 31, 2016. No cash was received from the exercise of options for the years ended December 31, 2016, 2015 and 2014.
Restricted Units
Restricted units are actual common units issued to a Participant that are subject to vesting restrictions and evidenced in such manner as the LTIP Committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the LTIP Committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. A holder of restricted units will have certain rights of holders of common units in general, including the right to vote the restricted units. However, during the period in which the restricted units are subject to vesting restrictions, the holder will not be permitted to sell, assign, transfer, pledge or otherwise encumber the restricted units. There were no restricted units granted, issued or outstanding through December 31, 2016.
ARP’s 2012 Long-Term Incentive Plan
ARP’s 2012 Long-Term Incentive Plan (“2012 ARP LTIP”), effective March 2012, provided incentive awards to officers, employees and directors and employees of ARP’s general partner and its affiliates, consultants and joint venture partners (collectively,
the “ARP Participants”), who performed services for ARP. The 2012 ARP LTIP was administered by the board of ARP’s general partner, a committee of the board or the board (or committee of the board) of an affiliate (the “ARP LTIP Committee”). Under the 2012 ARP LTIP, the ARP LTIP Committee granted awards of phantom units, restricted units or unit options.
ARP’s 2012 ARP LTIP Phantom Units
Phantom units represented rights to receive a common unit, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property upon vesting. Phantom units were subject to terms and conditions determined by the ARP LTIP Committee, which included vesting restrictions. In tandem with phantom unit grants, the ARP LTIP Committee granted DERs, which were the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by ARP with respect to a common unit during the period that the underlying phantom unit was outstanding. During the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings and the years ended December 31, 2015 and 2014, ARP paid approximately $15,000, $0.7 million and $2.0 million, respectively, with respect to the 2012 ARP LTIP’s DERs. These amounts were recorded as reductions of the non-controlling interest portion of equity on our combined consolidated balance sheets.
For the year ended December 31, 2014, the 2012 ARP LTIP phantom unit activity was as follows: Outstanding beginning of year: 839,808; Granted: 264,173; Vested: 274,414; Forfeited: 30,375; Outstanding end of year: 799,192. For the year ended December 31, 2015, the 2012 ARP LTIP phantom unit activity was as follows: Outstanding beginning of year: 799,192; Granted: 9,730; Vested: 472,278; Forfeited: 34,539; Outstanding end of year: 302,105. For the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings, the 2012 ARP LTIP phantom unit activity was as follows: Outstanding beginning of period: 302,105; Granted: 30,000; Vested: 24,679; Forfeited: 60,639; Outstanding end of period: 246,787. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
During the years ended December 31, 2016, 2015 and 2014, we recognized 2012 ARP LTIP unit based compensation expense for phantom units of $0.3 million, $4.1 million and $6.4 million, respectively, which was recorded in general and administrative expenses on our combined consolidated statements of operations.
ARP’s 2012 ARP LTIP Unit Options
A unit option was the right to purchase ARP’s common unit in the future at a predetermined price (the exercise price). The exercise price of each option was determined by the ARP LTIP Committee and may be equal to or greater than the fair market value of a common unit on the date the option was granted. The ARP LTIP Committee determined the vesting and exercise restrictions applicable to an award of options, if any, and the method by which the exercise price may be paid by the ARP Participant. Unit option awards expired 10 years from the date of grant.
For the year ended December 31, 2014, the 2012 ARP LTIP unit option activity was as follows: Outstanding beginning of year: 1,482,675; Granted: none; Exercised: none; Forfeited: 24,375; Outstanding end of year: 1,458,300. For the year ended December 31, 2015, the 2012 ARP LTIP unit option activity was as follows: Outstanding beginning of year: 1,458,300; Granted: none; Exercised: none; Forfeited: 103,775; Outstanding end of year: 1,354,525. For the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings, the 2012 ARP LTIP unit option activity was as follows: Outstanding beginning of period: 1,354,525; Granted: none; Exercised: none; Forfeited: 40,689; Outstanding end of period: 1,313,836. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2).
During the years ended December 31, 2016, 2015 and 2014, we recognized 2012 ARP LTIP unit based compensation expense for unit options of approximately $31,000, $0.8 million and $1.7 million, respectively, which was recorded in general and administrative expenses on our combined consolidated statements of operations.
ARP’s 2012 ARP LTIP Restricted Units
Restricted units were actual common units to be issued to an ARP Participant that were subject to vesting restrictions and evidenced in such manner as the ARP LTIP Committee deemed appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the ARP LTIP Committee would condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals or both. During the period from January 1, 2016 through the date of ARP’s Chapter 11 Filings and the years ended December 31, 2015 and 2014, ARP had no restricted units granted or outstanding. On the date of the Chapter 11 Filings, we deconsolidated ARP for financial reporting purposes (see Note 2)
NOTE 14-OPERATING SEGMENT INFORMATION
Our operations included three reportable operating segments: ARP (through the date of the Chapter 11 Filings), AGP, and corporate and other. These operating segments reflected the way we managed our operations and made business decisions. Corporate and other includes our equity investments in Lightfoot (see Note 2) and Titan (see Note 2), as well as our general and administrative and interest expenses. Operating segment data for the periods indicated were as follows (in thousands):
NOTE 15-SUBSEQUENT EVENTS
Long-Term Incentive Plan Vesting Delay. On February 20, 2017, our Board of Directors authorized the deferral until March 1, 2018 of the vesting of all phantom units granted to officers and employees under the 2015 LTIP that had previously been scheduled to vest during 2017 (see Note 13).
NOTE 16-SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil, Gas and NGL Reserve Information. The preparation of our natural gas, oil and NGL reserve estimates was completed in accordance with our prescribed internal control procedures by our reserve engineers. Other than for ARP’s Rangely assets, for the periods presented, Wright and Company, Inc., an independent third-party reserve engineer, was retained to prepare a report of proved reserves. The reserve information includes natural gas, oil and NGL reserves which are all located throughout the United States. The independent reserves engineer’s evaluation was based on more than 40 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. For ARP’s Rangely assets, Cawley, Gillespie, and Associates, Inc. was retained to prepare a report of proved reserves. The independent reserves engineer’s evaluation was based on more than 34 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions and government regulations. Our internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our Director of Reservoir Engineering, who is a member of the Society of Petroleum Engineers and has more than 18 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our senior engineering staff and management, with final approval by our President.
The reserve disclosures that follow reflect our estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of royalty interests, of natural gas, crude oil and NGLs owned at year end and changes in proved reserves during the last three years. Proved oil, gas and NGL reserves are those quantities of oil, gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are those reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for undeveloped reserves cannot be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. The proved reserves quantities and future net cash flows were estimated using an unweighted 12-month average pricing based on the prices on the first day of each month during the years ended December 31, 2016, 2015 and 2014, including adjustments related to regional price differentials and energy content.
There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of our oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors, for their effects have not been proved.
Reserve quantity information and a reconciliation of changes in our proved reserve quantities are as follows:
(1)
For the year ended December 31, 2015, the increase represents PUD additions related to our development and leasing activity in the Eagle Ford Shale. For the year ended December 31, 2014, the increase was primarily due to the addition of Marble Falls wells.
(2)
Represents the purchase of proved reserves due to ARP’s Rangely, ARP’s and AGP’s Eagle Ford and ARP’s GeoMet Acquisitions for the year ended December 31, 2014.
(3)
See “Revisions of Previous Estimates” section below for additional discussion and analysis of significant components of revisions of previous estimates.
(4)
For the year ended December 31, 2016, the decrease was due to the deconsolidation of ARP for financial reporting purposes in connection with ARP’s Chapter 11 Filings (see Note 2).
Revisions of Previous Estimates
The following represents the unweighted average of the first-day-of-the-month prices for each of the previous twelve months from the periods presented above:
For the year ended December 31, 2016 we had negative revisions of 58,818 MMcfe due to decreases in pricing and 60,860 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, partially offset by positive revision of 10,133 MMcfe due to our production outperforming the comparable period’s forecast.
For the year ended December 31, 2015, we had negative revisions of 258,667 MMcfe due to decreases in pricing, 223,551 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing and 46,804 MMcfe due to production underperforming previous year’s forecast.
For the year ended December 31, 2014, we had negative revisions of 145,235 MMcfe due to the removal of proved undeveloped properties that became uneconomic due to pricing, partially offset by positive revisions of 59,690 MMcfe due to our production outperforming the comparable period’s forecast and 47,525 MMcfe due to increases in pricing.
Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to oil and gas producing activities as of the periods indicated were as follows (in thousands):
(1)
As of December 31, 2016, we classified $63.3 million of AGP’s natural gas and oil properties as unproved properties due to challenges in capital fundraising.
Results of Operations from Oil and Gas Producing Activities. The results of operations related to our oil and gas producing activities during the periods indicated were as follows (in thousands):
(1)
For the year ended December 31, 2016, we recognized $25.4 million and $16.5 million of asset impairment related to AGP’s proved and unproved oil and gas properties in the Eagle Ford operating area, respectively, which were impaired due to lower forecasted commodity prices and timing of capital financing and deployment for the development of our undeveloped properties. During the year ended December 31, 2015, we recognized $974 million of asset impairment of which $960 million related to ARP’s proved oil and gas properties in the Barnett, Coal-bed Methane, Rangely, Southern Appalachia, Marcellus and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices, net of $85.8 million of future
hedge gains reclassified from accumulated other comprehensive income, $6.6 million of asset impairments in ARP’s unproved gas and oil properties primarily related to ARP’s unproved acreage in the New Albany Shale, which was impaired due to expiring acreage and no intention to pursue development, and $7.4 million related to AGP’s proved oil and gas properties in the Marble Falls and Mississippi Lime operating areas, which were impaired due to lower forecasted commodity prices. For the year ended December 31, 2014, we recognized $580.7 million of asset impairment of which $555.7 related to ARP’s proved oil and gas properties in Appalachian and Mid-Continent operations, which were impaired due to lower forecasted commodity prices, net of $82.3 million of future hedge gains reclassified from accumulated other comprehensive income, $6.9 million related to AGP’s proved oil and gas properties in the Marble Falls operating area, which was impaired due to lower forecasted commodity prices, and $18.1 million goodwill impairment resulting from the decline in overall commodity prices.
Costs Incurred in Oil and Gas Producing Activities. The costs incurred in our oil and gas activities during the periods indicated are as follows (in thousands):
(1)
There were no exploratory wells drilled during the periods presented.
Standardized Measure of Discounted Future Cash Flows. The following schedule presents the standardized measure of estimated discounted future net cash flows relating to our proved oil and gas reserves. The estimated future production was priced at a twelve-month average for the years ended December 31, 2016, 2015 and 2014, adjusted only for regional price differentials and energy content. The resulting estimated future cash inflows were reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels and include the effect on cash flows of settlement of asset retirement obligations on gas and oil properties. The future net cash flows were reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at the dates presented and such conditions continually change. Accordingly, such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (in thousands):
Changes in Standardized Discounted Future Cash Flows. The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil, gas and NGL reserves (in thousands), including amounts related to asset retirement obligations. Since AGP and ARP allocate taxable income to their respective owners, no recognition has been given to income taxes:
(1)
See “Reserve Quantity Information” and “Revisions of Previous Estimates” sections above for additional discussion and analysis of significant changes within the periods presented.
NOTE 17 - QUARTERLY RESULTS (UNAUDITED)
(1)
Revenues include gains (losses) on mark to market derivatives. A $73.3 million loss on ARP’s mark-to-market derivatives is included for the second quarter related to increases in commodity future prices relative to ARP’s commodity fixed price swaps during the second quarter as compared to the prior year period.
(2)
For the fourth quarter, second quarter and first quarter of the year ended December 31, 2016, approximately 9,709,000, 7,956,000 and 7,781,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive.
(3)
ARP was deconsolidated in the third quarter of 2016, resulting in the recognition of a $46.9 million gain in that quarter.
(4)
Includes an asset impairment charge of $41.9 million in the fourth quarter of 2016.
(1)
For the fourth quarter, third quarter and second quarter of the year ended December 31, 2015, approximately 7,649,000, 7,787,000 and 5,759,000 units, respectively, were excluded from the computation of diluted net income (loss) per common unit, because the inclusion of such units would have been anti-dilutive.
(2)
Includes an asset impairment charge of $679.5 million and $294.4 million in the third and fourth quarters of 2015, respectively.
ITEM 9:
ITEM 9:
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A:
ITEM 9A:
CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, our management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
Under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our disclosure committee appointed by such officers, we have carried out an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2016, our disclosure controls and procedures were effective at the reasonable assurance level.
There have been no changes in our internal control over financial reporting during the third quarter of 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of internal control over financial reporting based upon criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 Internal Control - Integrated Framework (COSO framework).
An effective internal control system, no matter how well designed, has inherent limitations, including the possibility of human error and circumvention or overriding of controls and therefore can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, effectiveness of an internal control system in future periods cannot be guaranteed because the design of any system of internal controls is based in part upon assumptions about the likelihood of future events. There can be no assurance that any control design will succeed in achieving its stated goals under all potential future conditions. Over time certain controls may become inadequate because of changes in business conditions, or the degree of compliance with policies and procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be detected.
There have been no changes in our internal control over financial reporting during the fourth quarter of 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Based on our evaluation under the COSO framework, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2016.
ITEM 9B:
ITEM 9B:
OTHER INFORMATION
None.
PART III
ITEM 10:
ITEM 10:
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Directors and Executive Officers
The following table sets forth information regarding our directors and executive officers.
Name
Age
Position(s)
Edward E. Cohen
Chief Executive Officer and Director
Jonathan Z. Cohen
Executive Chairman of the Board
Mark C. Biderman
Director
DeAnn Craig
Director
Dennis A. Holtz
Director
Walter C. Jones
Director
Jeffrey F. Kupfer
Director
Ellen F. Warren
Director
Daniel C. Herz
President
Jeffrey M. Slotterback
Chief Financial Officer
Mark D. Schumacher
Senior Vice President
Lisa Washington
Vice President, Chief Legal Officer and Secretary
Matthew J. Finkbeiner
Chief Accounting Officer
Edward E. Cohen has been our Chief Executive Officer since February 2015 and President from February 2015 to April 2015, and before that was Chairman and Chief Executive Officer since February 2012. Mr. Cohen has been Executive Chairman and a Class A Director of Titan Energy, LLC since September 2016 and, before that was Executive Chairman of Titan’s predecessor, Atlas Resource Partners, L.P., since August 2015. He has also served as Chairman of the board of directors and Chief Executive Officer of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. Mr. Cohen was the Chairman of the board of directors of the general partner of Atlas Energy, L.P. from its formation in January 2006 until February 2011, when he became its Chief Executive Officer and President until February 2015. Mr. Cohen served as the Chief Executive Officer of Atlas Energy’s general partner from its formation in January 2006 until February 2009. Mr. Cohen served on the executive committee of Atlas Energy’s general partner from 2006 until February 2015. Mr. Cohen also was the Chairman of the board of directors and Chief Executive Officer of Atlas Energy, Inc. (formerly known as Atlas America, Inc.) from its organization in 2000 until February 2011, and also served as its President from September 2000 to October 2009. Mr. Cohen was the Executive Chair of the managing board of Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP”) from its formation in 1999 until February 2015. Mr. Cohen was the Chief Executive Officer of Atlas Pipeline GP from 1999 to January 2009. Mr. Cohen was the Chairman of the Board and Chief Executive Officer of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc., from their formation in June 2006 until February 2011. In addition, Mr. Cohen was a director of Resource America, Inc. (formerly a publicly traded specialized asset management company) from 1988 until September 2016 and its Chairman of the board of directors from 1990 until September 2016, and was its Chief Executive Officer from 1988 until 2004 and President from 2000 until 2003; Chairman of the board of Resource Capital Corp. (a publicly traded real estate investment trust) from its formation in 2005 until November 2009 and served on its board
until September 2016; and Chairman of the board of directors of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen. Mr. Cohen’s strong financial and energy industry experience, along with his deep knowledge of our company resulting from his long tenure with Atlas Energy and its predecessors, enables Mr. Cohen to provide valuable perspectives on many issues facing us. Mr. Cohen’s service on the board of directors creates an important link between management and the board and provides us with decisive and effective leadership. Mr. Cohen’s extensive experience in founding, operating and managing public and private companies of varying size and complexity have enabled him to provide valuable expertise to us. Additionally, among the reasons for his appointment as a director, Mr. Cohen brings to the board of directors the vast experience that he has accumulated through his activities as a financier, investor and operator in various parts of the country. These diverse experiences enable Mr. Cohen to bring unique perspectives to the board of directors, particularly with respect to business management, financial markets and financing transactions and corporate governance issues.
