Item 1 - Business
General
Clayton Williams Energy, Inc., incorporated in Delaware in 1991, is an independent oil and gas company engaged in the exploration for and production of oil and natural gas primarily in its core area in Southern Reeves County, Texas. Unless the context otherwise requires, references to “the Company,” “CWEI,” “we,” “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. On December 31, 2016, our estimated proved reserves were 34,754 MBOE, of which 63% were proved developed. Our portfolio of oil and natural gas reserves is weighted in favor of oil, with approximately 84% of our proved reserves at December 31, 2016 consisting of oil and natural gas liquids (“NGL”) and approximately 16% consisting of natural gas. During 2016, we added proved reserves of 4,077 MBOE through extensions and discoveries, had downward revisions of 168 MBOE and had sales of minerals-in-place of 10,728 MBOE. We also had average net production of 13.7 MBOE per day in 2016, which implies a reserve life of approximately 7.0 years. CWEI held interests in 2,726 gross (1,096.7 net) producing oil and gas wells and owned leasehold interests in approximately 423,000 gross (232,000 net) undeveloped acres at December 31, 2016.
Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of our Board of Directors (the “Board”) and our Chief Executive Officer, beneficially owns, either individually or through his affiliates, 17.6% of the outstanding shares of our common stock. In addition, The Williams Children’s Partnership, Ltd. (“WCPL”), a limited partnership of which Mr. Williams’ adult children are the limited partners, and Mel G. Riggs, our President, is the sole member in the general partner, owns an additional 17.3% of the outstanding shares of our common stock. Messrs. Williams and Riggs actively participate in all facets of our business and have significant influence in matters voted on by our shareholders, including the election of our Board members.
Ares Management, LLC (“Ares”) beneficially owns, either individually or through its affiliates, 42.0% of the outstanding shares of our common stock. In addition, Ares possesses the right to elect up to two members of our Board and to recommend one other director to the Nominating and Governance Committee of the Board for appointment to the Board. Through its elected and recommended Board members and substantial ownership of our common stock, Ares has significant influence in matters voted on by our shareholders, including the election of our Board members.
Company Profile
Business Strategy
We are an oil and gas operator with a strategic focus on developmental drilling in prolific oil shale provinces. We have significant holdings in one of the major oil shale plays in the United States, the Wolfcamp Shale in the Southern Delaware Basin of West Texas. In addition to our developmental drilling, we may explore for oil and natural gas reserves in areas that we believe offer exceptional opportunities for reserve growth, and we may also search for possible proved property acquisitions. From year to year, our allocation of investment capital may vary between developmental and exploratory activities depending on our analysis of all available growth opportunities, but our long-term focus on growing oil and natural gas reserves is consistent with our goal of value enhancement for our shareholders. On January 13, 2017, we entered into a definitive agreement to be acquired by Noble Energy. For more information on our proposed merger with Noble Energy, see “- Recent Developments - Proposed Merger with Noble Energy” below.
Recent Developments
The severe downturn in oil prices that began in 2014 significantly reduced our cash flow from operations, causing us to suspend drilling operations in both of our core resource plays early in 2015 in order to preserve liquidity. Management quickly took decisive steps to reduce costs in an attempt to improve margins, but the combination of declining production attributable to suspended drilling activities and the impact of substantially lower oil and natural gas prices on cash flow led our senior management and the Board, beginning in early July 2015, to consider a variety of strategic and financial alternatives for the Company.
Ares Transactions
In August 2015, the Board formed a special committee comprising all four of our independent and disinterested directors to develop, explore and evaluate strategic alternatives for the Company, including potential transactions involving a business combination, a recapitalization, a sale of assets or securities of the Company, or another extraordinary transaction. Goldman,
Sachs & Co. (“Goldman”) was engaged to serve as the Company’s exclusive financial advisor in this process. The special committee also engaged independent legal counsel.
With the assistance of senior management, Goldman identified and contacted potential counterparties on a confidential basis to determine their interest in one or more of the strategic alternatives under consideration by the Company. The Company received indications of interest across all of these alternatives. Throughout the review process, the special committee reviewed indications of interest and other information with Goldman, senior management, legal counsel for the Company and legal counsel for the special committee.
In mid-January 2016, final bids were submitted for various potential transactions, including proposals for secured debt financing. The special committee concluded that a secured debt alternative was favorable to the Company and its shareholders. In reaching this conclusion, the special committee considered, among other factors, that the secured debt alternative (1) avoided a sale of our core assets during a time of declining commodity prices, (2) provided a dedicated source of liquidity to fund our operations and development activities over the next two to three years, (3) limited immediate dilution to existing shareholders and (4) retained the opportunity to ultimately enhance shareholder value if the commodity environment improves. The special committee instructed Goldman to negotiate final proposals with these bidders, and following negotiations, the special committee and the Board unanimously selected the proposal submitted by Ares.
On March 8, 2016, we entered into (1) a credit agreement with Ares providing for the issuance of second lien term loans and common stock warrants and (2) an amendment to the revolving credit facility with our banks (the “Refinancing”). Upon closing of the Refinancing on March 15, 2016, we issued term loans to Ares in the principal amount of $350 million, net of original issue discount of $16.8 million, for cash proceeds of $333.2 million. Concurrently, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share to Ares for cash proceeds equal to the original issue discount from the issuance on the term loans. The warrants represent the right to acquire approximately 12.8% of our outstanding shares of common stock, or approximately 11.2% of our common shares on a fully exercised basis. In connection with the issuance of the warrants, we designated and issued to funds managed by Ares, as the initial warrant holders, 3,500 shares of special voting preferred stock, $0.10 par value per share, granting them certain rights to elect two members of our Board. Aggregate cash proceeds from the transaction of approximately $340 million, net of transaction costs, were used to fully repay the outstanding indebtedness under the revolving credit facility of $160 million, plus accrued interest and fees, and added approximately $180 million of cash to our balance sheet to provide additional liquidity to fund our operations and future development.
The amendment to our revolving credit facility, among other things, reduced the borrowing base and aggregate lender commitments from $450 million to $100 million and modified the financial ratio covenant by (1) deleting the requirement that we maintain a specific ratio of consolidated EBITDAX to our consolidated net interest expense and (2) replacing the requirement that we maintain a varying ratio of consolidated funded indebtedness to consolidated EBITDAX with a fixed ratio of our debt under the revolving credit facility to consolidated EBITDAX of 2.0 to 1.0. The Refinancing has provided us dedicated liquidity and allowed us to decrease debt under the revolving credit facility in order to meet the financial ratio covenant under that facility. See the discussion under “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Revolving credit facility.”
On July 22, 2016, we entered into an agreement to sell 5,051,100 shares of common stock to funds managed by Ares for cash proceeds of $150 million, or approximately $29.70 per share (the “Private Placement”), which transaction closed on August 29, 2016. In connection with the Private Placement, we entered into an amendment to the term loan facility, waiving certain restrictions to enable us to use proceeds from equity issuances and specified asset sales for debt reduction and capital expenditures.
Giddings Sale
In October 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing adjustments. We closed the sale on December 19, 2016.