Jonathan Z. Cohen has been the Executive Chairman of our Board since February 2015, and before that was Vice Chairman from February 2012. Mr. Cohen has served as Titan Energy, LLC’s Executive Vice Chairman and a Class A Director since September 2016, and before that was Executive Vice Chairman of Titan’s predecessor, Atlas Resource Partners, L.P., since August 2015. Mr. Cohen has served as Executive Vice Chairman of the board of directors of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. Mr. Cohen served as Executive Chairman of the board of directors of Atlas Energy, L.P.’s general partner from January 2012 until February 2015. Before that, he served as Chairman of the board of directors of Atlas Energy’s general partner from February 2011 until January 2012 and as Vice Chairman of the board of directors of its general partner from its formation in January 2006 until February 2011. Mr. Cohen served as the chairman of the executive committee of Atlas Energy’s general partner from 2006 until February 2015. Mr. Cohen was the Vice Chairman of the board of directors of Atlas Energy, Inc. from its incorporation in September 2000 until February 2011. Mr. Cohen was the Executive Vice Chair of the managing board of Atlas Pipeline Partners GP, LLC from its formation in 1999 until February 2015. Mr. Cohen was the Vice Chairman of the Board of Atlas Energy Resources, LLC and its manager, Atlas Energy Management, Inc., from their formation in June 2006 until February 2011. Mr. Cohen was a senior officer of Resource America from 1998 until September 2016, serving as the Chief Executive Officer from 2004 to September 2016, President from 2003 to September 2016 and a director from 2002 to September 2016. Mr. Cohen served as Chief Executive Officer, President and a director of Resource Capital Corp. from its formation in 2005 until September 2016. Since September 2016, Mr. Cohen has served as the founder and Chief Executive Officer of Hepco Capital Management, LLC, a recently formed private investment firm. Mr. Cohen is a son of Edward E. Cohen. Mr. Cohen’s extensive knowledge of our business resulting from his long service with Atlas Energy and its predecessors, as well as his strong financial and industry experience, allows him to contribute valuable perspectives on many issues facing us. Mr. Cohen’s service on our board of directors creates an important link between management and the rest of the board of directors and provides us with decisive and effective leadership. Mr. Cohen’s involvement with public and private entities of varying size, complexity and focus, and raising debt and equity for such entities, provides him with extensive experience and contacts that will be valuable to us. Additionally, among the reasons for his appointment as a director, Mr. Cohen’s financial, business, operational and energy experience, as well as the experience that he has accumulated through his activities as a financier and investor, add strategic vision to the board of directors to assist with our growth, operations and development. Mr. Cohen will be able to draw upon these diverse experiences to provide guidance and leadership with respect to exploration and production operations, capital markets and corporate finance transactions and corporate governance issues.
Mark C. Biderman has been a director since February 2015. Mr. Biderman served as a director of the general partner of Atlas Energy, L.P. from February 2011 to February 2015. Before that, he was a director of Atlas Energy, Inc. from July 2009 until February 2011. Mr. Biderman was Vice Chairman of National Financial Partners Corp. from September 2008 to December 2008, and was its Executive Vice President and Chief Financial Officer from November 1999 to September 2008. From May 1987 to October 1999, he served as Managing Director and Head of the Financial Institutions Group at CIBC World Markets Group and its predecessor, Oppenheimer & Co., Inc. Mr. Biderman has served as a director and chair of the audit committee, as well as a member of the corporate governance and nominating committee, of Full Circle Capital Corporation from August 2010 until November 2016; a director and member of the audit committee of Great Elm Capital Corp. since November 2016; a director and chair of the compensation committee, as well as a member of the audit committee, of Apollo Commercial Real Estate Finance, Inc. since November 2010; and a director and chair of the audit committee, and a member of the nominating and corporate governance committee, of Apollo Residential Mortgage, Inc. from July 2011 until September 2016. Mr. Biderman is a Chartered Financial Analyst. Mr. Biderman brings over 40 years’ of business and financial experience to our board of directors. Mr. Biderman also brings more than ten years of collective service on various boards of directors as well as his service on the audit committees of three other companies. In addition, the board of directors will benefit from his business acumen and valuable financial experience.
Dolly Ann (DeAnn) Craig has been a director since March 2012. Dr. Craig served as a consultant to Atlas Energy, L.P. from April 2011 to January 2012. She has been an Adjunct Professor in the Petroleum Engineering Department of the Colorado School of Mines since January 2009, and a member of the Colorado Oil and Gas Conservation Commission since March 2009. Dr. Craig was the Senior Vice President - Asset Assessment of CNX Gas Corporation from September 2007 until February 2009, and President of Phillips Petroleum Resources (a Canadian subsidiary of Phillips Petroleum) and Manager of Worldwide Drilling and Production from July 1992 to October 1996. Dr. Craig was a director for Samson Oil & Gas Limited from July 2011 through January 2016 and served as chair of its audit committee as well as a member of its compensation committee. She is a Past-President of the Society of
Petroleum Engineers (“SPE”), Past-President of the Society of Petroleum Engineers’ Foundation, and a Past-President of the American Institute of Mining, Metallurgical, and Petroleum Engineers. Dr. Craig was awarded SPE Honorary Membership in 2015, the Society’s highest honor. Dr. Craig serves as chair of our environmental, health and safety committee. Dr. Craig is a member of the National Association of Corporate Directors and is a Registered Professional Engineer in the State of Colorado. Dr. Craig brings to our board of directors a strong technical and operational background and practical expertise in issues relating to exploration and production activities. Dr. Craig’s experience, particularly her background in petroleum engineering, and her knowledge of our operations resulting from her work as a consultant, benefits the board of directors. In addition, Dr. Craig provides leadership to the board of directors with respect to energy policy issues, owing to her experience as a member of the Colorado Oil and Gas Conservation Commission.
Dennis A. Holtz has been a director since February 2015 and has served as lead independent director since April 2015. Mr. Holtz served as a director of the general partner of Atlas Energy, L.P. from February 2011 until February 2015. Before that, he was a director of Atlas Energy, Inc. from February 2004 to February 2011. Mr. Holtz maintained a corporate and real estate law practice in Philadelphia and New Jersey from 1988 until his retirement in January 2008. During that period, Mr. Holtz was counsel for or corporate secretary of numerous private and public business entities, and this extensive experience with corporate governance issues was the reason he was chosen as chair of our nominating and governance committee. As a licensed attorney with over 50 years of business experience, Mr. Holtz offers a unique and invaluable perspective into corporate governance matters. Additionally, Mr. Holtz has extensive knowledge of the energy industry, having served as a director of our former affiliated companies for nine years.
Walter C. Jones has been as a director since February 2015. Mr. Jones served as a director of the general partner of Atlas Energy, L.P. from October 2013 until February 2015, a director and chair of the audit committee of Atlas Energy Resources, LLC from December 2006 until September 2009, and a director of Atlas Energy, Inc. from September 2009 until March 2010. Since November 2013, Mr. Jones has been the managing director of the Jones Pohl Group, an investment firm based in Dubai, UAE, that invests in clean energy projects, primarily in developing and developed markets around the globe. JPG is also the majority shareholder of a Dubai-based geothermal energy developer, RG Safa Energy. From April 2010 to October 2013, Mr. Jones served as the U.S. Executive Director and Chief-of-Mission to the African Development Bank in Tunis, Tunisia, having been nominated for the position by President Barack Obama in 2009 and confirmed by the U.S. Senate in 2010. In that position, he represented the United States on the African Development Bank’s Board of Directors, and served as chair of the bank’s audit committee and vice-chair of both the ethics and development effectiveness committees. Mr. Jones served as the Head of Private Equity and General Counsel at GRAVITAS Capital Advisors, LLC from June 2005 until May 2007. Mr. Jones served in a number of positions at the Overseas Private Investment Corporation from May 1994 to May 2005, and then again from September 2007 until April 2010, including Manager for Asia, Africa, the Middle East, Latin America and the Caribbean and Senior Investment Officer in the Finance Department; and was an International Consultant at the Washington, D.C. firm of Neill & Co. before that. Mr. Jones began his career at the law firm of Sidley & Austin, where he was a transactions attorney specializing in leveraged buyouts. Mr. Jones is a seasoned energy company director, having previously served as a director and chair of the audit committee of Atlas Energy Resources, LLC and a director of Atlas Energy, Inc. Mr. Jones’ combination of private and public sector experience, as well as his international work, has afforded him a unique combination of management and leadership experience. Our board of directors benefits from his investment and transaction expertise as well as his valuable financial experience.
Jeffrey F. Kupfer has been a director since February 2015. Mr. Kupfer served as a director of the general partner of Atlas Energy, L.P. from March 2014 until February 2015. Since 2015, Mr. Kupfer has been the co-founder of Starling Trust Sciences, an applied behavioral sciences technology company. He has been an Adjunct Professor of Policy and Management at Carnegie Mellon University’s H. John Heinz III College since October 2009. Mr. Kupfer served as a senior advisor for policy and government affairs at Chevron from February 2011 to January 2014, and a Senior Vice President at Atlas Energy, Inc. from September 2009 to February 2011. Before that, Mr. Kupfer held a number of high level positions in the U.S. Department of Energy, including Acting Deputy Secretary and Chief Operating Officer from March 2008 to January 2009, and Chief of Staff from October 2006 to March 2008. Mr. Kupfer also worked in the White House as a Special Assistant to the President for Economic Policy in 2006, as the Executive Director of the President’s Panel on Federal Tax Reform in 2005, and as Deputy Chief of Staff at the U.S. Treasury Department from 2001 to 2005. Mr. Kupfer brings to the board of directors extensive experience in the energy industry, as well his perspective as a former senior official in the U.S. government, which we view as complementary to the industry perspective of other members of the board of directors.
Ellen F. Warren has been a director since February 2015. Ms. Warren served as a director of the general partner of Atlas Energy, L.P. from February 2011 until February 2015, a director of Atlas Energy, Inc. from September 2009 until February 2011, and a director of Atlas Energy Resources, LLC from December 2006 until September 2009. She is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Before founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. She was previously Vice President of Marketing/Communications for Jefferson Bank from September 1992 to February 1998, and President of Diversified Advertising, Inc. from December 1984 to September 1992, where she provided marketing services to various industries, including the energy industry. Ms. Warren is a seasoned energy company director who brings her extensive experience as an independent member of the boards of Atlas Energy, Inc. and Atlas Energy Resources, LLC, where she
chaired a special committee. As a former member of the National Association of Corporate Directors, Ms. Warren also offers expertise in corporate governance matters. Ms. Warren has 35 years of experience in public relations, corporate communications, crisis communications and marketing, and as the founder and president of various marketing communications firms, she is uniquely positioned to provide leadership to the board of directors in public relations and communications matters. Ms. Warren also brings valuable management, strategic planning, communication, community involvement and leadership skills to the board of directors.
Daniel C. Herz has been our President since April 2015. Mr. Herz has served as Titan Energy, LLC’s Chief Executive Officer and a Class A Director since September 2016, and before that was Chief Executive Officer of Titan’s predecessor, Atlas Resource Partners, L.P., since August 2015. Mr. Herz has also served as President and a director of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of the general partner of Atlas Resource Partners, L.P. from March 2012 to April 2015. Mr. Herz served as Senior Vice President of Corporate Development and Strategy of the general partner of Atlas Energy, L.P. from February 2011 until February 2015. Mr. Herz was also Senior Vice President of Corporate Development of Atlas Pipeline Partners GP, LLC from August 2007 until February 2015. He was also Senior Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Energy Resources, LLC from August 2007 until February 2011. Before that, Mr. Herz was Vice President of Corporate Development of Atlas Energy, Inc. and Atlas Pipeline Partners GP, LLC from December 2004 until August 2007.
Jeffrey M. Slotterback has been our Chief Financial Officer since September 2015 and served as our Chief Accounting Officer from March 2012 to October 2015. Mr. Slotterback has been Titan Energy, LLC’s Chief Financial Officer and a Class A Director since September 2016, and before that was Chief Financial Officer of Titan’s predecessor, Atlas Resource Partners, L.P., since September 2015. Mr. Slotterback has also served as the Chief Financial Officer of the general partner of Atlas Growth Partners, L.P. since September 2015 and served as its Chief Accounting Officer from its inception in 2013 to October 2015. Mr. Slotterback served as Chief Accounting Officer of the general partner of Atlas Energy, L.P. from March 2011 until February 2015, and Manager of Financial Reporting from May 2007 until July 2009 and again from February 2011 until March 2011. Mr. Slotterback was the Manager of Financial Reporting for Atlas Energy, Inc. from July 2009 until February 2011 and for Atlas Pipeline Partners GP, LLC from May 2007 until July 2009. Mr. Slotterback was a Senior Auditor at Deloitte and Touche, LLP from 2004 until 2007, where he focused on energy and health care clients. Mr. Slotterback is a Certified Public Accountant.
Mark D. Schumacher has served as our Senior Vice President since April 2015 and had served as Chief Operating Officer from October 2013 to April 2015. Mr. Schumacher has served as Titan Energy, LLC’s President since September 2016, and before that was President of Titan’s predecessor, Atlas Resource Partners, L.P., since April 2015. Mr. Schumacher has been the Executive Vice President of Operations of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. He had served as Executive Vice President of Atlas Energy, L.P. from July 2012 to October 2013. From August 2008 to July 2012, Mr. Schumacher served as President of Titan Operating, LLC, which ARP acquired in July 2012. From November 2006 until August 2008, Mr. Schumacher served as President of Titan Resources, LLC, which built an acreage position in the Barnett Shale that it sold to XTO Energy in October 2008. From February 2005 to November 2006, Mr. Schumacher served as the Team Lead of EnCana Oil & Gas (USA) Inc. where he was responsible for Encana’s Barnett Shale development. Mr. Schumacher has over 33 years of experience in drilling, production and reservoir engineering management, operations and business development in East Texas, Austin Chalk, Barnett Shale, Mid-Continent, the Rockies, the Gulf of Mexico, Latin America and Canada.
Lisa Washington has been our Senior Vice President since September 2015, and our Chief Legal Officer and Secretary since February 2012 and served as Vice President from February 2015 until September 2015. Ms. Washington has served as Titan Energy, LLC’s Vice President, Chief Legal Officer and Secretary since September 2016, and before that was Vice President, Chief Legal Officer and Secretary of Titan’s predecessor, Atlas Resource Partners, L.P., since August 2015. Ms. Washington has served as Chief Legal Officer and Secretary of the general partner of Atlas Growth Partners, L.P. since its inception in 2013. Ms. Washington served as Chief Legal Officer and Secretary of the general partner of Atlas Energy, L.P. from January 2006 to October 2009, and as a Senior Vice President of its general partner from October 2008 to October 2009, and as Vice President, Chief Legal Officer and Secretary from February 2011 to February 2015. She also served as Chief Legal Officer and Secretary of Atlas Pipeline Partners GP, LLC from November 2005 to October 2009, a Senior Vice President from October 2008 to October 2009 and a Vice President from November 2005 until October 2008; Chief Legal Officer and Secretary of Atlas Energy, Inc. from November 2005 until February 2011, a Senior Vice President from October 2008 until February 2011, and a Vice President from November 2005 until October 2008; and Chief Legal Officer and Secretary of Atlas Energy Resources, LLC from 2006 until February 2011, a Senior Vice President from July 2008 until February 2011 and a Vice President from 2006 until July 2008. From 1999 to 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.
Matthew Finkbeiner has been our Chief Accounting Officer since October 2015. Mr. Finkbeiner has been the Chief Accounting Officer of Titan Energy, LLC since September 2016, and before that was the Chief Accounting Officer of Titan’s predecessor, Atlas Resource Partners, L.P., since October 2015. Mr. Finkbeiner has been the Chief Accounting Officer of the general partner of Atlas Growth Partners, L.P. since October 2015. Mr. Finkbeiner has held positions with Deloitte & Touche LLP, including Audit Senior Manager from September 2010 until joining us in October 2015, Audit Manager from September 2007 to September 2010, and Audit Senior/Staff from September 2002 until September 2007. While at Deloitte & Touche LLP,
Mr. Finkbeiner managed audits for a diversified base of clients in the oil and gas industry, including master limited partnerships. Mr. Finkbeiner is a Certified Public Accountant.
Involvement in Certain Legal Proceedings
Each of our executive officers also served as an executive officer of ARP during its Chapter 11 Filings. See “Item 1. Business-Overview-ARP Restructuring and Emergence from Chapter 11 Proceedings.”
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires executive officers and board members and persons who beneficially own more than 10% of a registered class of our equity securities to file reports of ownership and changes in ownership with the Securities and Exchange Commission and to furnish us with copies of all such reports.
Based solely upon our review of reports received by us, or representations from certain reporting persons that no filings were required for those persons, we believe that during fiscal year 2016 our executive officers, directors and persons who beneficially owned more than 10% of our common units complied with all applicable filing requirements except for Mr. Leon Cooperman who filed one late Form 4 relating to sales of common units.
Composition of the Board of Directors
Our board of directors is divided into three classes, comprised of two, three and three directors, respectively. The directors designated as Class II directors have terms expiring at the 2017 annual meeting of unitholders, the directors designated as Class III directors have terms expiring at the 2018 annual meeting of unitholders, and the directors designated as Class I directors have terms expiring at the 2019 annual meeting of unitholders. The Class I directors are Mark C. Biderman and DeAnn Craig; Class II directors are Edward E. Cohen, Walter C. Jones and Jeffrey F. Kupfer; and Class III directors are Jonathan Z. Cohen, Dennis A. Holtz and Ellen F. Warren. Directors for each class will be elected at the annual meeting of unitholders held in the year in which the term for that class expires and thereafter will serve for a term of three years.
Director Independence
While our common units are no longer listed on the New York Stock Exchange (“NYSE”), we have determined to continue to use the NYSE standard of independence. The board has determined that all directors other than Edward E. Cohen and Jonathan Z. Cohen qualify as “independent” under the NYSE standards. These standards provide that no director qualifies as “independent” unless the board of directors affirmatively determines that the director has no material relationship with us or our subsidiaries (either directly or as a member, partner, shareholder or officer of an organization that has a relationship with us or any of our subsidiaries). In making this determination, the board of directors (i) adheres to all of the specific tests for independence included in the NYSE standards, and (ii) considers all other facts and circumstances it deems necessary or advisable and any standards of independence as may be established by the board from time to time. Under NYSE standards:
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a director is not independent if the director is, or has been within the last three years, an employee of us or any of our subsidiaries, or if an immediate family member is, or has been within the last three years, an executive officer of us or any of our subsidiaries;
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a director is not independent if the director has received, or has an immediate family member who has received, during any 12-month period within the last three years, more than $120,000 in direct compensation from us or any of our subsidiaries, other than director and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service), and other than amounts received by an immediate family member for service as an employee (other than an executive officer);
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a director is not independent if (A) the director is a current partner or employee of a firm that is our internal or external auditor; (B) the director has an immediate family member who is a current partner of such firm; (C) the director has an immediate family member who is a current employee of such a firm and personally works on our audit; or (D) the director or an immediate family member was within the last three years a partner or employee of such a firm and personally worked on our audit within that time;
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a director is not independent if the director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the present executive officers of us or any of our subsidiaries at the same time serves or served on that company’s compensation committee; and
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a director is not independent if the director is a current employee, or if an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, us or any of our subsidiaries for property or services in an amount that, in any of the last three fiscal years, exceeds the greater of $1 million or two percent of such other company’s consolidated gross revenues.