Proposed Merger with Noble Energy
On January 13, 2017, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Noble Energy, Wild West Merger Sub, Inc., a Delaware corporation and indirect wholly owned subsidiary of Noble Energy (“Merger Sub”), and NBL Permian LLC, a Delaware limited liability company and indirect wholly owned subsidiary of Noble Energy (“Merger Sub II”), pursuant to which Noble Energy will acquire the Company in exchange for a combination of shares of common stock, par value $0.01 per share, of Noble Energy (“Noble Energy Common Shares”) and cash. Upon the terms and subject to the conditions of the Merger Agreement, (i) Merger Sub will merge with and into the Company (the “Merger”), with the Company continuing
as the surviving corporation in the Merger and an indirect wholly owned subsidiary of Noble Energy, and (ii) thereafter, the Company will merge with and into Merger Sub II, with Merger Sub II continuing as the surviving company and an indirect wholly owned subsidiary of Noble Energy.
Under the terms of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each share of the Company’s common stock issued and outstanding immediately prior to the Effective Time (other than common stock held in treasury and common stock held by shareholders who properly comply in all respects with the provisions of Section 262 of the General Corporation Law of the State of Delaware (“DGCL”) as to appraisal rights) and each unexercised warrant to purchase or otherwise acquire shares of common stock of the Company (each, a “CWEI Warrant”) issued and outstanding as of the Effective Time will be cancelled and extinguished and automatically converted into the right to receive, at the election of the shareholder or warrant holder, as applicable, and subject to proration as described below, one of the following forms of consideration (the “Merger Consideration”):
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for each share of common stock, one of (i) 3.7222 Noble Energy Common Shares (the “Share Consideration”); (ii) (A) $34.75 in cash (subject to applicable withholding tax), without interest, and (B) 2.7874 Noble Energy Common Shares (the “Mixed Consideration”); or (iii) $138.39 in cash (subject to applicable withholding tax), without interest (the “Cash Consideration”); and
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for each CWEI Warrant, either (i) the Share Consideration in respect of the number of shares of common stock of the Company that would be issued upon a cashless exercise of such CWEI Warrant immediately prior to the Effective Time (“Warrant Notional Common Shares”); (ii) the Mixed Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant; or (iii) the Cash Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant.
The Merger Consideration is subject to proration so that the aggregate Merger Consideration paid in respect of all shares of common stock of the Company and CWEI Warrants consists of 75% Noble Energy Common Shares and 25% cash. No fractional Noble Energy Common Shares will be issued in the Merger, and holders of common stock of the Company will, instead, receive cash in lieu of fractional Noble Energy Common Shares, if any. The implied value of the aggregate Merger Consideration is $2.7 billion based on the per share closing trading price of Noble Energy Common Shares on January 13, 2017.
At the Effective Time, each share of preferred stock, par value $0.10 per share, of the Company (each, a “CWEI Preferred Share”) issued and outstanding immediately prior to the Effective Time will be converted into the right to receive cash in an amount equal to $1.00 (subject to any applicable withholding tax), without interest.
Each option to purchase shares of common stock of the Company (each, a “CWEI Option”) that is outstanding immediately prior to the Effective Time will vest and be exchanged for the number of Noble Energy Common Shares, rounded down to the nearest whole share, equal to the quotient obtained by dividing (i) the product of (A) the number of shares of common stock of the Company subject to the CWEI Option and (B) the amount, if any, by which the per share closing trading price of common stock of the Company on the business day immediately before the closing date of the Merger exceeds the exercise price per common stock of the Company otherwise purchasable pursuant to the CWEI Option immediately prior to the Effective Time by (ii) the average of the closing sale prices of a Noble Energy Common Share as reported on the New York Stock Exchange for the ten consecutive full trading days ending at the close of trading on the full trading day immediately preceding the date on which the Effective Time occurs. If such calculation results in zero or a negative number, the applicable CWEI Option shall be forfeited for no consideration.
At the Effective Time, the restricted shares of common stock of the Company (“CWEI Restricted Shares”) outstanding immediately prior to the Effective Time will be converted into a number of restricted Noble Energy Common Shares equal to the number of CWEI Restricted Shares multiplied by the Share Consideration, rounded up to the nearest whole share, and subject to the same vesting, repurchase and other restrictions as the CWEI Restricted Shares.
Each of Noble Energy, Merger Sub and the Company has made customary representations and warranties and agreed to customary covenants in the Merger Agreement. The Merger is subject to various closing conditions, including but not limited to (i) approval of the Merger Agreement by at least a majority of the outstanding shares of common stock of the Company, (ii) the expiration or earlier termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, (iii) the absence of any law, order or injunction prohibiting the Merger, (iv) the accuracy of each party’s representations and warranties, (v) each party’s compliance with its covenants and agreements contained in the Merger Agreement and (vi) that the aggregate number of shares of common stock of the Company as to which appraisal rights are exercised does not exceed 10% of the outstanding shares of common stock of the Company.
The Merger Agreement contains certain termination rights for both Noble Energy and the Company, including if the Merger is not consummated by July 17, 2017, and further provides that, upon termination of the Merger Agreement under certain circumstances, the Company may be required to pay Noble Energy a termination fee equal to $87 million. The closing of the Merger is expected to occur in the second quarter of 2017.
Domestic Operations
We conduct all of our drilling, exploration and production activities in the United States. All of our oil and gas assets are located in the United States, and all of our revenues are derived from sales to customers within the United States.
Development Program
Our current focus is on developmental drilling in our core area of Southern Reeves County, Texas. A developmental well is a well drilled within the proved area of an oil and gas reservoir to a horizon known to be productive. We have an inventory of developmental projects available for drilling in the future, most of which are located in the oil-prone region of Southern Reeves County, Texas. In many cases, our leasehold interests in developmental projects are held by the continuous production of other wells, meaning that our rights to drill these projects are not subject to near-term expiration. This provides us with a high degree of flexibility in the timing of developing these reserves.
Exploration Program
To a lesser degree, from time to time, we are also engaged in finding reserves through exploratory drilling. Our exploration program consists of generating exploratory prospects, leasing the acreage related to these prospects, drilling exploratory wells on these prospects to determine if recoverable oil and gas reserves exist, drilling developmental wells on these prospects and producing and selling any resulting oil and gas production.
Acquisition and Divestitures of Proved Properties
In addition to our exploration and development activities, we seek opportunities to acquire reserves and leased acreage that could complement our current operations and enhance shareholder value. However, competition for the purchase of reserves and leased acreage can be intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it difficult for us to acquire reserves and leased acreage without assuming significant price and production risks.
In January 2017, we purchased approximately 1,900 net mineral acres in Southern Reeves County, Texas from a private seller, for cash consideration totaling $44.3 million. The acreage is located in and around our existing contiguous acreage block. Also included in the deal was a non-operated gross working interest of approximately 26% in an existing horizontal well.
From time to time, we sell certain of our undeveloped leases and proved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them. We consider many factors in deciding to sell properties, including the need for liquidity, the risks associated with continuing to own the properties, our expectations for future development on the properties, the fairness of the price offered and other factors related to the condition and location of the properties.
On December 19, 2016, we closed the sale of substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing adjustments. Prior to December 2016, we successfully closed several asset sales. In September 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $1.4 million. In July 2016, we sold our interests in certain wells in Glasscock County, Texas for approximately $19.4 million, subject to customary post-closing adjustments. In June 2016, we sold our interests in certain wells in Oklahoma for cash consideration of $1.5 million. In April 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $2 million. In February 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $0.8 million.