The board of directors assesses on a regular basis, and at least annually, the independence of directors and, based on the recommendation of the Nominating and Corporate Governance Committee, will make a determination as to which members are independent.
Committees of the Board of Directors
The standing committees of the board of directors are the Audit Committee, the Compensation Committee, the Nominating and Governance Committee, the Investment Committee and the Environment, Health and Safety Committee.
Audit Committee. The Audit Committee’s duties include recommending to our board of directors the independent public accountants to audit our financial statements and establishing the scope of, and overseeing, the annual audit. The committee also approves any other services provided by public accounting firms. The Audit Committee provides assistance to the board of directors in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of internal audit function. The Audit Committee oversees our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that our management and the board of directors have established. In doing so, it is the responsibility of the Audit Committee to maintain free and open communication between the committee and the independent auditors, internal accounting function and our management. In accordance with the Sarbanes-Oxley Act of 2002, the Audit Committee has adopted procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls, and auditing matters and to allow for the confidential, anonymous submission by employees and others of concerns regarding questionable accounting or auditing matters. All of the members of the Audit Committee meet the independence standards established by the NYSE and the board. The members of the Audit Committee are Mr. Biderman, Mr. W. Jones and Mr. Kupfer. Mr. Biderman is the chair and has been determined by the board of directors to be an “audit committee financial expert,” as defined by SEC rules.
Compensation Committee. The principal functions of the Compensation Committee are to assist the board of directors in carrying out its responsibilities with respect to compensation, particularly including evaluation of the compensation paid or payable to our chief executive officer and other named executive officers. The Compensation Committee reviews compensation paid or payable under employee qualified benefit plans, employee stock option and restricted stock option plans, under individual employment agreements, and executive compensation and bonus programs. The Compensation Committee has the sole authority to select, retain and/or terminate independent compensation advisors. Ms. Warren and Messrs. Biderman and Holtz are the members of the Compensation Committee, with Ms. Warren acting as the chair. The board of directors has determined that each member of the Compensation Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board. In addition, the members of the Compensation Committee qualify as “non-employee directors” for purposes of Rule 16b-3 under the Exchange Act.
Nominating and Governance Committee. The principal functions of the Nominating and Governance Committee are to recommend to the board the criteria for members of the board and to identify individuals who meet such criteria, and recommend such individuals to the board for election to fill vacancies on the Board; review all compensation paid to directors, in cash or in equity grants, and, on a biannual basis, recommend changes to such compensation, if appropriate; establish procedures for the annual self-assessment by directors set forth by the NYSE, and implement and supervise each self-assessment; and periodically review our formation documents and suggest revisions to them. Ms. Warren and Messrs. Holtz and Kupfer are the members of the Nominating and Governance Committee, with Mr. Holtz acting as the chair. The board of directors has determined that each of the members of the Nominating and Governance Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board.
Investment Committee. The principal functions of the Investment Committee are to assist the board in reviewing management investment practices, policies, strategies, transactions and performance, as well as evaluating and monitoring existing and proposed investments. Messrs. Biderman, Jones and Kupfer are the members of the Investment Committee, with Messrs. Jones and Kupfer acting as the co-chairs. The board of directors has determined that each of the members of the Investment Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board.
Environment, Health and Safety Committee. The Environment, Health and Safety Committee assists the board of directors in determining whether we have appropriate policies and management systems in place with respect to environment, health and safety and related matters. The committee monitors the adequacy of our policies and management for addressing environment, health and safety matters consistent with prudent exploration and production industry practices. The Environment, Health and Safety Committee monitors and reviews compliance with applicable environment, health and safety laws, rules and regulations. The committee reviews actions taken by management with respect to deficiencies identified or improvements recommended. The members of the Environment, Health and Safety Committee are Dr. Craig, Ms. Warren and Messrs. Holtz and Kupfer. Dr. Craig serves as chair of the committee. The board of directors has determined that each of the members of the Environment, Health and Safety Committee is independent, as defined by the rules of the NYSE and in accordance with the independence standards adopted by the board.
Code of Business Conduct and Ethics, Governance Guidelines and Committee Charters
We have adopted a code of business conduct and ethics that applies to our principal executive officer, principal financial officer and principal accounting officer, as well as to persons performing services for us generally. We have also adopted governance guidelines and charters for the Audit Committee, Compensation Committee, Nominating and Governance Committee and Environmental, Health and Safety Committee. We will make a printed copy of our code of ethics, our governance guidelines and
committee charters available to any unitholder who so requests. Requests for print copies may be directed to us as follows: Atlas Energy Group, LLC, Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, Pennsylvania 15275-1011, Attention: Secretary. The code of business conduct and ethics, the governance guidelines and our committee charters are also posted, and any waivers we grant to our code of business conduct and ethics will be posted, on our website at www.atlasenergy.com.
Compensation Committee Interlocks and Insider Participation
The Compensation Committee of our board of directors consists of Ms. Warren and Messrs. Biderman and Holtz. None of such persons was an officer or employee of ours or any of our subsidiaries during fiscal 2016 or was formerly an officer of ours. During 2016, no members of the Compensation Committee had a relationship that must be described under the SEC rules relating to disclose of related person transactions. None of our executive officers has served on the board of directors or compensation committee of any entity that had one or more of its executive officers serving on our Board of Directors or Compensation Committee.
Corporate Governance
Board Leadership; Executive Sessions of the Board
Jonathan Z. Cohen serves as the Executive Chairman of the board and Edward E. Cohen serves as our Chief Executive Officer and director. We believe that the most effective leadership structure at the present time is to have separate Executive Chairman of the board and Chief Executive Officer positions because this allows the board to benefit from having two strong voices bringing separate views and perspectives to meetings. The Chief Executive Officer and the Executive Chairman of the board are in regular contact and serve together with Daniel C. Herz, who serves as President, as our executive committee. Our leadership structure is also comprised of a lead independent director, board committees led and comprised of independent directors and active engagement by all directors. The Board believes that this structure provides a balance between strong company leadership and appropriate safeguards and oversight by independent directors.
As set forth in our governance guidelines, the independent members of our board of directors meet in executive session regularly without management. The purpose of these executive sessions is to promote open and candid discussion among the independent board members.
In April 2015 the Board established the position of lead independent director, and appointed Dennis Holtz to fill the role. The lead independent director may serve as the liaison between the independent members of the Board and management on matters such as the annual board evaluation; however, independent members of the Board also interface with management directly.
Governance Guidelines
The board of directors has adopted governance guidelines to assist it in guiding our governance practices. These practices will be regularly reevaluated by the Nominating and Governance Committee in light of changing circumstances in order to continue serving our best interests and the best interests of our unitholders.
Role in Risk Oversight
General
The role in risk oversight of the board of directors recognizes the multifaceted nature of risk management. The board has empowered several of its committees with aspects of risk oversight. We administer our risk oversight function through the Audit Committee, which monitors material enterprise risks, and the Environment, Health and Safety Committee, which assists in determining whether appropriate policies and management systems are in place with respect to environment, health and safety and related matters and monitors and reviews compliance with applicable environment, health and safety laws, rules and regulations. The Audit Committee also oversees our internal audit function and is responsible for monitoring the integrity and ensuring the transparency of our financial reporting processes and systems of internal controls regarding finance, accounting and regulatory compliance. The Audit Committee incorporates its risk oversight function into its regular reports to the board of directors. The Environment, Health and Safety Committee reviews actions taken by management with respect to deficiencies identified or improvements recommended.
In addition to these committees’ role in overseeing risk management, the full board of directors regularly engages in discussions of the most significant risks that we face and how these risks are being managed. Our senior executives provide regular updates about our strategies and objectives and the risks inherent within them at board and committee meetings and in regular reports. Board and committee meetings also provide a venue for directors to discuss issues of concern with management. The Board and committees may call special meetings when necessary to address specific issues or matters that should be addressed before the next regularly scheduled meeting. In addition, our directors have access to our management at all levels to discuss any matters of interest, including those related to risk. Those members of management most knowledgeable of the issues will attend board meetings to provide additional insight into items being discussed, including risk exposures.
Compensation Programs
Our compensation policies and programs are intended to encourage employees to remain focused on both our short-term and long-term goals. Annual incentives are intended to tie a significant portion of each of the named executive officer’s compensation to our annual performance and/or that of the divisions for which the officer was responsible. We believe that the focus on revenue growth and distributable cash flow in making incentive bonus awards and unit price performance in granting equity awards provides a check on excessive risk taking. Our Code of Business Conduct and Ethics, which applies to all officers and directors, further seeks to mitigate the potential for inappropriate risk taking. We also prohibit hedging transactions involving our units so our officers and directors cannot insulate themselves from the effects of our unit performance.
Our compensation committee, together with senior management, also reviews compensation programs and benefits plans affecting employees generally (in addition to those applicable to our executive officers), and we have concluded that our compensation policies and practices do not create risks that are reasonably likely to have a material adverse effect on our company. We also believe that our incentive compensation arrangements provide incentives that do not encourage risk-taking beyond our ability to effectively identify and manage significant risks; are compatible with effective internal controls and our risk management practices; and are supported by the oversight and administration of the Compensation Committee with regard to executive compensation programs.
Director Nomination Process
The Nominating and Governance Committee is responsible for reviewing with our board of directors the appropriate skills and characteristics required of board members in the context of the makeup of the board of directors and developing criteria for identifying and evaluating board candidates. The Nominating and Governance Committee identifies director nominees by first evaluating the current members of the board willing to continue in service. Current members with skills and experience that are relevant to our business and who are willing to continue in service will be considered for renomination, balancing the value of continuity of service by existing members of the board with that of obtaining a new perspective. If any member of the board does not wish to continue in service, or if the Nominating and Governance Committee or the board decides not to nominate a member for reelection, or if we decide to expand the size of the board, the Nominating and Governance Committee identifies the desired skills and experience of a new nominee consistent with the Nominating and Governance Committee’s criteria for board service. Current members of the board and management are be polled for their recommendations. Research may also be performed or third parties retained to identify qualified individuals. To date, we have not engaged third parties to identify or evaluate potential nominees; however, we may in the future choose to do so. The Nominating and Governance Committee considers diversity as an element in identifying director nominees.
The Nominating and Governance Committee evaluates independent director candidates based upon a number of criteria, including:
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commitment to promoting the long-term interests of our unitholders and independence from any particular constituency;
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professional and personal reputations that are consistent with our values;
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broad general business experience and acumen, which may include experience in management, finance, marketing and accounting;
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a high level of personal and professional integrity;
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adequate time to devote attention to the board;
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such other attributes, including independence, relevant in constituting a board that also satisfy the requirements imposed by the SEC and the NYSE; and
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board balance in light of our current and anticipated needs and the attributes of the other directors and executives.
The specific criteria that the Nominating and Governance Committee uses to identify a nominee to serve as a member of the board of directors depends on the qualities being sought. The committee may reevaluate the relevant criteria for board membership from time to time in response to changing business factors or regulatory requirements. The full board of directors is responsible for selecting candidates for election as directors based on the recommendation of the Nominating and Governance Committee.
Our limited liability company agreement contains provisions that address the process by which a unitholder may nominate an individual to stand for election to the board of directors. Our board of directors has adopted a policy concerning the evaluation of unitholder recommendations of board candidates by the Nominating and Governance Committee. Our Nominating and Governance Committee evaluates director candidates nominated by unitholders in the same manner as other candidates.
Unitholder Nominations to Our Board of Directors
Pursuant to our limited liability agreement, our unitholders may nominate candidates for election to our board by providing timely prior notice to our board as described below under “-Communicating with the Board of Directors” as follows:
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The notice must be delivered to our board not earlier than the close of business on the 120th day nor later than the close of business on the 90th day prior to the first anniversary of the preceding year’s annual meeting; provided, however, that
o
in the event that the date of the annual meeting is more than 30 days before or more than 60 days after such anniversary date, and
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in the case of the 2016 annual meeting, a unitholder’s notice to be timely must be so delivered not earlier than the close of business on the 120th day prior to the date of such annual meeting and not later than the close of business on the later of the 90th day prior to the date of such annual meeting or, if the first public announcement of the date of such annual meeting is less than 100 days prior to the date of such annual meeting, the 10th day following the day on which public announcement of the date of the annual meeting is first made. In no event shall an adjournment or postponement of an annual meeting, or the public announcement thereof, commence a new time period for the giving of a limited partner’s notice as described above.
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The notice must be updated and supplemented, if necessary, so that the information provided or required to be provided in such notice will be true and correct as of the record date for the meeting and as of the date that is ten business days prior to the meeting or any adjournment or postponement thereof, and such updates and supplements must be delivered to our board
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not later than five business days after the record date for the meeting in the case of the update and supplement required to be made as of the record date, and
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not later than eight business days prior to the date for the meeting, any adjournment or postponement thereof in the case of the update and supplement required to be made as of ten business days prior to the meeting or any adjournment or postponement thereof.
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The notice must set forth:
o
the name and address of the unitholder, as they appear on our books, of the beneficial owner, if any, and of their respective affiliates or associates or others acting in concert therewith;
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(1) the class or series and number of our securities which are, directly or indirectly, owned beneficially and of record by such unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, (2) any option, warrant, convertible security, stock appreciation right, or similar right with an exercise or conversion privilege or a settlement payment or mechanism at a price related to any of our securities or with a value derived in whole or in part from the value of any of our securities, or any derivative or synthetic arrangement having the characteristics of a long position in any of our securities, or any contract, derivative, swap or other transaction or series of transactions designed to produce economic benefits and risks that correspond substantially to the ownership of any of our securities, including due to the fact that the value of such contract, derivative, swap or other transaction or series of transactions is determined by reference to the price, value or volatility of any of our securities, whether or not such instrument, contract or right shall be subject to settlement in the underlying security, through the delivery of cash or other property, or otherwise, and without regard to whether the unitholder of record, the beneficial owner, if any, or any affiliates or associates or others acting in concert therewith, may have entered into transactions that hedge or mitigate the economic effect of such instrument, contract or right, or any other direct or indirect opportunity to profit or share in any profit derived from any increase or decrease in the value of common units or any of our securities (any of the foregoing, a “Derivative Instrument”), directly or indirectly owned beneficially by such unitholder, the beneficial owner, if any, or any affiliates or associates or others acting in concert therewith, (3) any proxy, contract, arrangement, understanding, or relationship pursuant to which such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith has a right to vote any of our securities, (4) any agreement, arrangement, understanding, relationship or otherwise, including any repurchase or similar so-called “stock borrowing” agreement or arrangement, involving such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith, directly or indirectly, the purpose or effect of which is to mitigate loss to, reduce the economic risk (of ownership or otherwise) of any of our securities by, manage the risk of share price changes for, or increase or decrease the voting power of, such unitholder with respect to any of our securities, or which provides, directly or indirectly, the opportunity to profit or share in any profit derived from any decrease in the price or value of any Partnership Security (any of the foregoing, a “Short Interest”), (5) any rights to dividends on any of our securities owned beneficially by such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith that are separated or separable from the underlying security, (6) any proportionate interest in any of our securities or Derivative Instruments held, directly or indirectly, by a general or limited partnership in which such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith is a general partner or, directly or indirectly, beneficially owns an interest in a general partner of such general or limited partnership, (7) any performance-related fees (other than an asset-based fee) that such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith is entitled to based on any increase or decrease in the value of any of our securities or Derivative Instruments, if any, including without limitation any such interests held by members of such person’s immediate family sharing the same household, (8) any significant equity interests or any Derivative Instruments or Short Interests in any of our principal competitors held by such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith, and (9) any direct or indirect
interest of such unitholder, such beneficial owner, if any, and their respective affiliates or others acting in concert therewith in any contract with us, any of our affiliates or any of our principal competitors (including, in any such case, any employment agreement, collective bargaining agreement or consulting agreement);
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all information that would be required to be set forth in a Schedule 13D filed pursuant to Rule 13d-1(a) under the Exchange Act or an amendment pursuant to Rule 13d-2(a) under the Exchange Act if such a statement were required to be filed under the Exchange Act and the rules and regulations promulgated thereunder by such Unitholder, such beneficial owner and their respective affiliates or associates or others acting in concert therewith, if any; and
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any other information relating to such unitholder and beneficial owner, if any, that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for, as applicable, the proposal and/or for the election of directors in a contested election pursuant to Section 14 of the Securities Exchange Act and the rules and regulations promulgated thereunder.
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If the notice relates to any business other than a nomination of a director that the unitholder proposes to bring before the meeting, the notice must, in addition to the matters set forth in paragraph above, also set forth:
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a brief description of the business desired to be brought before the meeting, the reasons for conducting such business at the meeting and any material interest of the unitholder and beneficial owner, if any, in such business;
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the text of the proposal or business (including the text of any resolutions proposed for consideration); and
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a description of all agreements, arrangements and understandings between the unitholder and beneficial owner, if any, and any other person or persons (including their names) in connection with the proposal of such business by the unitholder.