Desta Drilling
Through our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), we currently have eight drilling rigs available for our use or for contract drilling operations. The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties. Due to the downturn in oil prices, all our rigs have been idle since November 2015.
Exploration and Development Activities
Overview
We spent $91.3 million on exploration and development activities in the Permian Basin and the Giddings Area during 2016. On October 24, 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing adjustments. We closed the sale on December 19, 2016.
Areas of Operations
Permian Basin
The Permian Basin is a sedimentary basin in West Texas and Southeastern New Mexico known for its large oil and gas deposits from the Permian geologic period. The Permian Basin covers an area approximately 250 miles wide and 350 miles long and contains commercial accumulations of oil and gas in multiple stratigraphic horizons at depths ranging from 1,000 feet to over 25,000 feet. The Permian Basin is characterized by an extensive production history, mature infrastructure, long reserve life, multiple producing horizons and enhanced recovery potential. Although many fields in the Permian Basin have been heavily exploited in the past, favorable product prices over the past several years, coupled with improved technology (including deep horizontal drilling) continued to attract high levels of drilling and recompletion activities.
We spent $55.2 million in the Permian Basin during 2016 on drilling and completion activities and $23.7 million on leasing and seismic activities. We drilled and completed 6 gross (6.0 net) operated wells in the Permian Basin and conducted various remedial operations on other wells during 2016. Following is a discussion of our principal assets in the Permian Basin.
Delaware Basin
We currently hold approximately 73,000 net acres in the active Wolfbone resource play in the Delaware Basin, primarily in Southern Reeves County, Texas. The Wolfbone resource play generally refers to the interval from the Bone Springs formation down through the Wolfcamp formation at depths typically found between 8,000 and 11,500 feet. A Wolfbone well generally refers to a vertical well completed in multiple intervals within these formations or a horizontal well being completed in an interval within such formations. These Permian aged formations in the Delaware Basin are composed of limestone, sandstone and shale. Geology in the Delaware Basin consists of multiple stacked pay zones with both over-pressured and normal-pressured intervals.
We entered the Delaware Basin as a vertical play, but with encouraging results from our horizontal drilling, we shifted our emphasis to a horizontal program. Most of our horizontal drilling to date has targeted the Wolfcamp A shale interval in Southern Reeves County, Texas with 35 Wolfcamp A wells currently on production. We also have four Wolfcamp C wells currently on production.
We spent approximately $53 million on drilling and completion activities and $23.2 million on leasing activities in the Wolfbone play during 2016.
We own oil, natural gas and water disposal pipelines in Southern Reeves County, Texas consisting of 119 miles of oil pipelines with current capacity of 10,000 barrels of oil per day (expandable to 25,000 barrels of oil per day), 117 miles of natural gas pipelines with a current capacity of 10,000 Mcf of natural gas per day (expandable to 25,000 Mcf of natural gas per day) and 124 miles of salt water disposal pipelines with a current capacity of 30,000 barrels of produced water per day (expandable to 36,000 barrels of produced water per day).
Other Permian Basin
Approximately 33% of our 2016 oil and gas production was derived from wells in parts of the Permian Basin other than our Delaware Basin Wolfbone resource play. Many of these wells are located on the Central Basin Platform, geographically located between the Midland Basin and Delaware Basin, and produce from formations with conventional porosity such as the San Andres, Grayburg, Fusselman, Ellenburger and Yeso formations. A significant portion of our production in this area is derived from mature fields, several of which are in varying stages of secondary and/or tertiary recovery.
Other
We spent $2.2 million during 2016 on exploration and development activities in other regions, including Oklahoma and California.
Factors That Significantly Affect Our Financial Results
Revenue, cash flow from operations and future growth depend on many factors beyond our control, such as oil prices, cost of services and supplies, economic, political and regulatory developments and competition from other sources of energy. Historical oil prices have been volatile and are expected to fluctuate widely in the future. Sustained periods of low prices for oil could materially and adversely affect our financial position, our results of operations, the quantities of oil and gas that we can economically produce and our ability to obtain capital.
Like all businesses engaged in the exploration for and production of oil and gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and gas production from a given well decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. We attempt to overcome this natural decline by developing existing properties, implementing secondary and tertiary recovery techniques and by acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from existing reserves and to continue to add reserves in excess of production through exploration, development and acquisition. We will maintain our focus on costs necessary to produce our reserves as well as the costs necessary to add reserves through production enhancement, drilling and acquisitions. Our ability to make capital expenditures to increase production from existing reserves and to acquire more reserves is dependent on availability of capital resources, and can be limited by many factors, including the ability to obtain capital in a cost-effective manner and to obtain permits and regulatory approvals in a timely manner.
Marketing Arrangements
Oil
Most of our oil production is sold based on the New York Mercantile Exchange (“NYMEX”) futures market for West Texas Intermediate light sweet crude oil (referred to as WTI and traded in the NYMEX futures market under the symbol CL). Cushing, Oklahoma is a major trading hub for crude oil and is the price settlement point for WTI. As a result, basis differentials exist between the NYMEX price and the price we receive for our oil production depending on the proximity of our properties to the ultimate market for that production. Basis differentials are market-based and are adversely affected by logistical factors such as pipeline constraints and inadequate storage capacities.
Approximately 99% of our oil reserves at December 31, 2016 are located in the Permian Basin. Most Permian Basin oil production gains access to refineries through the Cushing trading hub. Basis differentials between the Midland, Texas oil storage facility and the Cushing trading hub are referred to as the Midland-Cushing differential. Through multiple marketing arrangements, which expire in November 2017, we have effectively limited our exposure to the Midland-Cushing differential to less than $2 per barrel on a majority of our Permian Basin production.
Natural gas
Natural gas is generally sold based on the NYMEX futures market for natural gas (traded in the NYMEX futures market under the symbol NG). Since the delivery point for NYMEX traded natural gas is the distribution hub on a natural gas pipeline system in Erath, Louisiana, referred to as Henry Hub, basis differentials exist between the NYMEX price and the price we receive for our gas production depending on the proximity of our properties to the ultimate market for that production. Basis differentials are market-based and are adversely affected by logistical factors such as pipeline constraints and inadequate storage capacities.
Most of our natural gas production is produced from our oil wells. This gas, known as casinghead gas, generally has a high Btu content. Casinghead gas may be processed downstream to extract NGL from the gas and lower the Btu content of the residue gas to a level suitable for manufacturing and residential use. Our casinghead gas is generally sold in one of three ways: (1) as processed gas where the purchaser processes the gas and pays us a percentage of the value of the NGL and a percentage of the value of the residue gas; (2) as processed gas where the purchaser accounts for the value of any extracted NGL and includes that value in the price paid to us for our gas production at the wellhead; and (3) as unprocessed gas where the purchaser pays us a price per MMBtu for our gas production at the wellhead. All of the value we receive from casinghead gas production is recorded as gas sales in our financial records, except for the value of NGL paid to us under method (1), which is reported separately as NGL sales.
Some of our natural gas production is produced from gas wells. This gas, known as dry gas, generally not exceeding 1,000 Btus is not suitable for extraction of NGL. Most of our dry gas is sold under contracts where the purchaser pays us a price per MMBtu for our gas production at the wellhead.