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As to each person whom the unitholder proposes to nominate for election or reelection to the board, the notice must also:
o
set forth all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Securities Exchange Act and the rules and regulations promulgated thereunder (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if elected);
o
set forth a description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, between or among such unitholder and beneficial owner, if any, and their respective affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective affiliates and associates, or others acting in concert therewith, on the other hand, including, without limitation all information that would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the unitholder making the nomination and any beneficial owner on whose behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in concert therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant; and
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include a completed and signed questionnaire with respect to the background and qualification of the person nominated and the background of any other person or entity on whose behalf the nomination is being made, and a completed and signed representation and agreement that the person nominated (a) is not and will not become a party to (i) any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how the person, if elected as a director, will act or vote on any issue or question (a “Voting Commitment”) that has not been disclosed to us or (ii) any Voting Commitment that could limit or interfere with the person’s ability to comply, if elected as a director, with the person’s fiduciary duties under applicable law, (b) is not and will not become a party to any agreement, arrangement or understanding with any person or entity other than us with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a director that has not been disclosed therein, and (c) in the person’s individual capacity and on behalf of any person or entity on whose behalf the nomination is being made, would be in compliance, if elected as a director, and will comply, with all of our applicable publicly disclosed corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines. In addition, we may require any proposed nominee to furnish such other information as we may reasonably require to determine the eligibility of such proposed nominee to serve as an independent director or that could be material to a reasonable unitholder’s understanding of the independence, or lack thereof, of such nominee.
Communicating with the Board of Directors
Unitholders and other interested parties who would like to communicate their concerns to one or more members of our board of directors, a board committee or the independent directors as a group may do so by writing to them at Atlas Energy Group, LLC, Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, Pennsylvania 15275, c/o Dennis Holtz, Lead Director. All concerns received will be appropriately forwarded and, if deemed appropriate by the Lead Director, may be accompanied by a report summarizing such concerns.
ITEM 11:
ITEM 11:
EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
For purposes of the following Compensation Discussion and Analysis and executive compensation disclosures, the individuals listed below are collectively referred to as our “Named Executive Officers” or “NEOs”:
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Edward E. Cohen, our Chief Executive Officer
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Jeffrey M. Slotterback, our Chief Financial Officer
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Jonathan Z. Cohen, our Executive Chairman of the Board
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Daniel C. Herz, our President
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Mark D. Schumacher, our Senior Vice President
The Atlas Energy Group Compensation Committee (“Compensation Committee”) determines the compensation of our executive officers consistent with our compensation and benefit plans, programs and policies. The following sections of this Compensation Discussion and Analysis describe our compensation philosophy, policies and practices during 2016 as they apply to the Named Executive Officers.
Prior to September 1, 2016, we were the general partner of Atlas Resource Partners, L.P. On September 1, 2016, upon the emergence from bankruptcy of its successor, Titan Energy, we entered into an agreement via a wholly owned subsidiary of ours pursuant to which we manage Titan Energy’s business except for the Non-Delegated Duties as set forth in Titan Energy’s LLC Agreement.
We provide services to Titan Energy pursuant to the provisions of the Omnibus Agreement (the “Omnibus Agreement”) that we entered into on September 1, 2016. Under the Omnibus Agreement, Titan Energy pays us for expenses incurred in connection with our provision of services, subject to certain approval rights held by the Titan Energy Conflicts Committee relating to allocation methodologies for general and administrative costs.
Pursuant to the Omnibus Agreement, eighty percent of our NEOs’ compensation is paid by Titan Energy, with the remainder allocated to us and our subsidiaries. Since Titan Energy does not have a separate Compensation Committee, it relies on our Compensation Committee, and on the Compensation Committee’s independent Compensation Consultant. Titan Energy’s Conflicts Committee has the right to approve “new or additional compensation agreements or arrangements” as well as salary increases for our NEOs. Following September 1, 2016, there have not been any new or additional compensation agreements or arrangements, but our Compensation Committee and the Titan Energy Conflicts Committee did approve an increase in Mr. Slotterback’s base salary.
To protect our rights and those of our key employees, our company and Titan Energy (pursuant to arrangements approved by the Bankruptcy Court), have entered directly into employment agreements with our Chief Executive Officer, Executive Chairman, Executive Vice Chairman, President, and Senior Vice President as set forth below.
Compensation Program Objectives
An understanding of our executive compensation program begins with our program objectives.
•
Aligning the interests of executives and unitholders. We seek to align the interests of our executives with those of our unitholders through equity-based compensation and executive unit ownership requirements.
•
Linking rewards to performance. We seek to implement a pay-for-performance philosophy by tying a significant portion of executives’ compensation to their achievement of goals that are linked to our business strategy and each executive’s contributions towards the achievement of those goals.
•
Offering competitive compensation. We seek to offer an executive compensation program that is competitive and that helps attract, motivate and retain top performing executives.
The Compensation Committee believes that a significant portion of executive compensation should be variable and based on defined performance goals (i.e., “at risk”). Our program meets this objective by delivering compensation in the form of equity and other performance-based awards. Our long-term strategy is to have greater emphasis on long-term corporate success; in 2016, recognizing the restructuring, our pay mix was adjusted toward short-term incentive pay.
Atlas CEOAtlas Average for Other NEOs
Note: Based on compensation for CEO (E. Cohen) and Average for other NEOs (Slotterback, J. Cohen, Herz, and Schumacher). Compensation includes final 2016 base salaries, annual incentives paid for 2016, and annualized values of Atlas Energy Group and Titan Energy long-term incentives granted in 2016.
What we do
What we don’t do
▲ Tie Pay to Performance. A significant portion of each executive officer’s target annual compensation is tied to corporate and individual performance, requiring the achievement of predetermined performance objectives during the performance period.
▼ Tax Gross Ups. We don’t pay tax gross ups for excise taxes that may be imposed as a result of severance or other payments deemed made in connection with a change of control.
▲ Utilize Stock Ownership Guidelines. We have significant unit ownership guidelines, which require our executive officers and directors to hold a percentage of their annual base salary (for directors, their retainer) in equity.
▼ Excessive Perquisites. We generally do not provide perquisites to our executives, other than automobile allowances and Excess 401(k) match contributions for some of our NEOs.
▲ Retain an Independent Compensation Consultant. The Compensation Committee engages an independent compensation consultant, who does not provide compensation related services to management.
▼ Allow Hedging and Pledging. Our insider trading policy prohibits margining, derivative or speculative transactions, such as hedges, pledges and margin accounts for executive officers.
▲ Employment Agreements. We and Titan have written employment agreements with a majority of our NEOs.
Governance of Executive Compensation
Compensation Committee
The Compensation Committee is comprised solely of independent directors.
The Compensation Committee is responsible for designing our compensation objectives and methodology, and evaluating the compensation to be paid to our NEOs. The Compensation Committee is also responsible for administering our stock ownership guidelines and certain employee benefit plans, including incentive plans.
Chief Executive Officer
Our Chief Executive Officer makes recommendations to the Compensation Committee regarding the salary, bonus and incentive compensation component of each of the other NEO’s total compensation. Our Chief Executive Officer provides the Compensation Committee with key elements of our NEOs’ performance during the year or the applicable performance period to assist the committee in its determinations. Our Chief Executive Officer, at the Compensation Committee’s request, might attend committee meetings to provide insight into our NEOs’ performance, as well as the performance of other comparable companies in the same industry.
Independent Compensation Consultant
Since 2015, our Compensation Committee has engaged Mercer (US) Inc., a global compensation and benefits consulting firm and wholly-owned subsidiary of Marsh & McLennan Companies, Inc. (“Marsh”), to provide information and objective advice regarding executive compensation.
A critical criterion in the Atlas Energy Group Compensation Committee’s selection of Mercer to provide executive and director compensation consulting services was that Mercer does not provide any other executive compensation consulting services to us or our affiliated companies other than insurance brokerage services provided by its parent company, Marsh. Atlas Energy Group directors and officers are also required to complete questionnaires on an annual basis, which allows us to review whether there are any potential conflicts as a result of personal or business relationships. There were no business or personal relationships between the consultants from Mercer who work with us and our directors and executive officers other than the executive compensation consulting described herein. The Committee also determined that the reporting relationship and the compensation of Mercer were separate from, and not determined by reference to Mercer’s or Marsh’s other lines of business or any other work for us. Further, the Committee is aware that in the ordinary course of business we use Marsh’s insurance broker services, but it does not monitor or approve those services. Mercer’s fees for executive compensation consulting services provided to the Compensation Committee in 2016 were $129,365. The commission paid for Marsh’s insurance broker services were $624,973.
Timing of Compensation Decision Process
In April 2016, the Compensation Committee approved retention bonuses for certain senior members of management including Mr. Slotterback, who was the only NEO who received such a retention bonus. In granting the bonuses, the Committee recognized the importance of retaining senior employees amidst the uncertainty facing the energy industry. In May 2016, in consultation with Mercer, the Committee approved the 2016 performance measurements under the Annual Incentive Plan for Senior Executives (the “Senior Executive Plan”). The 2016 performance measurements under the Senior Executive Plan were to be evaluated by the Committee on a periodic basis. The Committee convened in July 2016 and determined that the NEOs were eligible for bonuses for the first two quarters.
Recognizing that his annual compensation continued to fall below the 10th percentile for the peer group and below the 25th percentile of oil and gas industry survey data for chief financial officers in the peer group, in October 2016, the Compensation Committee approved an increase in Mr. Slotterback’s annual base salary.
In March 2017, the Committee met with Mercer and determined that the NEOs had successfully achieved the performance measurements for the second two quarters of 2016 and approved payment of the bonuses for those quarters as well.
Elements of Our Compensation Program
Component
Type of pay
Purpose
Key characteristics
Base salary
Fixed
Provide fixed compensation for performance of core duties that contribute to our success. Not intended to compensate for achievement of performance metrics or for extraordinary performance.
Fixed compensation that is reviewed annually and adjusted if and when appropriate.
Annual (short-term) incentives
Performance-based
Motivate NEOs to achieve annual performance targets.
Performance-based cash and/or equity awards tied to pre-established performance goals.
Long-term incentives
Performance-based
Align compensation with changes in unit prices and unitholder return experience.
Time-vested phantom stock and option awards.
Base Salary
Base salary is intended to provide fixed compensation to the NEOs for their performance of core duties that contribute to our success. Base salaries represent one component of our compensation strategy and are not contingent upon the achievement of performance metrics and/or intended to compensate individuals for performance which exceeds expectations.
Annual Incentives
Annual incentives are intended to tie a significant portion of each of the NEO’s compensation to our annual performance. The Compensation Committee may recommend awards of performance-based bonuses and, on rare occasions, discretionary bonuses.
We have an Annual Incentive Plan for Senior Executives, which we refer to as the Senior Executive Plan, to award pay for achievement of predetermined performance measurements during a performance period. The applicable performance period is the current fiscal year. During the 2016 performance period, each of the NEOs participated in the Senior Executive Plan. Awards under the Senior Executive Plan may be paid in cash or in a combination of cash and time-vesting equity.
As soon as was practicable, the Compensation Committee approved the performance measurements for the 2016 performance period. In recognizing current circumstances with respect to the energy industry, the Compensation Committee adopted a performance formula that would be evaluated by the Compensation Committee on a quarterly basis with respect to each NEO. The Committee determined that the most critical measurement, which was to be given the greatest weight, was the performance with respect to negotiating with stakeholders including, but not limited to: bond holders, second lienholders, banks, other lenders, vendors, service providers and other general creditors; and other persons or entities who are or may be operationally, financially or strategically important to the Company. In addition to the aforementioned measurement, the Committee would also evaluate each NEO’s performance in connection with his regular and normal responsibilities, consistent with his position and past practice, including but not limited to cost control operationally and/or administratively, financial performance of Atlas Energy Group during the period, private channel fund raise, hedge position values, production margin performance and environmental performance
Pursuant to the Senior Executive Plan, the Compensation Committee had discretion to recommend awards up to the maximum amount. The maximum award on an annual basis, for each participant was as follows: Mr. E. Cohen, $1,600,000; Mr. J. Cohen, $1,200,000; Mr. Herz, $1,200,000; Mr. Schumacher, $1,000,000; and Mr. Slotterback, $800,000. As discussed in greater detail below, none of the NEOs received above 71% of the maximum award.
Exceptional Bonuses
In exceptional circumstances, additional bonuses may be awarded to recognize individual and group performance without regard to limitations otherwise in effect. Other than Mr. Slotterback, who received a retention bonus in April 2016, the Compensation Committee did not award any additional bonuses to the NEOs with respect to our performance for the applicable performance period.
Long-Term Incentives
We believe that our long-term success depends upon aligning our executives’ and unitholders’ interests. To support this objective, we provide our executives with various means to become significant equity holders, including awards under our 2015 Long-Term Incentive Plan (the “Atlas Energy Group Plan” or “our Plan”). Under the Atlas Energy Group Plan, the Compensation Committee may recommend grants of equity awards in the form of options and/or phantom units. Generally, the unit options and phantom units vest over a three- or four-year period.
Until September 1, 2016, our NEOs were also eligible to receive awards under the Atlas Resource Partners, L.P. 2012 Long-Term Incentive Plan, which we refer to as the ARP Plan. Since September 1, 2016, our NEOs are eligible to receive awards under the Titan Energy Management Incentive Plan, which we refer to as the Titan MIP; however, awards under the Titan MIP to our NEOs are determined by the Titan Energy Board.
Additional Information Concerning Executive Compensation
Deferred Compensation
All our employees may participate in our 401(k) plan, which is a qualified defined contribution plan designed to help participating employees accumulate funds for retirement. In February 2015, we also assumed the Atlas Energy Executive Excess 401(k) Plan (currently known as the “Deferred Compensation Plan”), a nonqualified deferred compensation plan that was designed to permit individuals who exceeded certain income thresholds as established by the IRS and who might be subject to compensation and/or contribution limitations under what was then the Atlas Energy 401(k) plan and is now the Atlas Energy Group 401(k) Plan to defer an additional portion of their compensation. Effective July 22, 2016, we suspended deferrals and allocations to the accounts; however, the account balances remain payable as specified in original deferral elections. The purpose of the Deferred Compensation Plan was to provide participants with an incentive for a long-term career with us by providing them with an appropriate level of replacement income upon retirement. Under the Deferred Compensation Plan, a participant was permitted to contribute to an account an amount up to 10% of annual cash compensation (which means a participant’s salary and non-performance-based bonus) and up to 100% of all performance-based bonuses. Until the suspension in July 2016, we were obligated to make matching contributions on a dollar-for-dollar basis of the amount deferred by the participant subject to a maximum matching contribution equal to 50% of the participant’s base salary for any calendar year. We did not pay above-market or preferential earnings
on deferred compensation. Participation in the Deferred Compensation Plan is available pursuant to the terms of an individual’s employment agreement or at the designation of the Compensation Committee. During 2016, Messrs. E. Cohen and J. Cohen were the only participants in the Deferred Compensation Plan. For further details, please see “2016 Nonqualified Deferred Compensation” table.
Unit Ownership Guidelines for NEOs
The Compensation Committee established unit ownership guidelines for our NEOs pursuant to which these executives are expected to hold a minimum number of our common units equal to a specified multiple of their annual base salaries, as follows:
Position
Required ownership multiple(1)
Chief Executive Officer
Five (5) times annual base salary
Executive Chair
Four (4) times annual base salary
President
Three (3) times annual base salary
Chief Financial Officer
Three (3) times annual base salary
Executive Vice Presidents
Three (3) times annual base salary
Senior Vice Presidents
Two (2) times annual base salary
_____________________
(1)
The number of equity units necessary to reach the required ownership multiple was calculated based upon the fair market value of the units when the plan was implemented or at the time the executive was promoted to serve as an NEO.
Equity interests that count toward the satisfaction of the ownership guidelines include common units held directly or indirectly by the executive, including common units purchased on the open market or acquired upon the exercise of a unit option and common units remaining or received upon the settlement of restricted stock, restricted stock units, and phantom units, and vested units allocated to the executive’s account under any qualified plan. Executives have five years from the date of the commencement of the guidelines or the date the executive was designated a covered executive by the Compensation Committee, whichever was later, to attain these ownership levels. Executives who become subject to the guidelines as the result of a promotion, have three years to attain the ownership level. If an executive officer does not meet the applicable guideline by the end of the applicable period, the executive officer may be required to hold any net shares resulting from any future vesting of restricted or phantom units or exercise of stock options until the guideline is met. The Compensation Committee believes these guidelines reinforce the importance of aligning the interests of our executive officers with the interests of our unitholders and encourages our executive officers to consider the long-term perspective when managing our company. The Compensation Committee has the discretion to re-evaluate and revise an executive’s target ownership requirement in light of changes in the executive’s annual base salary or changes in the trading price of our common units.
No Hedging Of Company Stock
All of our employees are prohibited from hedging their company stock.
No Tax Gross-Ups
We do not provide tax reimbursements to our NEOs.
Perquisites
At the discretion of the Compensation Committee, we provide perquisites to our NEOs. In 2016, the benefits provided to the NEOs were limited to providing automobile allowances or automobile-related expenses to Messrs. E. Cohen, Herz and Schumacher.
Consulting Agreement with Mr. J. Cohen
We acquired Atlas Energy’s direct and indirect ownership interests in the Lightfoot entities as part of the assets and liabilities it acquired in connection with the Targa transaction. As part of the transaction, we also assumed the obligations under an agreement pursuant to which Mr. J. Cohen receives compensation in recognition of his role in negotiating and structuring its investment and his continued service as chair of Lightfoot GP. Pursuant to the agreement, Mr. J. Cohen receives an amount equal to 10% of the distributions that we receive from the Lightfoot entities, excluding amounts that constitute a return of capital.