Natural gas liquids
A portion of our casinghead gas production is processed under contracts where the purchaser pays us a percentage of the value of the NGL extracted. The price we receive for NGL is generally based on the spot liquids price for the various NGL products sold at Mont Belvieu, Texas and reported by Oil Price Information Service. We compute the price differential for NGL based on the NYMEX benchmark for oil, but the NGL components are subject to their own supply and demand factors, not all of which vary in correlation with changes in oil prices.
Pipelines and Other Midstream Facilities
We own interests in and operate oil, natural gas and water service facilities in the state of Texas. These midstream facilities consist of interests in approximately 423 miles of pipeline located primarily in Southern Reeves County, Texas, two treating plants, one dehydration facility and multiple wellhead type treating and/or compression stations. Most of our operated gas gathering and treating activities facilitate the transportation and marketing of our operated oil and gas production and third party producers. Portions of our gathering systems in Southern Reeves County, Texas are regulated by the Railroad Commission of Texas (the “RCT”). The RCT regulates portions of our crude oil gathering system as a common carrier, and it regulates portions of our natural gas gathering system as a gas utility.
Competition and Markets
Competition in all areas of our operations is intense. We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable properties and prospects for future development and exploration activities.
In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenues.
The market for our oil, gas and NGL production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and NGL, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.
Regulation
Generally. Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas 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 others in our industry with similar types, quantities and locations of production.
Regulations affecting production. All of the states in which we operate generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring gas and requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many states impose a production or severance tax with respect to the
production and sale of oil and gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.
In the event we conduct operations on federal, state or American Indian oil and gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements and on-site security regulations, and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.
Regulations affecting sales. The sales prices of oil, gas and NGL are not presently regulated but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on the operations of the underlying properties.
The Federal Energy Regulatory Commission (the “FERC”) regulates interstate gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the gas industry. We do not believe that we will be affected by any such FERC action in a manner materially different from other gas producers in our areas of operation.
The price we receive from the sale of oil and NGL is affected by the cost of transporting those products to market. Interstate transportation rates for oil, NGL and other products are regulated by the FERC. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC adjusts this index every five years. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and NGL.
Market manipulation and market transparency regulations. Under the Energy Policy Act of 2005 (the “EP Act 2005”), the FERC possesses regulatory oversight over gas markets, including the purchase, sale and transportation of gas by “any entity” in order to enforce the anti-market manipulation provisions in the EP Act 2005. The Federal Trade Commission (the “FTC”) has similar regulatory oversight of oil markets in order to prevent market manipulation. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of crude oil, gas and NGL, our gathering of these energy commodities, and any related hedging transactions that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by the FERC, the FTC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties potentially in excess of $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
The FERC has issued certain market transparency rules for the gas industry pursuant to its EP Act 2005 authority, which may affect some or all of our operations. The FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 MMBtu of physical gas in the previous calendar year, including gas producers, gatherers, processors and marketers, to report, on May 1 of each year, beginning in 2009, aggregate volumes of gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices, as explained in Order 704. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. In addition, to the extent that we enter into transportation contracts with interstate pipelines that are subject to FERC regulation, we are subject to FERC requirements related to use of such interstate capacity. Any failure on our part to comply with the FERC’s regulations could result in the imposition of civil and criminal penalties.
Gathering regulations. Section 1(b) of the Natural Gas Act (the “NGA”) exempts gas gathering facilities from the jurisdiction of the FERC under the NGA. We own certain gas pipelines that we believe meet the traditional tests that the FERC has used to establish a pipeline’s status as a gatherer not subject to the FERC jurisdiction. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between the FERC-regulated transmission facilities and federally unregulated gathering facilities is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering lines may be subject to change based on future determinations by the FERC, the courts or Congress.
While we own some gas gathering facilities, we also depend on gathering facilities owned and operated by third parties to gather production from our properties, and therefore, we are affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for gathering services, we also may be affected by these changes. We do not anticipate that we would be affected any differently than similarly situated gas producers.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. For example, portions of our natural gas and crude oil gathering systems in Southern Reeves County, Texas are regulated by the RCT. Accordingly, we have filed tariffs with the RCT with respect to those systems. Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather gas or crude oil. In addition, our gas and crude oil gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.
Pipeline Safety Matters
Certain of our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) with respect to oil and the Natural Gas Pipeline Safety Act (“NGPSA”) with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of oil and natural gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. The HLPSA and NGPSA were amended by the Pipeline, Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law.
Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. New pipeline safety laws or implementing regulations adopted by PHMSA or analogous state agencies may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. For example, in January 2017, PHMSA issued a final rule that significantly extends and expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in presidential administrations. Additionally, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as five dwellings within a potential impact area; and requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressure. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines.
Environmental and Occupational Safety and Health Matters
Our operations pertaining to oil and natural gas exploration and production, as well as oil, natural gas and water pipeline or service facilities and related activities are subject to numerous federal, state and local laws governing occupational safety and health, the emission and discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits prior to commencing drilling, providing produced water disposal or other regulated activities in connection with our operations; restrict or prohibit the types, quantities and concentration of substances that we can release into the environment; restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources; require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells and pipelines; impose specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from our operations. Such laws and regulations may substantially increase the cost of our operations and may prevent or delay the permitting, commencement or continuation of a given project and thus generally could have an adverse effect upon our capital expenditures, earnings or competitive position. Violation of these laws and regulations could result in sanctions including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective obligations and the issuance of orders enjoining some or all of our operations in affected areas. We have experienced accidental spills, leaks and other discharges of contaminants at some of our properties, as have other similarly situated oil and gas companies, and some of the properties that we have acquired, operated or sold, or in which we may hold an interest but not operational control, may have past or ongoing contamination for which we may be held responsible. Also, some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas that may obligate us to implement costly mitigative or precautionary measures, while some of our properties are located in areas particularly susceptible to hurricanes and other destructive storms that may damage facilities and cause the release of pollutants. Our environmental insurance coverage may not fully insure all of these risks.
Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. Changes in existing environmental laws and regulations or the adoption of new legal requirements could have a significant impact on our operations, as well as the oil and gas industry in general. For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements, or drilling, completion, construction or water management activities could have an adverse impact on our operations.
The following is a summary of the more significant existing environmental and worker health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
Hazardous substances and wastes. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which applies to crude oil and natural gas, we nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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.
The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose detailed requirements for the generation, storage, treatment, transportation and disposal of hazardous and non-hazardous wastes. In the course of our operations, we generate ordinary industrial wastes that may be regulated as hazardous wastes. RCRA currently exempts certain drilling fluids, produced waters and other wastes associated with exploration, development and production of oil and natural gas from regulation as hazardous wastes. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as nonhazardous wastes could be classified as hazardous wastes in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the Environmental Protection Agency (“EPA”) for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and natural gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016 (the “Consent Decree”). Under the decree, the EPA is required
to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and natural gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Repeal or modification of the current RCRA exclusion or similar exemptions under state law could increase the amount of hazardous waste we or, in the case of our pipeline and natural gas treatment and dehydration services, our oil and natural gas exploration and production customers are required to manage and dispose of and could cause us or our customers to incur increased operating costs, which could have a significant impact on us as well as reduce demand for our pipeline and natural gas treatment and dehydration services.
We currently own or lease and have in the past owned or leased properties that for many years have been used for oil and natural gas exploration and production activities as well as pipeline and natural gas treatment and dehydration services. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other substances and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons or other substances and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other substances and wastes was not under our control. These properties and any hydrocarbons, substances and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.