Determination of 2016 Compensation Amounts
Given the transformative events of the 2016 fiscal year, the determination of the components of the 2016 compensation amounts for our NEOs took place over different times during the year. Early in 2016, at the same time that it evaluated our NEOs’
performance under the metrics that had been established pursuant to the Senior Executive Plan, the Compensation Committee adjusted the base salaries of Messrs. E. Cohen and J. Cohen to levels that were at the median of, and Mr. Herz to a level that was competitive with, the peer group that had been approved by the board and from which Mercer had developed a competitive market assessment.
The Compensation Committee consulted with Mercer over the course of the rest of 2016 with respect to retention bonuses for various senior officers including Mr. Slotterback, developing the 2016 performance metrics under the Senior Executive Plan, and increasing Mr. Slotterback’s base salary.
Because the 2016 performance metrics were analyzed on a periodic basis, in July 2016 and then again in February and March 2017, the Compensation Committee consulted with Mercer, with our Chief Executive Officer participating, to evaluate our performance and to approve short-term incentive awards to NEOs. In July 2016, prior to ARP’s bankruptcy, the Compensation Committee approved short-term incentive awards for the first two quarters of 2016. In February 2017, as the Committee prepared to evaluate the NEOs’ performance under the Senior Executive Plan with respect to the last two quarters of 2016, at the Committee’s request, Mercer provided the Committee with an analysis of the proposed short-term incentive awards under the Senior Executive Plan and a benchmark of the NEO total direct compensation for 2016.
At the request of our Compensation Committee, Mercer compiled a group comprised of 16 similarly sized oil and gas companies (the “comparison group”) that reflected, to the greatest extent possible, Atlas Energy Group’s business mix and structure following Titan’s emergence from bankruptcy. Five of the companies in the group were part of the 2015 peer group that was utilized with respect to 2015 compensation and 2016 base salaries.
The members of the comparison group are:
Company
Revenues
(in millions)
Breitburn Energy Partners LP
$521
SandRidge Energy, Inc.
$428
Sanchez Energy Corporation
$415
Vanguard Natural Resources, LLC
$392
Carrizo Oil & Gas, Inc.
$382
Legacy Reserves LP
$303
Black Stone Minerals, L.P.
$250
EXCO Resources, Inc.
$235
Eclipse Resources Corporation
$217
Bonanza Creek Energy Inc.
$205
EV Energy Partners, L.P.
$173
Comstock Resources, Inc.
$169
Bill Barrett Corporation
$163
Clayton Williams Energy, Inc.
$158
Penn Virginia Corporation
$152
Jones Energy, Inc.
$118
Comparison Group Summary Statistics
Maximum
$521
75th Percentile
$389
50th Percentile
$226
25th Percentile
$165
Minimum
$118
Atlas Energy Group/Titan Energy1
$298
Percentile Rank
64%
Combined revenues of Titan and Atlas Energy Group, supplied to Mercer. Percentile rank of 64% indicates Atlas Energy Group/Titan Energy revenues fall between the 50th and 75th percentiles of the comparison group.
Mercer’s analysis found that total direct compensation (representing the annualized long-term incentive award value plus total cash compensation) aligns most closely with the 25th percentile for Messrs. E. Cohen, J. Cohen and Slotterback, the 50th percentile for Mr. Schumacher and at the 75th percentile for Mr. Herz.
Base Salary
In January 2016, the Compensation Committee engaged Mercer to conduct an analysis of historical short-term incentives and benchmarking of base salaries of all of our NEOs using a market competitive assessment against a peer group of then-comparable energy companies (the “2015 peer group”). The Compensation Committee considered the analysis and benchmarking and approved increases to Messrs. E. Cohen and J. Cohen’s base salaries to $700,000 and $500,000, respectively, bringing their base salaries to the median of the 2015 peer group. The Committee recognized the further increased role that Mr. Herz had undertaken in challenging times and approved an increase in his 2016 base salary to $500,000, an amount that was competitive with the 2015 peer group. The Committee maintained the base salaries of Messrs. Slotterback and Schumacher at 2015 levels. Mr. Slotterback’s base salary was below the median of the peer group and Mr. Schumacher’s base salary was competitive with the median. In October 2016, however, upon further consultation with Mercer, and based upon benchmarking against the 2015 peer group as well as against an executive remuneration survey for the oil and gas industry, the Committee authorized the increase to $350,000 of Mr. Slotterback.
In February 2017, the Committee did not make further adjustments to the 2017 base salaries of the NEOs.
Annual Incentives
Following the first half of the 2016 fiscal year and again after the end of the 2016 fiscal year, the Compensation Committee considered incentive awards pursuant to the Senior Executive Plan based on our performance during the 2016 performance period. In determining the actual amounts to be paid to our NEOs, the Compensation Committee considered both individual and company performance. Our Chief Executive Officer made recommendations of incentive award amounts based upon our performance as well as the performance of our subsidiaries; however, the Compensation Committee had the discretion to approve, reject or modify the recommendations. Further, the Committee had the discretion to reduce, but not increase, the maximum awards available under the Senior Executive Plan.
The Compensation Committee noted that although 2015 was a difficult year for the oil and gas industry, 2016 was no better, but that our management had demonstrated their ability to navigate the continuing challenging market conditions. The Committee recognized that in the face of these significant challenges, the NEOs experienced great success in dealing with stakeholders during the year past. At the beginning of 2016, both the Company and Atlas Resources Partners were facing significant liquidity issues. By year-end 2016, the NEOs had resolved these crises through successful negotiation and execution involving virtually all stakeholder interests.
In evaluating the 2016 performance measurements, the Committee focused and gave great weight to the NEOs’ efforts, progress and success in negotiating with the many stakeholders. The Committee commended the NEOs for successfully securing agreement amongst our lenders for a restructuring that substantially reduced cash interest expense and markedly increased covenant compliance. Even more importantly, perhaps, ARP’s creditors were persuaded (without any payment of any kind from us) to release all claims against us as general partner of the bankrupt ARP. Our NEOs were also able to preserve our 2% preferred ownership interest in Titan and significant control over Titan’s ongoing operations.
The Committee also commended the NEOs’ skill in effectuating in 2016 one of the quickest in-court restructurings ever achieved in the energy sector, working successfully with ARP’s 23 banks, two second lien holders, and 99% (by face value) of the principal holders of ARP’s unsecured notes. All these stakeholders supported management’s plan of reorganization for ARP, resulting in the birth of Titan Energy, over which our NEOs continue to exercise control.
In addition to evaluating the NEOs’ performance in dealing with stakeholders, the Committee also evaluated the NEOs’ performance with respect to their regular and normal responsibilities. The Committee noted that management had reduced general and administrative expense of the business from $81.3 million in 2015 to approximately $49.3 million in 2016. Noting that despite management’s success in effectuating such cuts and reductions, environment, health and safety compliance actually improved in 2016 as compared to 2015, although the number of operated wells across the Company had remained approximately constant. The Committee noted that we experienced a lower incident rate and fewer reportable spills in 2016 as compared to 2015. Management’s hedging activities provided approximately $216 million in net proceeds toward repayment of ARP’s first lien credit facility. On an unhedged basis, during the fourth quarter of 2016 (the first full quarter subsequent to emergence), Titan Energy realized unhedged gross margin of $1.80 per mcfe compared with $0.69 for the comparable quarter in 2015. This improvement reflected management’s ability to expand oil production (with its superior margins) as against our traditional natural gas business (with its disappointing gross margins).
The Compensation Committee took both our overall performance during the year together with the achievement of the performance measurements and, while recognizing the strong performance during challenging times, ultimately awarded short-term incentive awards that were below the maximum potential awards for each of the NEOs as follows:
Named Executive Officer
Maximum
potential
awards
Actual
awards
Actual awards as percentage of maximum potential awards
Edward E. Cohen
$1,600,000
$950,000
59 %
Jeffrey M. Slotterback
$800,000
$537,500
67 %
Jonathan Z. Cohen
$1,200,000
$850,000
71 %
Daniel C. Herz
$1,200,000
$850,000
71 %
Mark D. Schumacher
$1,000,000
$587,500
59 %
Long-Term Incentives
In an effort to maintain critical continuity of our proven NEOs and senior management team during a highly challenging environment, in October 2016, the Compensation Committee granted Atlas Energy Group phantom units to our senior management and to the NEOs as follows: Mr. E. Cohen-200,000 phantom units; Mr. J. Cohen-200,000 phantom units; Mr. Herz-200,000 phantom units; Mr. Schumacher-100,000 phantom units; and Mr. Slotterback-100,000 phantom units. These awards are to vest one-third on each anniversary of the grant. The Compensation Committee recognized that such continuity grants were critical to retention of executives and other employees even in a “soft” energy market. In February 2017, our board approved the deferral until March 1, 2018 of the vesting of all phantom units granted to officers and employees under our Plan that had previously been scheduled to vest during 2017. Our board determined the deferral was in our best interests as we continue to evaluate options regarding changes to our debt or equity capital structure.
Targa Transaction Incentives and Related Compensation
In addition, in connection with the Targa transactions, outstanding Atlas Energy and APL equity awards held by our employees generally, including our Named Executive Officers, were adjusted, cancelled, converted, or settled pursuant to the applicable terms of the merger agreement. ARP equity awards were not adjusted in connection with the Targa transactions and remained outstanding in accordance with their respective terms until the ARP bankruptcy, when all of ARP’s outstanding equity was cancelled. Messrs. E. Cohen, J. Cohen and Herz received termination payments in connection with certain employment agreements which were terminated as a result of the merger.
COMPENSATION OF NAMED EXECUTIVE OFFICERS
THE SUMMARY COMPENSATION TABLE BELOW INCLUDES PAYMENTS MADE IN CONNECTION WITH THE $7.7 BILLION TARGA TRANSACTIONS. THE FOOTNOTES TO THE SUMMARY COMPENSATION TABLE DELINEATE WHICH AMOUNTS ARE ATTRIBUTABLE TO THE TARGA TRANSACTION.
SUMMARY COMPENSATION TABLE
Name
Year
Salary
($)
Bonus
($)
Stock awards ($)(1)
Option awards ($)(2)
Non-equity incentive plan compensation
($)
All other compensation
($)
Total
($)
Edward E. Cohen
700,000
869,555
950,000(3)
150,886(4)
2,670,441
475,000
1,607,500
300,000
72,453,196(5)
74,835,696
1,000,000
17,812,798
2,000,000
4,178,447
24,991,245
Jeffrey M. Slotterback
280,192
300,000
367,835
537,500(3)
75(6)
1,485,602
205,384
225,050
300,000
735,912(7)
1,466,347
Jonathan Z. Cohen
500,000
869,555
850,000(3)
321,239(8)
2,540,794
417,308
1,607,500
250,000
63,058,149(9)
65,332,956
700,000
17,312,821
2,000,000
3,766,497
23,779,318
Daniel C. Herz
500,000
869,555
850,000(3)
9,600(10)
2,229,155
325,000
1,607,500
1,000,000
14,975,844(11)
17,908,343
392,308
750,000
5,844,469
1,042,524
8,029,301
Mark D. Schumacher
375,000
367,835
587,500(3)
11,991(12)
1,342,326
375,000
1,125,250
500,000
1,680,655(13)
3,680,905
____________
(1)
For fiscal year 2016, the amounts reflect the grant date fair value of the phantom units under the Atlas Energy Group Plan and the grant date fair value of the common shares under the Titan Plan. The grant date fair value was determined in accordance with FASB ASC Topic 718 and is based on the market value on the grant date of Atlas Energy Group units and Titan stock. See “Compensation Discussion & Analysis-Determination of 2016 Compensation Amounts-Long-Term Incentives.” For fiscal year 2015, the amounts reflect the grant date fair value of the phantom units under the Atlas Energy Group Plan. The grant date fair value was determined in accordance with FASB ASC Topic 718 and is based on the market value on the grant date of Atlas Energy Group units. For fiscal year 2014, the amounts reflect the grant date fair value of the phantom units under the Atlas Energy Plans and the Atlas Pipeline Partners Plans (the “APL Plans”). The grant date fair value was determined in accordance with FASB ASC Topic 718 and is based on the market value on the grant date of Atlas Energy units (February 2014 and June 2014) and Atlas Pipeline Partners units (February 2014 and June 2014 for Messrs. E. Cohen, J. Cohen, and Herz).
(2)
The amounts in this column reflect the grant date fair value of options awarded under the Atlas Resource Partners Plan (the “ARP Plan”) calculated in accordance with FASB ASC Topic 718.
(3)
Atlas Energy’s compensation committee, advised by its independent consultant Mercer, has approved payments of the amounts listed above. These payments are still under consideration by Titan’s board and Titan’s conflict committee.
(4)
Includes a matching contribution of $148,077 under the Atlas Energy Deferred Compensation Plan and tax, title and insurance premiums for Mr. E. Cohen’s automobile.
(5)
Comprised of (i) payments on DERs of $317,237 with respect to the phantom units awarded under the Atlas Energy Plans, (ii) payments on DERs of $29,490 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $100,800 with respect to the phantom units awarded under the APL Plans, (iv) a matching contribution of $524,423 under the Atlas Energy Deferred Compensation Plan, (v) tax, title and insurance premiums for Mr. E. Cohen’s automobile. The “All Other Compensation” amount also includes payments related to the Targa transaction as follows: (i) cash-out of Atlas Energy and APL equity awards of 38,463,425, (ii) cash severance of $32,538,286; and (iii) a pro-rated cash annual incentive of $476,712.
(6)
Represents payments on DERs of $75 with respect to the phantom units awarded under the ARP Plan.
(7)
Comprised of (i) payments on DERs of $8,168 with respect to the phantom units awarded under the Atlas Energy Plans and (ii) payments on DERs of $3,148 with respect to the phantom units awarded under the ARP Plan. The “All Other Compensation” amount also includes a cash-out of Atlas Energy equity awards of $629,597 related to the Targa transaction.
(8)
Comprised of (i) a matching contribution of $ 133,846 under the Atlas Energy Deferred Compensation Plan, and (ii) 187,393 paid under the agreement relating to Lightfoot.
(9)
Comprised of (i) payments on DERs of $289,181 with respect to the phantom units awarded under the Atlas Energy Plans, (ii) payments on DERs of $29,490 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $100,800 with respect to the phantom units awarded under the APL Plans, (iv) a matching contribution of $ 375,577 under the Atlas Energy Deferred Compensation Plan, and (v) 284,707 paid under the agreement relating to Lightfoot. The “All Other Compensation” amount also includes payments related to the Targa transaction as follows: (i) cash-out of Atlas Energy and APL equity awards of 30,613,393, (iii) cash severance of $ 30,888,289; and (iii) a pro-rated cash annual incentive of $476,712.
(10)
Represents an automobile allowance.
(11)
Comprised of (i) payments on DERs of $122,713 with respect to the phantom units awarded under the Atlas Energy Plans, (ii) payments on DERs of $13,762 with respect to the phantom units awarded under the ARP Plan, (iii) payments on DERs of $ 36,640 with respect to the phantom units awarded under the APL Plans, and (iv) an automobile allowance. The “All Other Compensation” amount also includes payments related to the Targa transaction as follows: (i) cash-out of Atlas Energy and APL equity awards of 11,926,461, (ii) cash severance of $2,866,667; and (iii) a pro-rated cash annual incentive of $182,740.
(12)
Comprised of (i) payments on DERs of $2,390 with respect to the phantom units awarded under the ARP Plan, and (ii) an automobile allowance.
(13)
Comprised of (i) payments on DERs of $24,858 with respect to the phantom units awarded under the Atlas Energy Plans, (ii) payments on DERs of $96,255 with respect to the phantom units awarded under the ARP Plan; and (iii) an automobile allowance. The “All Other Compensation” amount also includes a cash-out of Atlas Energy equity awards of $1,549,943 related to the Targa transaction.
2016 GRANTS OF PLAN-BASED AWARDS
_______________
(1)
Represents performance-based bonuses under our Senior Executive Plan that may be paid in cash and/or equity. As discussed under “Compensation Discussion and Analysis-Elements of our Compensation Program-Annual Incentives,” our Compensation Committee set performance measurements for the NEOs. The Compensation Committee did not award any equity awards under the Senior Executive Plan.
(2)
Represents phantom units granted under the Atlas Energy Group Plan.
(3)
Represents restricted and unrestricted shares granted under the 2016 Titan Management Incentive Plan.
(4)
The grant date fair value was calculated in accordance with FASB ASC Topic 718
Employment Agreements and Potential Payments Upon Termination or Change of Control
We have employment agreements with certain of our NEOs that provide for severance compensation to be paid if such NEO’s employment is terminated under certain conditions.
Atlas Employment Agreements
On September 4, 2015, we and ARP entered into employment agreements with each of Edward E. Cohen, our Chief Executive Officer, Jonathan Z. Cohen, our Executive Chairman of the board of directors, Daniel C. Herz, our President, and Mark Schumacher, our Senior Vice President (collectively, the “Atlas Employment Agreements”).
The Atlas Employment Agreements with Messrs. E. Cohen and J. Cohen each provide for a term of three years (which automatically renews daily unless earlier terminated) and an initial base salary of $350,000, subject to periodic increases by the compensation committee. The Atlas Employment Agreements with Messrs. Herz and Schumacher each provide for a term of two years (which automatically renews daily for one-year terms after the first anniversary of the effective date of the agreement unless earlier terminated) and an initial base salary of $350,000 (in the case of Mr. Herz) and $375,000 (in the case of Mr. Schumacher), subject to increases, but not decreases, by the compensation committee.