Air emissions. The Clean Air Act (“CAA”) and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits or utilize specific emission control technologies to limit emissions. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondary standards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Additionally, the EPA issued final CAA regulations in 2012 that include New Source Performance Standards (“NSPS”) for completions of hydraulically fractured natural gas wells and issued added CAA regulations in June 2016 that include new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category, including production activities. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business.
Water discharges. The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws and regulations impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water from our operations and may be required to develop and implement spill prevention, control and countermeasure (“SPCC”) plans in connection with on-site storage of significant quantities of oil, including refined petroleum products. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts ponder lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. To the extent this rule expands the scope of the Clean Water Act’s jurisdiction, drilling programs could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.
The United States Oil Pollution Act of 1990 (“OPA”) amends the Clean Water Act, and sets minimum standards for prevention, containment and cleanup of oil spills. The OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under the OPA, responsible parties including owners and operators of onshore facilities may be held strictly liable for oil cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills.
Subsurface injections. Fluids associated with oil and natural gas production, consisting primarily of salt water, are disposed by injection in belowground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control (“UIC”) program established under the federal Safe Drinking Water Act (“SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. Any change in disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of salt water and ultimately increase the cost of our operations. For example, there exists a growing concern that the injection of saltwater and other fluids into belowground disposal wells triggers seismic activity in certain areas, including Texas, where we operate. In response to these concerns, in 2014, the Texas Railroad Commission (“TRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. In addition, Oklahoma has taken numerous regulatory actions in response to concerns related to the operation of saltwater disposal wells and induced seismicity. These requirements include volumetric limits for wastewater disposal wells, enhanced monitoring and recordkeeping, and requirements to reduce the depth of, or “plug back,” existing disposal wells. Restriction on the volumes permissible for injection or a lack of waste disposal sites could cause us to delay, curtail or discontinue our exploration and development plans. Increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, such as requirements to monitor or plug back disposal wells, may reduce our profitability. These developments may result in additional levels of regulation, or increased complexity and costs with respect to existing regulations, that could lead to operational delays or increased operating and compliance costs, which could have a material adverse effect on our business, results of operations, cash flows or financial condition.
Climate change. Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, onshore and offshore oil and natural gas production facilities and onshore processing, transmission, storage and distribution facilities, which include certain of our operations. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the NSPS.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued NSPS Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. Moreover, in November 2016, the EPA issued a final information collection request (“ICR”) seeking information about methane emissions from facilities and operations in the oil and natural gas industry. The EPA has indicated that it intends to use the information from this request to develop Existing Source Performance Standards for the oil and natural gas industry. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France to prepare an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us or, in the case of our pipeline or treating or dehydration services, our oil and natural gas exploration and production customers to incur increased costs that could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we or our customers produce and lower the value of our reserves as well as reduce demand for our pipeline and treating and dehydration services.
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, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the target formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions or other similar state agencies, but several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has taken the following actions: in 2014, asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; in 2012 and June 2016, issued final regulations under the CAA governing performance standards, including first-time standards in 2016 for the capture of methane emissions released during hydraulic fracturing; in June 2016, published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants; and in 2014, issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. In June 2016, the U.S. District Court of Wyoming struck down this final rule, finding that the BLM lacked authority to promulgate the rule, and that decision is currently being appealed by the federal government.
From time to time, the U.S. Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states, including Texas and New Mexico, where we conduct operations, have adopted and other states are considering adopting legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we or, in the case of our pipeline and treating or dehydration services, our customers operate, we or our customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded in the drilling of wells or in the volume that we or our customers are ultimately able to produce from reserves.
Endangered species. The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species or their critical habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Some of our operations and pipeline services, including drilling, producing, treating or dehydration services and those of our pipeline customers are conducted in areas where protected species are known to exist. In these areas, we or our customers may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we or our customers may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when we or our customers’ operations could have an adverse effect on protected species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete well drilling and development and could adversely affect our future production from those areas. Moreover, as a result of one or more settlements entered into by the U.S. Fish and Wildlife Service (“FWS”), the agency is required to make a determination on the listing of numerous species as endangered or threatened under the ESA in accordance with specific timelines. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could
result in limitations on our exploration and production activities that could have an adverse effect on our ability to develop and produce reserves and, an indirect adverse impact on our pipeline and treating or dehydration services.
OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. 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.
Claims are sometimes made or threatened against companies engaged in oil and natural gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. We have been named as a defendant in a number of such lawsuits. While some jurisdictions in which we operate limit damages in such cases to the value of land that has been impaired, courts in other jurisdictions have allowed damage claims in excess of land value, including claims for the cost of remediation of contaminated properties. However, we do not believe that resolution of these claims will have a material adverse impact on our financial condition and operations.
Title to Properties
As is customary in the oil and gas industry, we perform a minimal title investigation before acquiring undeveloped properties. A title opinion is obtained prior to the commencement of drilling operations on such properties. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. These title investigations and title opinions, while consistent with industry standards, may not reveal existing or potential title defects, encumbrances or adverse claims as we are subject from time to time to claims or disputes regarding title to properties. Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect the value of such properties. Substantially all of our oil and gas properties are currently mortgaged to secure borrowings under the revolving credit facility and the term loan credit facility and may be mortgaged under any future credit facilities entered into by us.
Operational Hazards and Insurance
Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. In addition, the presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment.
We maintain insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition and results of operations. We cannot give any assurances that we will be able to maintain adequate insurance in the future at rates we consider reasonable.
Operating Segments
For financial information about our operating segments, see Note 18 to the accompanying consolidated financial statements.
Employees
At December 31, 2016, we had 197 full-time employees, of which eight were employed by Desta Drilling. None of our employees are subject to a collective bargaining agreement. In our opinion, relations with employees are good.
Website Address
We maintain an Internet website at www.claytonwilliams.com. We make available, free of charge, on our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. The information contained in or incorporated in our website is not part of this report.
Item 1A
Item 1A - Risk Factors
There are many factors that affect our business, some of which are beyond our control. Our business, financial condition and results of operations could be materially adversely affected by any of these risks. The nature of our business activities further subjects us to certain hazards and risks. The risks described below are a summary of some of the material risks relating to our business. Other risks are described in “Item 1 - Business” and “Item 7A - Quantitative and Qualitative Disclosures About Market Risk.” Additional risks not presently known to us or that we currently deem immaterial individually or in the aggregate may also impair our business operations. If any of these risks actually occur, it could materially harm our business, financial condition or results of operations and impair our ability to implement business plans or complete development projects as scheduled. In that case, the market price of our common stock could decline.
The Merger with Noble Energy may not be consummated even if our shareholders approve the Merger.
The Merger Agreement contains conditions, some of which are beyond the parties’ control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Merger not occurring, even though our shareholders may have voted to approve the Merger. We cannot predict with certainty whether and when any of the conditions to the completion of the Merger will be satisfied. Any delay in completing the Merger could cause us not to realize, or delay the realization of, some or all of the benefits that we expect to achieve from the Merger. In addition, we can agree with Noble Energy not to consummate the Merger even if our shareholders approve the Merger and the conditions to the closing of the Merger are otherwise satisfied.
While the Merger Agreement with Noble Energy is in effect, we may be limited in our ability to pursue attractive business opportunities.
While the Merger Agreement with Noble Energy is in effect, we are prohibited from, without Noble Energy’s consent, taking certain actions with respect to our business and financial affairs pending completion of the Merger or termination of the Merger Agreement. In addition, our management continues to devote substantial time and other resources to the Merger and related matters, which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, standalone projects and other transactions. If we are unable to pursue such other attractive business opportunities, our growth prospects and the long-term strategic position of our business could be adversely affected.
Furthermore, the uncertainty surrounding the approval of the Merger may adversely affect our ability to attract and retain qualified personnel. We operate in an industry that currently experiences a high level of competition among different companies for qualified and experienced personnel. The uncertainty relating to the possibility of the Merger may increase the risk that we could experience higher than normal rates of attrition or that we experience increased difficulty in attracting qualified personnel or incur higher expenses to do so. High levels of attrition among the management and employee personnel necessary to operate our business or difficulties or increased expense incurred to replace any personnel who leave, could materially adversely affect our business or results of operations.
If the Merger with Noble Energy does not occur, we will not benefit from the expenses we have incurred in the pursuit of the Merger.
The Merger with Noble Energy may not be completed. If the Merger is not completed, we will have incurred substantial expenses for which no ultimate benefit will have been received by us. We currently expect to incur significant Merger-related expenses, consisting of independent advisory, legal and accounting fees, and financial printing and other related charges, much of which may be incurred even if the Merger is not completed. In addition, if the Merger Agreement is terminated under specified circumstances, we will be required to pay certain Merger-related expenses of Noble Energy.
We may be subject to class action lawsuits relating to the Merger, which could materially adversely affect our business, financial condition and operating results.
Our directors and officers may be subject to class action lawsuits relating to the Merger and other additional lawsuits that may be filed. Such litigation is very common in connection with dispositions of public companies, regardless of any merits related to the underlying disposition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.
One of the conditions to consummating the Merger is that no injunction or other order prohibiting or otherwise preventing the consummation of the Merger shall have been issued by any court or governmental entity of competent jurisdiction. Consequently, if any lawsuit is filed challenging the Merger and is successful in obtaining an injunction preventing the parties to the Merger
Agreement from consummating the Merger, such injunction may prevent the Merger from being completed in the expected time frame, or at all.
Failure to complete, or significant delays in completing, the Merger with Noble Energy could negatively affect the trading prices of our common stock and our future business and financial results.
Completion of the Merger is not assured and is subject to risks, including the risks that approval of the Merger by our shareholders is not obtained or that other closing conditions are not satisfied. If the Merger is not completed, or if there are significant delays in completing the Merger, the trading prices of our common stock and our future business and financial results could be negatively affected, and we will be subject to several risks, including the following:
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we may be liable for damages to Noble Energy under the terms and conditions of the Merger Agreement;
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negative reactions from the financial markets, including declines in the prices of our common stock due to the fact that current prices may reflect a market assumption that the Merger will be completed;
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having to pay certain significant costs relating to the Merger; and
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the attention of our management will have been diverted to the Merger rather than our own operations and pursuit of other opportunities that could have been beneficial to us.
The Merger with Noble Energy is a taxable transaction and the resulting tax liability of a shareholder, if any, will depend on each such shareholder’s particular situation.
The receipt of Noble Energy common stock, cash or a combination of Noble Energy common stock and cash as Merger consideration in exchange for our common stock in the Merger will be treated as a taxable sale by such holders of such common stock for U.S. federal income tax purposes. The amount of gain or loss recognized by each shareholder in the Merger will vary depending on each shareholder’s particular situation, including the value of the Noble Energy common stock and/or amount of cash received by each shareholder as Merger consideration in the Merger, the adjusted tax basis of the common stock exchanged by each shareholder in the Merger, and the amount of any suspended passive losses that may be available to a particular shareholder to offset a portion of the gain recognized by the shareholder.
Oil and gas prices are volatile. Since the second half of 2014, there has been a substantial decline in commodity prices, which has significantly affected, and in the future may adversely affect, our financial condition, liquidity, results of operations, cash flows, access to the capital markets and ability to grow.
Our revenues, operating results, liquidity, cash flows, profitability and value of proved reserves depend substantially upon the market prices of oil and gas. For the past two years, following the significant decline that began in late 2014, crude oil prices, in particular, have been trading in a much lower range. While in the second half of 2016 commodity prices improved, we expect prices to remain volatile. These depressed commodity prices adversely affected our 2016 financial condition and results of operations and contributed to a reduction in our anticipated future capital expenditures. In addition, this decline in commodity prices has adversely impacted our estimated proved reserves and resulted in substantial impairments to our oil and natural gas properties in 2016 and 2015.
Commodity prices affect our cash flows available for capital expenditures and our ability to access funds under the revolving credit facility and through the capital markets. The amount available for borrowing under the revolving credit facility is subject to a borrowing base, which is determined at least semi-annually by our lenders taking into account the estimated value of our proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in commodity prices have historically adversely affected the estimated value of our proved reserves and, in turn, the market values used by our lenders in determining our borrowing base. If commodity prices continue to decline in the future, the decline could have further and more severe adverse effects on our reserves and borrowing base.
The commodity prices we receive for our oil and gas depend upon factors beyond our control, including among others:
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changes in the supply of and demand for oil and gas;
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market uncertainty;
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the level of consumer product demands;
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pipeline constraints and sufficient capacity;
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hurricanes and other weather conditions;
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domestic governmental regulations and taxes;
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shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas;
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the price and availability of alternative fuels;
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political and economic conditions in oil producing countries;
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the foreign supply of oil and gas;
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the price of oil and gas imports; and
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overall domestic and foreign economic conditions.
These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and gas prices do not necessarily fluctuate in direct relation to each other.
We may not be able to replace production with new reserves.
In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. In past years, our oil and gas properties have had steep rates of decline and short estimated productive lives.
Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves. Also, we may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot give assurance that our future exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.
We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.
Our business is capital intensive and requires us to spend substantial amounts of capital for exploration and development activities. Low product price environments such as the downturn in oil prices that we are currently experiencing, as well as operating difficulties and other factors, many of which are beyond our control, may cause our revenues and cash flows from operating activities to decrease and may limit our ability to internally fund our exploration and development activities. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot give assurance that additional debt or equity financing will be available on terms acceptable to us, or that cash flows provided by operations will be sufficient to meet our capital expenditures requirements.
Our limited capital expenditures and drilling program, when coupled with a sustained depression in oil and natural gas prices, will significantly reduce our cash flow and constrain future drilling, which could have a material adverse effect on our business, financial condition or results of operations.
Historically, we have made substantial capital expenditures for the exploration and development of oil and natural gas reserves. The combination of lower prices and reduction of our drilling operations resulted in reduced production and operating cash flows in 2016. A sustained depression in oil and natural gas prices combined with reduced production and accompanying lower cash flows will adversely affect our business, financial condition or results of operations.
We have substantial indebtedness. Our leverage and the covenants in our debt agreements could negatively impact our financial condition, liquidity, results of operations and business prospects.