Under the Atlas Employment Agreements, Messrs. E. Cohen and J. Cohen are entitled to receive cash and non-cash bonus compensation in such amounts as our board or compensation committee may approve or under the terms of any incentive plan that we maintain for our senior level executives. We are required to maintain a term life insurance policy for each of Mr. E. Cohen’s and Mr. J. Cohen’s respective lives that each separate policy provide a death benefit of $3 million to one or more beneficiaries designated by Messrs. E. Cohen and J. Cohen respectively, which such policy, at each individual’s request, can be assumed by such individual upon a termination of employment, if and as allowed by the applicable insurance company.
Pursuant to the Atlas Employment Agreements, Messrs. Herz and Schumacher are each entitled to receive a bonus determined in accordance with procedures established by our board or compensation committee. In addition Messrs. Herz and Schumacher are each eligible to receive grants of equity-based compensation as determined by our board or compensation committee.
Under the Atlas Employment Agreements, if the executive is terminated without cause or resigns with good reason, then, subject to his execution and non-revocation of a release of claims in favor of us and related parties, the executive will be entitled to receive (a) two times (or three times in the case of Messrs. E. Cohen and J. Cohen) the sum of the executive’s base salary plus his average incentive compensation for the previous three years (or such lesser period as applicable), (b) a pro rata cash bonus for the year of termination, (c) 24 months of continued health insurance (or 36 months in the case of Messrs. E. Cohen and J. Cohen of continued health and life insurance), and (d) accelerated vesting of all equity-based compensation.
Pursuant to the Atlas Employment Agreements, in the event of death, Messrs. E. Cohen and J. Cohen are each entitled to receive (a) a pro rata cash bonus for the year of termination and (b) accelerated vesting of all equity-based compensation. Under the Atlas Employment Agreements, in the event of disability, Messrs. E. Cohen and J. Cohen are each entitled to receive (a) a pro rata
cash bonus for the year of termination, (b) 36 months of life and health insurance, and (c) accelerated vesting of all equity-based compensation.
Under the Atlas Employment Agreements, in the event of death or disability, Messrs. Herz and Schumacher are each entitled to receive (a) a pro rata cash bonus for the year of termination, (b) 12 months of continued health insurance for the executive and his dependents, and (c) accelerated vesting of all equity-based compensation.
In addition, the Atlas Employment Agreements each contain certain restrictive covenants, including (a) in the case of Messrs. E. Cohen and J. Cohen, a 12 month post termination noncompetition covenant and 24 month post termination nonsolicitation covenant if the executive is terminated with cause or resigns without good reason, (b) in the case of Mr. Herz an 18 month post termination noncompetition covenant and a 24 month post termination nonsolicitation covenant if the executive is terminated without cause or resigns without good reason, and (c) in the case of Mr. Schumacher, an 18 month post termination noncompetition covenant and 24 month post termination nonsolicitation covenant, if prior to a change in control or after the first anniversary of a change in control, the executive is terminated with cause or resigns without good reason, or within one year following a change in control, the executive’s employment terminates for any reason.
Under each of the Atlas Employment Agreements, any payments or benefits payable to the executive will be cutback to the extent that such payments or benefits would result in the imposition of excise taxes under Section 4999 of the Internal Revenue Code, unless the executive would be better off on an after-tax basis receiving all such payments or benefits.
The following table provides an estimate of the value of the benefits to Mr. E. Cohen pursuant to his Atlas Employment Agreement, if a termination event had occurred as of December 31, 2016.
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$4,776,712(3)
$-
$681,215
Disability
1,776,712
37,000
681,215
Termination by us without cause or by Mr. Cohen for good reason
9,541,780(4)
37,000
681,215
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents pro rata incentive compensation and life insurance policy proceeds.
(4)
Represents pro rata incentive compensation plus three times (a) Mr. Cohen’s base salary plus (b) average incentive compensation.
The following table provides an estimate of the value of the benefits to Mr. J. Cohen pursuant to his Atlas Employment Agreement, if a termination event had occurred as of December 31, 2016.
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$4,776,712(3)
$-
$681,215
Disability
1,726,712
66,718
681,215
Termination by us without cause or by Mr. Cohen for good reason
8,816,780(4)
66,718
681,215
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents pro rata incentive compensation and life insurance policy proceeds.
(4)
Represents pro rata incentive compensation plus three times (a) Mr. Cohen’s base salary plus (b) average incentive compensation.
The following table provides an estimate of the value of the benefits to Mr. Herz pursuant to his Atlas Employment Agreement, if a termination event had occurred as of December 31, 2016.
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$1,582,740
$ 22,144
$681,215
Disability
1,582,740
22,144
681,215
Termination by us without cause or by Mr. Herz for good reason
4,915,480(3)
44,288
681,215
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents two times (a) Mr. Herz’s base salary plus (b) average incentive compensation.
The following table provides an estimate of the value of the benefits to Mr. Schumacher, pursuant to his Atlas Employment Agreement, if a termination event had occurred as of December 31, 2016:
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$500,000
$22,239
$331,957
Disability
500,000
22,239
331,957
Termination by us without cause or by Mr. Schumacher for good reason
2,012,500(3)
44,479
331,957
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents two times (a) Mr. Schumacher’s base salary plus (b) average incentive compensation.
Titan Employment Agreements
On September 1, 2016, Titan Energy and Titan Energy Operating, LLC, a Delaware limited liability company, entered into employment agreements with each of Messrs. E. Cohen, its Executive Chairman, J. Cohen, its Executive Vice Chairman, Herz, its Chief Executive Officer, and Schumacher, its President (collectively, the “Titan Employment Agreements”). The Titan Employment Agreements and compensation thereunder are not intended to duplicate that provided under the Atlas Employment Agreements.
The Titan Employment Agreements for Messrs. E. Cohen and J. Cohen each have an initial term of three years and the Titan Employment Agreements for Messrs. Herz and Schumacher each have an initial term of two years, in each case subject to early termination under certain circumstances. Each of the Titan Employment Agreements contain automatic daily extensions of the term; the term of the Titan Employment Agreements for Messrs. E. Cohen and J. Cohen are extended by one day each day so that the remaining term remains at three years and the term of the Titan Employment Agreements for Messrs. Herz and Schumacher are also extended for an additional day on a daily basis commencing on September 1, 2017 (unless, in the case of Messrs. Herz and Schumacher, Titan Energy gives written notice to the executive following September 1, 2017 that the term will not be so extended). Under the Titan Employment Agreements, the annual base salaries for each of Messrs. E. Cohen, J. Cohen, Herz and Schumacher are $700,000, $500,000, $500,000 and $375,000, respectively, and for each of 2016 and 2017 each executive will receive an annual bonus of at least 100% of his annual salary, payable in a combination of cash and equity (subject to certain restrictions regarding the composition of the bonus, as set forth in the Titan Employment Agreements). We are required to maintain a term life insurance policy for each of Mr. E. Cohen’s and Mr. J. Cohen’s respective lives that each separate policy provide a death benefit of $3 million to one or more beneficiaries designated by Messrs. E. Cohen and J. Cohen respectively, which such policy, at each individual’s request, can be assumed by such individual upon a termination of employment, if and as allowed by the applicable insurance company.
Under the Titan Employment Agreements, if the executive is terminated without cause or resigns with good reason, then, subject to his execution and non-revocation of a release of claims in favor of us and related parties, the executive will be entitled to receive (a) two times (or three times in the case of Messrs. E. Cohen and J. Cohen) the sum of the executive’s base salary plus his average incentive compensation for the previous two years, (b) a pro rata cash bonus for the year of termination, (c) 24 months of continued health insurance (or 36 months in the case of Messrs. E. Cohen and J. Cohen of continued health and life insurance), and (d) accelerated vesting of all equity-based compensation. In addition, if Messrs. E. Cohen or J. Cohen is terminated without cause or resigns in good reason in connection with a change in control, then the severance payable in (a) as stated above shall not exceed an amount equal to $5,000,000 reduced by the fair market value as of the date of such change in control of any unvested equity awards held by Messrs. E Cohen and J. Cohen, but in no event shall such amount of severance payable in (a) be reduced below $2,000,000.
The Titan Employment Agreements contain the same death and disability provisions for the executives as outlined above in the summary of the death and disability provisions of the Atlas Employment Agreements.
Each of the Titan Employment Agreements contains restrictive covenants applicable to the executive officers with respect to noncompetition and nonsolicitation that are similar to such provisions in the Atlas Employment Agreements.
In addition, Under each of the Titan Employment Agreements, any payments or benefits payable to the executive will be cutback to the extent that such payments or benefits would result in the imposition of excise taxes under Section 4999 of the Internal Revenue Code, unless the executive would be better off on an after-tax basis receiving all such payments or benefits.
The following table provides an estimate of the value of the benefits to Mr. E. Cohen pursuant to his Titan Employment Agreement, if a termination event had occurred as of December 31, 2016.
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$3,821,370(3)
$-
$357,215
Disability
1,421,370
29,600
357,215
Termination by us without cause or by Mr. Cohen for good reason
7,633,424(4)
29,600
357,215
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents pro rata incentive compensation and life insurance policy proceeds allocated to Titan.
(4)
Represents pro rata incentive compensation plus three times (a) Mr. Cohen’s base salary plus (b) average incentive compensation allocated to Titan.
The following table provides an estimate of the value of the benefits to Mr. J. Cohen pursuant to his Titan Employment Agreement, if a termination event had occurred as of December 31, 2016.
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$3,781,370(3)
$-
$357,215
Disability
1,381,370
53,374
357,215
Termination by us without cause or by Mr. Cohen for good reason
7,053,424(4)
53,374
357,215
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents pro rata incentive compensation and life insurance policy proceeds allocated to Titan.
(4)
Represents pro rata incentive compensation plus three times (a) Mr. Cohen’s base salary plus (b) average incentive compensation allocated to Titan.
The following table provides an estimate of the value of the benefits to Mr. Herz pursuant to his Titan Employment Agreement, if a termination event had occurred as of December 31, 2016.
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$1,266,192
17,715
$357,215
Disability
1,266,192
17,715
357,215
Termination by us without cause or by Mr. Herz for good reason
3,932,384(3)
35,431
357,215
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents two times (a) Mr. Herz’s base salary plus (b) average incentive compensation allocated to Titan.
The following table provides an estimate of the value of the benefits to Mr. Schumacher, pursuant to his Titan Employment Agreement, if a termination event had occurred as of December 31, 2016:
Reason for termination
Lump sum severance payment
Benefits(1)
Accelerated vesting of unit awards and option awards(2)
Death
$400,000
$17,791
$133,957
Disability
400,000
17,791
133,957
Termination by us without cause or by Mr. Schumacher for good reason
1,610,000(3)
35,583
133,957
_____________________
(1)
Dental and medical benefits were calculated using 2016 COBRA rates.
(2)
Represents the value of unvested unit awards disclosed in the “2016 Outstanding Equity Awards at Fiscal Year-End” table. Calculated by multiplying the number of accelerated units by the closing price of the applicable unit on December 31, 2016.
(3)
Represents two times (a) Mr. Schumacher’s base salary plus (b) average incentive compensation allocated to Titan.
Long-Term Incentive Plans
2015 Long-Term Incentive Plan
In February 2015, we adopted the Atlas Energy Group, LLC 2015 Long-Term Incentive Plan, which we refer to as the “2015 LTIP.” The following is a brief description of the principal features of the 2015 LTIP.
Purpose
The 2015 LTIP is intended to promote our interests by providing to our officers, employees, and directors, employees of our affiliates, consultants, and joint venture partners who perform services for us incentive awards for superior performance that are based on our common units. The 2015 LTIP is intended to enhance our ability to attract and retain the services of individuals who are essential for our growth and profitability, and to encourage them to devote their best efforts to our business and advancing our interests.
Administration
Grants made under the 2015 LTIP are determined by our board of directors or a committee of the board of appointed by the board of directors to administer the 2015 LTIP. Our board has appointed the Compensation Committee to administer the 2015 LTIP, which we refer to as the “committee.”
Subject to the provisions of the 2015 LTIP, the committee is authorized to administer and interpret the 2015 LTIP, to make factual determinations, and to adopt or amend its rules, regulations, agreements, and instruments for implementing the 2015 LTIP. The committee also has the full power and authority to determine the recipients of grants under the 2015 LTIP as well as the terms and provisions of restrictions relating to grants.
Subject to any applicable law, the committee, in its sole discretion, may delegate any or all of its powers and duties under the 2015 LTIP, including the power to award grants under the 2015 LTIP, to our Chief Executive Officer, subject to such limitations as the committee may impose, if any. However, the Chief Executive Officer may not make awards to, or take any action with respect to any grant previously awarded to, himself or a person who is subject to Rule 16b-3 under the Exchange Act.
Eligibility
Persons eligible to receive grants under the 2015 LTIP are (a) officers and employees of us, our affiliates, consultants, or joint venture partners who perform services for us or an affiliate or in furtherance of our business (we refer to each such officer and employee as an “eligible employee”) and (b) our non-employee directors.
Unit Reserve; Adjustments
Awards in respect of up to 5.25 million of our common units may be issued under the 2015 LTIP. This amount is subject to adjustment as provided in the 2015 LTIP for events such as distributions (in common units or other securities or property, including cash), unit splits (including reverse splits), recapitalizations, mergers, consolidations, reorganizations, reclassifications, and other extraordinary events affecting our outstanding common units such that an adjustment is necessary in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the 2015 LTIP. Common units issued under the 2015 LTIP may consist of newly issued common units, common units acquired in the open market or from any of our affiliates, or any other person, or any combination of the foregoing. If any award granted under the 2015 LTIP is forfeited or otherwise terminates or is cancelled or paid without the delivery of common units, then the common units covered by the award will (to the extent of the forfeiture, termination, or cancellation, as the case may be) again be available for grants of awards under the 2015 LTIP. Common units surrendered in payment of the exercise price of an option, and withheld or surrendered for payment of taxes, will not be available for re-issuance under the 2015 LTIP.
Awards
Awards granted under the 2015 LTIP may consist of options to purchase common units, phantom units, and restricted units. All grants are subject to such terms and conditions as the committee deems appropriate, including vesting conditions.
Options. An option is the right to purchase a common unit in the future at a predetermined price (which we refer to as the “exercise price”). The exercise price of each option is determined by the committee and may be equal to or greater than the fair market value of a common unit on the date the option is granted. The committee will determine the vesting and exercise restrictions applicable to an award of options, if any, and the method or methods by which payment of the exercise price may be made, which may include, without limitation, cash, check acceptable to the board of directors, a tender of common units having a fair market value equal to the exercise price, a “cashless” broker-assisted exercise, a recourse note in a form acceptable to the board of directors and that does not violate the Sarbanes-Oxley Act of 2002, a “net exercise” that permits us to withhold a number of common units that otherwise would be issued to the holder of the option pursuant to the exercise of the option having a fair market value equal to the exercise price, or any combination of the methods described above.
Phantom Units. Phantom units represent rights to receive common units, an amount of cash or other securities or property based on the value of a common unit, or a combination of common units and cash or other securities or property. Phantom units are subject to terms and conditions determined by the committee, which may include vesting restrictions. In addition, the committee may grant distribution equivalent rights in connection with a grant of phantom units. Distribution equivalent rights represent the right to receive an amount in cash, securities, or other property equal to, and at the same time as, the cash distributions or other distributions of securities or other property made by us with respect to common units during the period that the underlying phantom unit is outstanding. Distribution equivalents may (a) be paid currently or may be deferred and, if deferred, may accrue interest, (b) accrue as a cash obligation or may convert into additional phantom units for the holder of the underlying phantom units, (c) be payable based on the achievement of specific goals, and (d) be payable in cash or common units or in a combination of cash and common units, in each case as determined by the committee.
Restricted Units. Restricted units are actual common units issued to a participant that are subject to vesting restrictions and evidenced in such manner as the committee may deem appropriate, including book-entry registration or issuance of one or more unit certificates. Prior to or upon the grant of an award of restricted units, the committee will condition the vesting or transferability of the restricted units upon continued service, the attainment of performance goals, or both. Unless otherwise determined by the committee, a holder of restricted units will have certain rights of holders of our common units in general, including the right to vote the restricted units. During the period during which the restricted units are subject to vesting restrictions, however, the holder will not be permitted to sell, assign, transfer, pledge, or otherwise encumber the restricted units. As determined by the committee, cash dividends on restricted units may be automatically deferred or reinvested in additional restricted units and held subject to the vesting of the underlying restricted units, and dividends payable in common units may be paid in the form of restricted units of the same class as the restricted units with respect to which the dividend is paid and may be subject to vesting of the underlying restricted units.
Change in Control
Individual
Triggering event
Acceleration
Eligible employees
Change of Control (as defined in the 2015 LTIP), and
Termination of employment without “cause” as defined in the 2015 LTIP or upon any other type of termination specified in the applicable award agreement(s), following a change of control
Unvested awards immediately vest in full and in the case of options, become exercisable for the one-year period following the date of termination (but not later than the end of the original term of the option)
Independent directors
Change of Control (as defined in the 2015 LTIP)
Unvested awards immediately vest in full
No Assignment
Except as otherwise determined by the committee, no award granted under the 2015 LTIP is assignable or transferable except by will or the laws of descent and distribution. When a participant dies, the personal representative or other person entitled to succeed to the rights of the participant may exercise the participant’s rights under his or her awards.