As of December 31, 2016, the principal amount of our outstanding consolidated debt was approximately $848 million, consisting of $352.5 million (net of $24.7 million of original issue discount and debt issuance costs) under the second lien term loan credit facility and $495.5 million (net of $4.5 million of original issue discount and debt issuance costs) in outstanding principal amount of 7.75% Senior Notes due 2019 (the “2019 Senior Notes”). In March 2016, we amended our revolving credit facility and reduced the borrowing base and aggregate lender commitments from $450 million to $100 million and entered into a new term loan credit facility providing for the issuance of term loans in the principal amount of $350 million. The revolving credit facility, the term loan credit agreement and the indenture governing the 2019 Senior Notes (the “Indenture”) each impose significant restrictions on our ability to take certain actions, including our ability to incur additional indebtedness, sell certain assets, merge, make investments or loans, issue redeemable or preferred stock, pay distributions or dividends, create liens, guarantee other indebtedness and enter into new lines of business.
Our level of indebtedness and the restrictive covenants in our debt agreements could have important consequences on our business and operations. Among other things, these may:
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require us to use a significant portion of our cash flows to pay principal and interest on the debt, which will reduce the amount available to fund working capital, capital expenditures, and other general corporate purposes;
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adversely affect the credit ratings assigned by third-party rating agencies, which have in the past downgraded, and may in the future downgrade their ratings of our debt and other obligations due to changes in our debt level or our financial condition;
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limit our access to the capital markets;
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increase our borrowing costs and impact the terms, conditions and restrictions contained in our debt agreements, including the addition of more restrictive covenants;
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limit our flexibility in planning for and reacting to changes in our business as covenants and restrictions contained in our existing and possible future debt arrangements may require that we meet certain financial tests and place restrictions on the incurrence of additional indebtedness;
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place us at a disadvantage compared to similar companies in our industry that have less leverage; and
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make us more vulnerable to economic downturns and adverse developments in our business.
A higher level of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other expenses will depend on our future performance. Our future performance will be affected by oil and gas prices, financial, business, domestic and worldwide economic conditions, governmental and environmental regulations and other factors, many of which we are unable to control. Under current commodities pricing, we expect that we will be in compliance with all financial covenants through 2017. Further deterioration in commodities pricing, however, could result in non-compliance and cause us to seek to negotiate revisions to our loan covenants, which relief may not be obtainable from our bank lenders. If our cash flows are not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell shares of our stock on terms that we do not find attractive, if these options are available at all.
We cannot be certain that funding will be available to the extent required to fund our development and other operations.
If funding under our revolving credit facility becomes unavailable or limited, we may need to seek additional funding in order to finance our development and operations. This additional or replacement financing may not be available as needed, or may be available only in limited amounts and on more expensive or otherwise unfavorable terms. In such a scenario, we may be unable to implement a drilling plan to replace or increase our reserves, take other measures to enhance our existing business, or pursue business opportunities or respond to competitive pressures, and our production, revenues and results of operations could be adversely affected.
The credit risk of financial institutions could adversely affect us.
We have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies and their affiliates. These transactions expose us to credit risk in the event of default by our counterparty,
principally with respect to hedging transactions but also insurance contracts and bank lending commitments. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us.
Our hedging transactions could result in financial losses or could reduce our income and cash flow.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into and may in the future enter into hedging transactions for a portion of our expected oil and gas production. These transactions could result in both realized and unrealized hedging losses. Conversely, if we do not enter into hedging transactions and product prices for our oil and gas production decline significantly during any unhedged production periods, we may realize a material reduction in our operating margins. The prolonged effects of lower operating margins on our business are significant since they reduce our cash flow from operations and diminish the present value of our oil and gas reserves.
The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative transactions. For example, the derivative instruments we utilize are primarily based on NYMEX futures prices, which may differ significantly from the actual crude oil and gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and the revolving credit facility and the term loan credit facility also mandate, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions. If our actual future production is higher than we estimated, we will have greater commodity price exposure than we intended. If our actual future production is lower than the nominal amount that is subject to our derivative instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flows from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
In addition, our hedging transactions are subject to the following risks:
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we may be limited in receiving the full benefit of increases in oil and gas prices as a result of these transactions;
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a counterparty may not perform its obligation under the applicable derivative instrument or may seek bankruptcy protection;
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there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
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the steps we take to monitor our derivative instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and gas reserves, and our revenues, profitability and cash flows to be materially different from our estimates.
The accuracy of estimated proved reserves and estimated future net cash flows from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses and other matters. Although we believe that our estimated proved reserves represent reserves that we are reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn could adversely affect our cash flows, results of operations, financial condition and the availability of capital resources. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Downward adjustments to our estimated proved reserves could require us to impair the carrying value of our oil and gas properties, which would reduce our earnings and our shareholders’ equity.
The present value of proved reserves will not necessarily equal the current fair market value of our estimated oil and gas reserves. In accordance with reserve reporting requirements of the SEC, we are required to establish economic production for
reserves on an average historical price. Actual future prices and costs may be materially higher or lower than those required by the SEC. The timing of both the production and expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.
The estimated proved reserve information is based upon reserve reports prepared by independent engineers. From time to time, estimates of our reserves are also made by the lenders under the revolving credit facility in establishing the borrowing base under the revolving credit facility and by our engineers for use in developing business plans and making various decisions. Such estimates may vary significantly from those of the independent engineers and have a material effect upon our business decisions and available capital resources.
Our producing properties are largely concentrated in one major geographic area, the Permian Basin. Concentrations of reserves in a limited geographic area may disproportionately expose us to operational, regulatory and geological risks.
Our core producing properties are geographically concentrated in Southern Reeves County, Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of oil, gas or NGL.
In addition, as of December 31, 2016, a significant portion of our proved reserves was derived from the Wolfcamp formation in the Delaware Basin. This concentration of assets within one producing formation exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
Our proved undeveloped locations are scheduled to be drilled over several years, subjecting us to uncertainties that could materially alter the occurrence or timing of our drilling activities.
We have assigned proved undeveloped reserves to certain of our drilling locations as an estimation of our future multi-year development activities on our existing acreage. These identified locations represent a significant part of our growth strategy. At December 31, 2016, our estimated proved undeveloped reserves were 37% of total estimated proved reserves. Our ability to drill and develop these locations is subject to a number of uncertainties, including (1) our ability to timely drill wells on lands subject to complex development terms and circumstances; (2) the availability of capital, equipment, services and personnel; (3) seasonal conditions; (4) regulatory and third-party approvals; (5) oil and gas prices; and (6) drilling and completion costs and results. Because of these uncertainties, we may defer drilling on, or never drill, some or all of these potential locations. If we defer drilling more than five years from the date proved undeveloped reserves were first assigned to a drilling location, we may be required under SEC guidelines to downgrade the category of the applicable reserves from proved undeveloped to probable. Any reclassification of reserves from proved undeveloped to probable could reduce our ability to borrow money and could reduce the value of our debt and equity securities.
We may reclassify proved undeveloped reserves to unproved due to our inability to commit sufficient capital within the required five-year development window, which could adversely affect the value of our properties.
The SEC generally requires that any undrilled location can be classified as a proved undeveloped reserve only if a development plan has been adopted indicating that the location is scheduled to be drilled within five years. Our recent reduction of our drilling program in response to depressed oil and natural gas prices is likely to impact our ability to develop proved undeveloped reserves within such five-year period. If we continue our limited drilling plan over a significant period of time or our future access to capital resources is limited, we will also likely further delay our development of our proved undeveloped reserves or ultimately suspend such development which could result in the reclassification of a significant amount of our proved undeveloped reserves as probable or possible reserves. A significant reclassification of proved undeveloped reserves could adversely affect the value of our properties.