Withholding
All awards granted under the 2015 LTIP are subject to applicable federal (including FICA), state, and local tax withholding requirements. If we so permit, common units may be withheld to satisfy tax withholding obligations with respect to awards paid in common units, at the time such awards become subject to employment taxes and tax withholding, as applicable, up to an amount that does not exceed the minimum required withholding for federal (including FICA), state, and local tax liabilities. We may require forfeiture of any award for which the participant does not timely pay the applicable withholding taxes.
Amendment and Termination
Subject to the limitations described below, the committee may amend, alter, suspend, discontinue, or terminate the 2015 LTIP at any time without the consent of participants, except that the committee may not amend the 2015 LTIP without approval of the unitholders if such approval is required in order to comply with applicable stock exchange requirements. We may waive any conditions or rights under, amend any terms of, or alter any award previously granted under the 2015 LTIP; however, no change to any award previously granted under the 2015 LTIP may materially reduce the benefit to a participant, unless the participant has consented or such change is explicitly allowed in the 2015 LTIP or the applicable award agreements. The committee may not reprice options, nor may the 2015 LTIP be amended to permit option repricing, unless the unitholders approve such repricing or amendment.
Plan Term
The 2015 LTIP will continue until the date terminated by our board of directors or the date upon which common units are no longer available for the grant of awards, whichever occurs first.
Titan Management Incentive Plan
The Amended and Restated Titan Energy, LLC Management Incentive Plan (the “MIP”) has been adopted the employees, directors and individual consultants of Titan and its affiliates. The MIP permits the grant of options, phantom shares and restricted and unrestricted common shares, as well as dividend equivalent rights. A maximum of 25% of the shares available for issuance under the MIP shall be available for issuance pursuant to incentive stock options. Subject to adjustment in accordance with the MIP, a maximum of 655,555 common shares was originally reserved for issuance pursuant to awards under the MIP. Common shares subject to forfeited awards or withheld to satisfy exercise prices or tax withholding obligations will again be available for delivery pursuant to other awards. Upon a change in control, all unvested awards held by directors shall immediately vest in full. The MIP has a term of 10 years and will be administered by the Board, which may delegate to a committee or Titan’s Chief Executive Officer.
Our Senior Executive Plan
In February 2015, we adopted the Atlas Energy Group, LLC Annual Incentive Plan for Senior Executives, which we refer to as the “Senior Executive Plan.” The following is a summary of the Senior Executive Plan.
Purpose
The Senior Executive Plan provides a means for awarding annual incentive pay, a component of our compensation program, to our senior executive employees and senior executive employees of our subsidiaries based on the achievement of performance goals over a designated performance period. The performance period is our fiscal year or any other period of up to 12 months. The objectives of the Senior Executive Plan are:
•
to enhance our ability to attract, reward and retain senior executive employees;
•
to strengthen employee commitment to our success; and
•
to align employee interests with those of our unitholders by providing compensation that varies based on our success.
Administration
The Senior Executive Plan is administered and interpreted by our Compensation Committee. The committee has the authority to establish rules and regulations relating to the Senior Executive Plan, to interpret the Senior Executive Plan and those rules and regulations, to select participants, to determine each participant’s maximum award and award amount, to approve all awards, to decide the facts in any case arising under the Senior Executive Plan, to make all other determinations, including factual determinations, and to take all other actions necessary or appropriate for the proper administration of the Senior Executive Plan, including the delegation of its authority or power, where appropriate.
Eligibility and Participation
Our senior executive employees are eligible to participate in the Senior Executive Plan. The Compensation Committee selects the senior executive employees who will participate in the Senior Executive Plan for each performance period.
Establishment of Performance Goals
As soon as practicable following the beginning of a performance period, the Compensation Committee determines the performance goals, and each participant’s maximum award for the performance period. The performance goals may provide for differing amounts to be paid based on differing thresholds of performance.
Performance Objectives
The performance goals are based on performance objectives selected by the Compensation Committee for each performance period. In each period, the committee may consider factors including performance relative to an appropriate group designated by the committee, total market return and distributions paid to unitholders, and factors related to the operation of the business, including growth of reserves, growth in production, processing and intake of natural gas, health and safety performance, environmental compliance, and risk management. The aforementioned performance criteria may be considered either individually or in any combination, applied to us as a whole, to a subsidiary, to a business unit of us or any subsidiary, to an affiliate or any subsidiary, or to any individual, measured either annually or cumulatively over a period of time. To the extent applicable, the Compensation Committee, in determining whether and to what extent a performance goal has been achieved, will use the information set forth in our audited financial statements and other objectively determinable information. The performance goals established by the committee may be (but need not be) different each performance period, and different performance goals may be applicable to different participants.
Calculation of Awards
A participant will earn an award for a performance period based on the level of achievement of the performance goals established by the Compensation Committee for that performance period. The committee may reduce or increase an award for any performance period based on its assessment of personal performance or other factors.
Payment of Awards
The Compensation Committee will certify and announce the awards that will be paid to each participant as soon as practicable following the final determination of our financial results for the relevant performance period. Payment of the awards certified by the committee will be made as soon as practicable following the close of the performance period, but in any event within 2.5 months after the close of the performance period. Awards shall be paid in cash, in equity, or in a combination thereof. Any common or phantom units may be issued under any long-term incentive plan.
Limitations on Payment of Awards
Generally, a participant must be employed on the last day of a performance period to receive payment of an award under the Senior Executive Plan. If a participant’s employment terminates before the end of the performance period, however, the Compensation Committee may determine that the participant will remain eligible to receive a prorated portion of any award that would have been earned for the performance period, in such circumstances as the committee deems appropriate. If a participant is on an authorized leave of absence during the performance period, the participant may be eligible to receive a prorated portion of any award that would have been earned, as determined by the committee.
Change in Control
Unless the Compensation Committee determines otherwise, if a “change in control” (as defined in the Senior Executive Plan) occurs before the end of a performance period, each participant will receive an award for the performance period based on performance measured as of the date of the change in control.
Amendment and Termination of Plan
The Compensation Committee has the authority to amend, modify, or terminate the Senior Executive Plan at any time. In the case of a termination of the plan, each participant may receive all or a portion of the award that would otherwise have been earned for the then-current performance period had the Senior Executive Plan not been terminated, as determined by the committee.
2016 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
_____________________
(1)
Represents restricted Titan Energy, LLC shares which will vest as follows: 9/1/2017- 24,456; 9/1/2018 - 24,456; 9/1/2019 - 25,199.
(2)
Represents Atlas Energy phantom units, which vest as follows: 3/1/2018 - 165,000; 6/8/2018 - 85,000.
(3)
Represents Atlas Energy phantom units, which vest as follows: 3/1/2018 - 132,000; 6/8/2018 - 68,000.
(4)
Represents restricted Titan Energy, LLC shares which will vest as follows: 9/1/2017- 9,171; 9/1/2018 - 9,171; 9/1/2019 - 9,450.
(5)
Represents Atlas Energy phantom units, which vest as follows: 3/1/2018 - 23,100; 6/8/2018 - 11,900.
(6)
Represents Atlas Energy phantom units, which vest as follows: 3/1/2018 - 66,000; 6/8/2018 - 34,000.
(7)
Represents Atlas Energy phantom units, which vest as follows: 3/1/2018 - 115,500; 6/8/2018 - 59,500.
2016 OPTION EXERCISES AND UNITS VESTED TABLE
_____________________
(1)
Represents Titan common shares with a fair market value of $4.82.
(2)
Comprised of 13,875 Titan common shares with a fair market value of $4.82 and 6,250 ARP common units with a fair market value of $0.74.
2016 NONQUALIFIED DEFERRED COMPENSATION
Name
Executive
contributions In the last
FY ($)
Registrant
contributions in the last
FY ($)
Aggregate
earnings
in the last
FY ($)
Aggregate
Withdrawals/Distributions ($)(1)
Aggregate
balance
at last
FYE ($)
Edward E. Cohen
35,000
35,000(2)
2,949
1,263,889
1,336,838
Jonathan Z. Cohen
26,538
26,538(3)
2,184
884,722
939,982
_____________________
(1)
Contributions are invested in a mutual fund and cash balances are invested daily in a money market account.
(2)
This amount is included within the Summary Compensation Table for 2016 reflecting our $35,000 matching contribution in the all other compensation column.
(3)
This amount is included within the Summary Compensation Table for 2016 reflecting our $26,538 matching contribution in the all other compensation column.
Effective July 1, 2011, Atlas Energy established the Atlas Energy Deferred Compensation Plan, an unfunded nonqualified deferred compensation plan for certain highly compensated employees. We assumed all of Atlas Energy’s obligations under the Atlas Energy Deferred Compensation Plan as part of the Targa transactions in February 2015, and refer to it as the Deferred Compensation Plan. The Deferred Compensation Plan provides Messrs. E. Cohen and J. Cohen, the plan’s current participants, with the opportunity to defer, annually, the receipt of a portion of their compensation, and to permit them to designate investment indices for the purpose of crediting earnings and losses on any amounts deferred under the Deferred Compensation Plan. Messrs. E. Cohen and J. Cohen may defer up to 10% of their total annual cash compensation (which means base salary and non-performance-based bonus) and up to 100% of all performance-based bonuses, and we are obligated to match such deferrals on a dollar-for-dollar basis (i.e., 100% of the deferral) up to a total of 50% of their base salary for any calendar year. Effective July 2016, we suspended deferrals and allocations to the accounts. Account balances remain payable as specified in original deferral elections. The account is invested in a mutual fund and cash balances are invested daily in a money market account. Atlas Energy established a “rabbi” trust to serve as the funding vehicle for the Deferred Compensation Plan and we will, not later than the last day of the first month of each calendar quarter, make contributions to the trust in the amount of the compensation deferred, along with the corresponding match, during the preceding calendar quarter. Notwithstanding the establishment of the rabbi trust, the obligation to pay the amounts due under the Deferred Compensation Plan constitutes a general, unsecured obligation, payable out of our general assets, and Messrs. E. Cohen and J. Cohen do not have any rights to any specific asset of our company.
The Deferred Compensation Plan has the following additional provisions:
•
At the time the participant makes his deferral election with respect to any year, he must specify the date or dates (but not more than two) on which distributions will start, which date may be upon termination of employment or a date that is at least three years after the year in which the amount deferred would otherwise have been earned. A participant may subsequently defer a specified payment date for a minimum of an additional five years from the previously elected payment date. If the participant fails to make an election, all amounts will be distributable upon the termination of employment.
•
Distributions will be made earlier in the event of death, disability or a termination of employment due to a change of control.
•
If the participant elects to receive all or a portion of his distribution upon the termination of employment, it will be paid in a lump sum. Otherwise, the participant may elect to receive a lump sum payment or equal installments over not more than 10 years.
•
A participant may request a distribution of all or part of his account in the event of an unforeseen financial emergency. An unforeseen financial emergency is a severe financial hardship due to an unforeseeable emergency resulting from a sudden and unexpected illness or accident of the participant, or a sudden and unexpected illness or accident of a dependent, or loss of the participant’s property due to casualty, or other similar and extraordinary unforeseeable circumstances arising as a result of events beyond the control of the participant. An unforeseen financial emergency is not deemed to exist to the extent it is or may be relieved through reimbursement or compensation by insurance or otherwise; by borrowing from commercial sources on reasonable commercial terms to the extent that this borrowing would not itself cause a severe financial hardship; by cessation of deferrals under the plan; or by liquidation of the participant’s other assets (including assets of the participant’s spouse and minor children that are reasonably available to the participant) to the extent that this liquidation would not itself cause severe financial hardship.
2016 DIRECTOR COMPENSATION TABLE
Name
Fees earned or paid in cash
Stock awards(1)
All other compensation
Total
Mark C. Biderman
$66,667
$39,500
$-
$106,167
DeAnn Craig
$53,333
$39,500
$-
$92,833
Dennis A. Holtz
$55,000
$39,500
$-
$94,500
Walter C. Jones
$53,125
$39,500
$-
$92,625
Jeffrey F. Kupfer
$51,875
$39,500
$-
$91,375
Ellen F. Warren
$56,667
$39,500
$-
$96,167
_____________________
(1)
Represents 50,000 phantom units granted under the 2015 LTIP having a grant date fair value of $0.79, all of which have vested.
Director Compensation
Our officers or employees who also served as directors did not receive additional compensation for their service as a director. In fiscal 2015, the annual retainer for non-employee directors was comprised of $75,000 in cash and an annual grant of phantom units with DERs under the 2015 LTIP having a fair market value of $125,000. The units will vest ratably over four years beginning on the grant date. The chair of the audit committee received an annual fee of $25,000, the chair of the compensation committee received an annual fee of $10,000, the chairs of the nominating and governance committee and investment committee each received an annual fee of $7,500 and the chair of the environment, health and safety committee received an annual fee of $5,000. However, since the directors on our board of directors also served as the board for Atlas Resource Partners, until September 2016, 50% of the fees paid in cash to the non-employee directors was allocated to Atlas Resource Partners until September 1, 2016. Following Titan’s emergence on September 1, 2016, it has its own board of directors and so we no longer allocate any director compensation.
In January 2016, after approval and recommendation from the nominating and governance committee, our board of directors reduced the annual grant of phantom units to non-employee directors to an amount having a fair market value of $50,000, which will vest 50% in 6 months from the date of grant with the remaining 50% to vest six months later. Additionally, our board of directors limited the annual grant of phantom units to our non-employee directors to 50,000 common units per year. In February 2017, the nominating and governance committee decided to maintain the cash portion of the annual compensation for 2017, but in light of our continuing evaluations of options regarding changes to our debt or equity capital structure, they temporarily suspended the equity issuance.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis with management and, based upon its review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
This report has been provided by the Compensation Committee of the Board.
Ellen F. Warren, Chair
Mark C. Biderman
Dennis A. Holtz
ITEM 12:
ITEM 12:
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
The following table sets forth (i) the number and percentage of common units owned as of April 14, 2017, (ii) the number and percentage of Series A convertible preferred units (“Series A Preferred Units”) owned as of April 14, 2017, and (iii) the total number of common units on an “as if” converted basis, assuming a conversion ratio of 3.125 common units for each Series A Preferred Unit, held by (a) each person who, to our knowledge, is the beneficial owner of more than 5% of the outstanding common units, (b) each of our present directors and nominees, (c) each of our named executive officers who served during the 2016 fiscal year, and (d) all of our directors, nominees and executive officers as a group. This information is reported in accordance with the beneficial ownership rules of the Securities and Exchange Commission under which a person is deemed to be the beneficial owner of a security if that person has or shares voting power or investment power with respect to such security or has the right to acquire such ownership within 60 days. Common units issuable pursuant to options, warrants or phantom units are deemed to be outstanding for purposes of computing the percentage of the person or group holding such options, warrants or phantom units but are not deemed to be outstanding for purposes of computing the percentage of any other person. The percentage of common units owned on an “as if” converted basis assume that all Series A Preferred Units are converted. Unless otherwise indicated in footnotes to the table, each person listed has sole voting and dispositive power with respect to the securities owned by such person.
Common unit amount and nature of beneficial ownership
Percent of class
Series A preferred unit amount and nature of beneficial ownership
Percent of class
Common units owned on an “as if” converted basis
Percent
Beneficial owner
Directors (1)
Mark C. Biderman
16,728
*
-
-
16,728
*
Edward E. Cohen
1,030,031(2)
3.9%
520,194(3)
27.5%
2,655,637
8.2%
Common unit amount and nature of beneficial ownership
Percent of class
Series A preferred unit amount and nature of beneficial ownership
Percent of class
Common units owned on an “as if” converted basis
Percent
Jonathan Z. Cohen
984,217(4)
3.7%
520,194(5)
27.5%
2,609,823
8.1%
DeAnn Craig
7,941
*
-
-
7,941
*
Dennis A. Holtz
14,122
*
-
-
14,122
*
Walter C. Jones
6,065
*
-
-
6,065
*
Jeffrey F. Kupfer
8,955
*
-
-
8,955
*
Ellen F. Warren
9,516
*
-
-
9,516
*
Named Executive Officers(1)
Daniel C. Herz
40,864(6)
*
56,745
3.0%
218,192
*
Jeffrey M. Slotterback
1,101
*
-
-
1,101
*
Mark D. Schumacher
7,375
*
-
-
7,375
*
All executive officers, directors and nominees as a group (13 persons)
1,157,982 (8)
4.4%
837,036(9)
44.3%
3,773,720
11.6%
Other owners of more than 5% of outstanding common units
Leon G. Cooperman(10)
1,287,190(11)
4.8%
945,830
50.0%
4,242,909
13.0%
Horizon Kinetics LLC(12)
3,383,030
13.0%
-
-
3,383,030
10.6%
MRM-Horizon Advisors, LLC(13)
2,579,900
9.9%
-
-
2,579,900
8.1%
Dorsey R. Gardner(14)
2,233,762
8.57%
-
-
2,233,762
7.0%
_________________
*
Less than 1%
(1)
The business address for each director, director nominee and executive officer is Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, PA 15275-1011.
(2)
Includes (i) 13,125 common units held in an individual retirement account of Mr. E. Cohen’s spouse, (ii) 33,636 common units held in trust for the benefit of Mr. E. Cohen’s spouse and/or children; (iii) 559,563 common units held by a charitable foundation of which Mr. E. Cohen, his spouse and their children are among the trustees (the “Foundation”); (iv) 151,413 warrants to purchase an equivalent number of common units held by the Foundation; (v) 50,299 common units held by Solomon Investment Partnership, L.P. (the “Partnership”), of which Mr. E. Cohen and his spouse are the sole shareholders, officers and directors of the corporate general partner and are the sole partners of the Partnership; and (vi) 151,413 warrants to purchase an equivalent number of common units held by the Partnership. Mr. E. Cohen disclaims beneficial ownership of the units described in (i) and (ii) above. 744,612 of these common units are also included in the common units referred to in footnote 4 below.
(3)
Includes 260,097 Series A Preferred Units held by the Partnership. Also includes 260,097 Series A Preferred Units held by the Foundation. The units held by the Foundation are also referred to in footnote 5 below.
(4)
Includes (i) 151,413 warrants to purchase an equivalent number of common units; (ii) 151,413 warrants to purchase an equivalent number of common units held by the Foundation; (iii) 33,636 common units held in a trust of which Mr. J. Cohen is a co-trustee and co-beneficiary and (iv) 559,563 common units held by the Foundation. 744,612 of common units are also included in the common units referred to in footnote 2 above.
(5)
This amount includes (i) 260,097 Series A Preferred Units held directly and (ii) 260,097 Series A Preferred Units held by the Foundation. The units held by the Foundation are also included in the units referred to in footnote 3 above.
(6)
Includes 32,445 warrants to purchase an equivalent number of common units.
(8)
This number has been adjusted to exclude 593,199 common units and 151,413 warrants to purchase common units which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.
(9)
This number has been adjusted to exclude 260,097 Series A Preferred Units which were included in both Mr. E. Cohen’s beneficial ownership amount and Mr. J. Cohen’s beneficial ownership amount.
(10)
The address of Mr. Cooperman is St. Andrew’s Country Club, 7118 Melrose Castle Lane, Boca Raton, FL 33496.
(11)
This information is based on a Schedule 13D/A filed on February 17, 2017. Includes 564,455 warrants to purchase an equivalent number of common units.
(12)
This information is based on a Schedule 13G/A filed on February 14, 2017 by Horizon Kinetics LLC, Horizon Asset Management, LLC, Kinetics Asset Management, LLC and Kinetics Advisers, LLC. The address of the reporting persons is 470 Park Avenue South, 4th Floor South, NY, NY, 10016.
(13)
This information is based on a Schedule 13G filed on February 14, 2017 by MRM-Horizon Advisors, LLC d/b/a Mad River Investors. The address of the reporting person is 84 State Street, Suite 800, Boston, MA 01009.
(14)
This information is based on a Schedule 13G filed on September 29, 2016 by Dorsey R. Gardner. The address of the reporting persons is 401 Worth Avenue, Palm Beach, Florida 33480.
We indirectly own 80.01% of Atlas Growth Partners, GP, LLC (“AGP GP”), and 19.99% of AGP GP is owned by current and former members of our management.
ITEM 13:
ITEM 13:
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Term Loans
On March 30, 2016, we, together with New Atlas Holdings, LLC (the “Borrower” and Atlas Lightfoot, LLC, entered into a Third Amendment (the “Third Amendment”) to that our credit agreement with Riverstone Credit Partners, L.P., as administrative agent (“Riverstone”), and the lenders (the “Lenders”) from time to time party thereto (the “First Lien Credit Agreement”).
The outstanding loans under the First Lien Credit Agreement were bifurcated between the existing First Lien Credit Agreement and the new Second Lien Credit Agreement (the “Second Lien Credit Agreement”), with $35 million and $35.8 million (including $2.4 million in deemed prepayment premium) in borrowings outstanding, respectively. In connection with the execution of the Third Amendment, the Borrower made a prepayment of approximately $4.8 million of the outstanding principal and interest.
Certain of our current and former officers are participants in approximately 12% of the loan syndication and a foundation affiliated with a 5% or more unitholder is a participant in approximately 12% of the loan syndication.
Warrants and Registration Rights Agreement
Pursuant to the terms of the Second Lien Credit Agreement, on April 27, 2016 we issued to the Lenders (including certain of our current and former officers and affiliates) warrants (the “Warrants”) to purchase an aggregate of up to 4,668,044 common units representing limited partner interests in us at an exercise price of $0.20 per unit. In connection with the issuance and sale of the Warrants, we entered into a registration rights agreement with the Lenders, dated April 27, 2016 (the “Registration Rights Agreement”), relating to the registered resale of the common units underlying the Warrants, as well as any common units issued as in-kind interest payments under the Second Lien Credit Agreement. Pursuant to the Registration Rights Agreement, we are required to file a shelf registration statement within 90 days of request by the Lenders and to use commercially reasonable efforts to cause such registration statement to become effective within 120 days of such request. In certain circumstances, the Lenders will have piggyback registration rights on certain registered offerings and will have rights to request an underwriter offering. The Lenders will cease to have rights under the Registration Rights Agreement on the later of (i) the earlier of (x) the fourth anniversary of the date on which all of such Lender’s Warrants have been exercised for common units and (y) April 27, 2026 and (ii) the earlier of (x) the date on which such Lender is no longer an “affiliate” as such term is defined in Rule 144 promulgated under the Securities Act and (y) April 27, 2026.
Our Relationship with Titan
Following the consummation of the transactions pursuant to the Plan, on September 1, 2016, weentered into a Delegation of Management Agreement (the “Delegation Agreement”) with Titan. Pursuant to the Delegation Agreement, Titan has delegated to Titan Management all of Titan’s rights and powers to manage and control the business and affairs of Titan Operating. However, Titan’s board of directors retains management and control over certain non-delegated duties.
Other than its named executive officers, Titan does not directly employ any persons to manage or operate its business. These functions are provided by our employees and affiliates, including Titan Management. In connection therewith, we and certain of our subsidiaries entered into an Omnibus Agreement (the “Omnibus Agreement”) dated September 1, 2016 with Titan. Pursuant to the Omnibus Agreement, we will provide Titan with certain financial, legal, accounting, tax advisory, financial advisory and engineering services (including cash management services) and Titan and Titan Operating will reimburse us for direct and allocable indirect expenses incurred in connection with the provision of the services, subject to certain approval rights in favor of Titan’s Conflicts Committee.
Upon termination of the Omnibus Agreement (other than due to a breach by Titan Management), Titan and Titan Operating will pay to Titan Management an amount sufficient to reimburse Titan Management for all severance and related costs it is expected to incur due to staff reduction (excluding any executive with an employment agreement with us, which executive shall receive payment under his or her employment agreement) in connection with such termination based upon the severance plans and arrangements of Titan Management and its affiliates in place at such time which shall be consistent with existing staff severance policies, subject to certain exceptions. The reimbursement obligation is subject to a cap of $14.9 million.
For the year ended December 31, 2016, Titan (and its Predecessor) reimbursed us $47.0 million for expenses, compensation and benefits.
Following the consummation of the transactions pursuant to the Plan, Titan Management, as the holder of Titan’s Series A Preferred Share, has the ability to appoint four Class A directors to Titan’s board of directors (the “Titan Board”). In addition, the holder of the Series A Preferred Share (currently Titan Management) is entitled to 2% of the aggregate of distributions paid to shareholders, subject to dilution if catch-up contributions are not made with respect to future equity issuances (other than any share split which is not a Series A Distribution or pursuant to the Titan Energy, LLC Management Incentive Plan, in each case as to which there shall be no adjustment to the percentage interest of the Series A Preferred Share). The Series A Preferred Share has voting rights identical to Titan’s common shares representing limited liability company interests (the “Titan Common Shares”) and votes as a single class with the Titan Common Shares with voting power equal to its then-applicable percentage interest; provided, that the Series A Preferred Share has no right to vote with respect to the election or removal of Class B directors or the exercise of the Preferred Share Call Right.
Common Share Issuance
On September 1, 2016, Titan issued 5,000,000 new Titan Common Shares in accordance with the Plan. The Second Lien Lenders received 500,000 Common Shares (representing 10% of the initially outstanding Common Shares). Holders of ARP’s senior notes, in exchange for 100% of the $668 million aggregate principal amount of notes outstanding plus accrued but unpaid interest as of the commencement of the Chapter 11 cases, received 4,500,000 Titan Common Shares (representing 90% of the initially outstanding Titan Common Shares). On September 1, 2016, Titan also issued the Series A Preferred Share to Titan Management.
Registration Rights Agreement
In connection with the issuance of the Titan Common Shares as of September 1, 2016 to the Second Lien Lenders and the holders of ARP’s senior notes, Titan entered into the Registration Rights Agreement, dated as of September 1, 2016, with the holders who received at least 5% of its outstanding Titan Common Shares (the “Holders”), relating to the registered resale of the Titan Common Shares. Pursuant to the Registration Rights Agreement, Titan was required to use its commercially reasonable efforts to file a shelf registration statement within 90 days of September 1, 2016 and use commercially reasonable efforts to cause such registration statement to become effective within 180 days of September 1, 2016. In certain circumstances, the Holders will have piggyback registration rights on certain registered offerings and will have rights to request underwritten offerings. The Holders will cease to have rights under the Registration Rights Agreement on the tenth anniversary of September 1, 2016.
Pursuant to the Registration Rights Agreement, Titan filed a Registration Statement on Form S-1(File No. 333-214850) on November 30, 2016, which the SEC declared effective on December 14, 2016.
Our Relationship with AGP
We indirectly own 80.01% of Atlas Growth Partners, GP, LLC (“AGP GP”), and 19.99% of AGP GP is owned by current and former members of our management.
AGP does not directly employ any persons to manage or operate its business. These functions are provided by our employees and affiliates. AGP GP receives an annual management fee in connection with its management of AGP equivalent to 1% of capital contributions per annum. During the year ended December 31, 2016, AGP paid $2.3 million for this management fee. We charge direct costs, such as salary and wages, and allocate indirect costs, such as rent for offices, to AGP by us based on the number of its employees who devoted substantially all of their time to activities on its behalf. AGP reimburses us at cost for direct costs incurred on its behalf. AGP will reimburse all necessary and reasonable costs allocated by the general partner.
Anthem is currently acting as the dealer manager for AGP’s issuance and sale in a continuous offering of up to a maximum agreement amount of 100,000,000 common units representing limited partner interests in AGP as further described in AGP’s registration statement on Form S-1 (File No. 333-207537). AGP will pay Anthem (1) compensation equal to 3.00% of the gross proceeds of the offering (Anthem may reallow up to 1.50% of gross offering proceeds it receives as dealer manager fees to participating broker-dealers, but expects to reallow 1.25% of gross offering proceeds to participating broker-dealers); (2) 7.00% and 3.00% of aggregate gross proceeds from the sale of Class A common units and Class T common units, respectively, as sales commissions; (3) with respect to Class T common units, a distribution and unitholder servicing fee in the aggregate amount of 4.00% of the gross proceeds from the sale of Class T common units, which distribution and unitholder servicing fee will be withheld from cash distributions otherwise payable to the purchasers of Class T common units at a rate of $0.025 per quarter per unit. On November 2, 2016, AGP decided to temporarily suspend its current primary offering efforts.
Drilling Partnerships
On October 24, 2016, the board of directors of Titan’s wholly owned subsidiary, Atlas Resources, LLC, approved Titan’s acquisition of properties in exchange for assuming all liabilities in connection with the liquidation of certain of the Drilling Partnerships. These acquisitions have an effective date of October 1, 2016. Titan recorded $31.0 million and $14.7 million of gas and oil properties and asset retirement obligations, respectively, resulting in non-cash gain of $22.4 million, net of consolidation and transfer adjustments, in the successor period from September 1, 2016 through December 31, 2016.
GP/LP Interest in Lightfoot
We have a 12.0% limited partner interest in Lightfoot Capital Partners, L.P. (“Lightfoot L.P.”) and a 15.9% general partner interest in Lightfoot Capital Partners GP, LLC (“Lightfoot G.P.” and together with Lightfoot L.P., “Lightfoot”), the general partner of Lightfoot L.P., an entity for which Jonathan Cohen, Executive Chairman of our board of directors, is the Chairman of the board of directors. During the year ended December 31, 2016, we received net cash distributions of $1.9 million.
Indemnification of Directors and Officers
Under our limited liability company agreement, in most circumstances, we will indemnify any director or, officer, manager, managing member, tax matters partner, employee, agent or trustee of our company or any of our affiliates and any person who is or was serving at our request as a manager, managing member, officer, director, tax matter partner, employee, agent, fiduciary or trustee of another person, to the fullest extent permitted by law, from and against all losses, claims or damages arising out of or incurred in connection with our business.
Procedures for Approval of Related Person Transactions
The board of directors has adopted a written policy designed to minimize potential conflicts of interest in connection with our transactions with related persons. This policy defines a “related person” to include: (i) any executive officer, director or director nominee; (ii) any person known to be a beneficial owner of 5% or more of our common units; (iii) an immediate family member of any person included in clauses (i) and (ii) (which, by definition, includes a person’s spouse, parents, and parents in law, step parents, children, children in law and step children, siblings and brothers and sisters in law and anyone residing in that person’s home); and (iv) any firm, corporation or other entity in which any person included in clauses (i) through (iii) above is employed as an executive officer, is a director, partner, principal or occupies a similar position or in which that person owns a 5% or more beneficial interest. The policy defines a “related person transaction” as a transaction, arrangement or relationship between us and a related party that is anticipated to exceed $120,000 in any calendar year and provide that each related person transaction must be approved, in advance, by the disinterested members of the board of directors. If approval in advance is not feasible, the related person transaction must be ratified by the disinterested directors. In approving a related person transaction, the disinterested directors will take into account, in addition to such other factors as they deem appropriate, the extent of the related person’s interest in the transaction and whether the transaction is no less favorable to us than terms generally available to an unaffiliated third party under similar circumstances.
The following related person transactions were pre-approved under the policy: (i) employment of an executive officer to perform services on our behalf (or on behalf of one of our subsidiaries) if (a) the compensation is required to be reported in our annual report on Form 10-K or (b) the executive officer is not an immediate family member of an executive officer, director, director nominee or person known to be a beneficial owner of 5% or more of our common units and such compensation was approved, or recommended to the board of directors for approval by the Compensation Committee; (ii) compensation paid to directors for serving on the board of directors or any committee thereof or reimbursement of expenses in connection with such services, if the compensation is required to be reported in our annual report on Form 10-K; (iii) transactions where the related person’s interest arises solely as a holder of our common units and all holders of our common units received the same benefit on a pro rata basis (e.g., dividends), or transactions available to all employees generally; (iv) a transaction at another company where the related person is only an employee (and not an executive officer), director or beneficial owner of less than 10% of such company’s shares and the aggregate amount involved does not exceed the greater of $1.0 million or 2% of that company’s total annual revenues; and (v) any charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which the related person’s only relationship is an employee (other than an executive officer) or director or similar capacity, if the aggregate amount involved does not exceed the lesser of $200,000 or 2% of the charitable organization’s total annual receipts, expenditures or assets.
Director Independence
Our board of directors has determined that Dr. Craig, Ms. Warren and Messrs. Biderman, Holtz, Jones and Kupfer each satisfy the requirement for independence set out in the rules of the New York Stock Exchange and those set forth in Rule 10A-3(b)(1) of the Exchange Act and meet the definition of an independent member set forth in our Governance Guidelines. In making these determinations, the board of directors reviewed information from each of these independent board members concerning all their respective relationships with us and analyzed the materiality of those relationships.
ITEM 14:
ITEM 14:
PRINCIPAL ACCOUNTANT FEES AND SERVICES
For the years ended December 31, 2016 and 2015, the accounting fees and services (in thousands) charged by Grant Thornton, LLP, our independent auditors, were as follows:
(1)
Represents the aggregate fees recognized in each of the last two years for professional services rendered by Grant Thornton LLP principally for the audits of our and our subsidiaries’ annual financial statements and the quarterly reviews of our and our subsidiaries’ financial statements included in Form 10-Qs and also for services related to our and our subsidiaries’ registration statements, Form 8-Ks and comfort letters, and audits related to the spin-off of assets associated with the Atlas Merger.
(2)
Represents the aggregate fees recognized during the years ended December 31, 2016 and 2015 for professional services rendered by Grant Thornton LLP substantially related to certain necessary audit related services in connection with the registration and/or private placement of Titan’s Drilling Partnerships and audits of our benefit plans.
(3)
The fees for tax services rendered related to tax compliance.
Audit Committee Pre-Approval Policies and Procedures
The audit committee, on at least an annual basis, will review audit and non-audit services performed by Grant Thornton LLP as well as the fees charged by Grant Thornton LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee. All of such services and fees were pre-approved during 2016 by the audit committee and in 2015 by the Atlas Energy audit committee.
PART IV
ITEM 15:
ITEM 15:
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as part of this report:
(1)
Financial Statements
The financial statements required by this Item 15(a)(1) are set forth in Item 8: Financial Statements and Supplementary Data.
(2)
Financial Statement Schedules
None
(3)
Exhibits:
________________________________________
*Provided herewith.
**The schedules have been omitted pursuant to Item 601(b) of Regulation S-K. A copy of the omitted schedules will be furnished to the U.S. Securities and Exchange Commission supplementally upon request.
***Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated as of April 17, 2017.
/s/ EDWARD E. COHEN
Chief Executive Officer and Director (Principal Executive Officer)
Edward E. Cohen
/s/ JONATHAN Z. COHEN
Executive Chairman of the Board
Jonathan Z. Cohen
/s/ JEFFREY M. SLOTTERBACK
Chief Financial Officer (Principal Financial Officer)
Jeffrey M. Slotterback
/s/ MATTHEW J. FINKBEINER
Chief Accounting Officer (Principal Accounting Officer)
Matthew J. Finkbeiner
/s/ MARK C. BIDERMAN
Director
Mark C. Biderman
/s/ DEANN CRAIG
Director
DeAnn Craig
/s/ DENNIS A. HOLTZ
Director
Dennis A. Holtz
/s/ WALTER C. JONES
Director
Walter C. Jones
/s/ JEFFREY F. KUPFER
Director
Jeffrey F. Kupfer
/s/ ELLEN F. WARREN
Director
Ellen F. Warren