Price declines may result in impairments of our asset carrying values.
Commodity prices have a significant impact on the present value of our proved reserves. Accounting rules require us to impair, as a non-cash charge to earnings, the carrying value of our oil and gas properties in certain situations. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable, and an impairment may be required. Any impairment charges we record in the future could have a material adverse effect on our results of operations in the period incurred.
Our exploration activities subject us to greater risks than development activities.
Generally, our oil and gas exploration activities pose a higher economic risk to us than our development activities. Exploration activities involve the drilling of wells in areas where there is little or no known production. Development activities relate to increasing oil or gas production from an area that is known to be productive by drilling additional wells, working over and recompleting existing wells and other production enhancement techniques. Exploration projects are identified through subjective analysis of geological and available geophysical data, including the use of 3-D seismic and other available technology. By comparison, the identification of development prospects is significantly based upon existing production surrounding or adjacent to the proposed drilling site.
To the extent we engage in exploration activities, we have a greater risk of drilling dry holes or not finding oil and gas that can be produced economically. The seismic data and other technology we use does not allow us to know with certainty prior to drilling a well whether oil or gas is present or can be produced economically. We cannot assure you that any of our future exploration efforts will be successful. If these activities are unsuccessful, it will have a significant adverse effect on our results of operations, cash flows and capital resources.
Drilling oil and gas wells is a high-risk activity and subjects us to a variety of factors that we cannot control.
Drilling oil and gas wells, including development wells, involves numerous risks, including the risk that we may not encounter economically productive oil or gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and result in a total loss of our investment. In addition, we are often uncertain as to the future cost or timing of drilling, completing and operating wells. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental requirements, which may increase our costs or restrict our activities; and
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costs of, or shortages or delays in the availability of, drilling rigs, tubular materials and equipment and services or crews.
If we do not encounter reserves that can be produced economically or if our drilling operations are curtailed, delayed or cancelled, it could have a significant adverse effect on our results of operations, cash flows and financial condition.
Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.
Our ongoing business strategy includes growing our reserves and drilling inventory through acquisitions. Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities including groundwater contamination, may not be discovered even when a review or inspection is performed.
Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write-down the carrying value of our oil and gas properties, which would reduce our earnings and our shareholders’ equity.
Our failure to integrate acquired properties successfully into our existing business could result in our incurring unanticipated expenses and losses. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in
connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.
The process of integrating acquired properties into our existing business may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of our existing business.
We may not be insured against all of the operating hazards to which our business is exposed.
Our operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as windstorms, lightning strikes, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids (including fluids used in hydraulic fracturing activities), fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations, all of which could result in a substantial loss. We maintain insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, we cannot give assurance of the continued availability of insurance at premium levels that justify its purchase.
Our business depends on oil and gas transportation facilities, most of which are owned by others.
The marketability of our oil and gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, maintenance and repair and general economic conditions could adversely affect our ability to produce, gather and transport oil and gas.
Future shortages of available drilling rigs, equipment and personnel may delay or restrict our operations.
The oil and gas industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies and personnel. During these periods, the costs and delivery times of drilling rigs, equipment and supplies are substantially greater. In addition, demand for, and wage rates of, qualified drilling rig crews rise with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel may increase drilling costs or delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Market conditions or operational impediments may hinder our access to oil and gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and gas processing or transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas, the proximity of reserves to pipelines and terminal facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from mechanical, operational or weather-related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering and transportation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could adversely affect our business, financial condition and results of operations. We may be required to shut-in or otherwise curtail production from wells due to lack of a market or inadequacy or unavailability of oil, gas or NGL pipeline or gathering, transportation or processing capacity. If that were to occur, then we would be unable to realize revenues from those wells until suitable arrangements were made to market our production.
Because we have no current plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
We have never paid any cash dividends on our common stock, and the Board does not currently anticipate paying any cash dividends to our shareholders in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of the Board and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the Board deems relevant. Covenants contained in the revolving credit facility, the term loan credit facility and the Indenture restrict the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
Investors seeking cash dividends should not purchase our common stock. For information on our proposed merger with Noble Energy, see “Item 1 - Business - Recent Developments - Proposed Merger with Noble Energy” above.
Our industry is highly competitive.
Competition in all areas of our operations is intense. We experience competition from major and independent oil and gas companies and oil and gas syndicates in bidding for desirable oil and gas properties, as well as in acquiring the equipment, data and labor required to operate and develop such properties. A number of our competitors have financial resources and acquisition, exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete with these companies. Competitors may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to increase reserves in the future will depend on our success at selecting and acquiring suitable properties and prospects for future development and exploration activities.
In addition, the oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenues. The market for our oil, gas and NGL production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and NGL, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.
Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.
Our success is highly dependent on our senior management. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.
Clayton W. Williams, Jr. and his children’s limited partnership have significant influence over the Company.
Clayton W. Williams, Jr., age 85, beneficially owns, either individually or through his affiliates, 17.6% of the outstanding shares of our common stock. Mr. Williams is also Chairman of the Board and Chief Executive Officer. As a result, Mr. Williams has significant influence in matters voted on by our shareholders, including the election of the Board members, and in other facets of our business.
WCPL, a limited partnership in which Mr. Williams’ adult children are the limited partners, owns an additional 17.3% of the outstanding shares of our common stock. Mel G. Riggs, our President, is the sole member in the general partner of WCPL and has the power to vote or direct the voting of the shares held by WCPL. In voting these shares, Mr. Riggs will not be acting in his capacity as an officer and director of the Company and will consider the interests of WCPL and Mr. Williams’ children. They may have interests that differ from the interests of our other shareholders.
The retirement, incapacity or death of Mr. Williams, or any change in the power to vote shares beneficially owned by Mr. Williams or held by WCPL, could result in negative market or industry perception and could have a material adverse effect on our business.
Ares has significant influence over the Company, and its interests may differ from those of our other shareholders.
As of February 23, 2017, Ares owned either individually or through its affiliates, 42.0% of the outstanding shares of our common stock. In addition, Ares possesses the right to elect up to two members of our Board and to recommend one other director to the Nominating and Governance Committee of the Board for appointment to the Board. Through its elected and recommended Board members and substantial ownership of our common stock, Ares has significant influence in matters voted on by our shareholders, including the election of our Board members, and its interests may differ from the interests of our other shareholders.
By extending credit to our customers, we are exposed to potential economic loss.
We sell our oil and gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells and enter into derivatives with various counterparties. As appropriate, we obtain letters of credit to secure amounts
due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. We cannot give assurance that we will not suffer any economic loss related to credit risks in the future.
Compliance with laws and regulations governing our activities could be costly and could negatively impact production.
Our oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.
All of the states in which we operate generally require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from our properties.
The FERC regulates interstate gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.
Our sales of oil and NGL are not presently regulated and are made at market prices. The price we receive from the sale of these products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs, which may have the effect of reducing wellhead prices for oil and NGL.
Section 1(b) of the NGA exempts natural gas gathering facilities from FERC’s jurisdiction. We believe that the gas gathering facilities we own meet the traditional tests the FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. Under the EP Act 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations in excess of $1 million per day for each violation and disgorgement of profits associated with any violation. While our gas operations have not been regulated by the FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting. The FERC prohibits market manipulation in connection with the purchase or sale of natural gas. The CFTC has similar authority under the Commodity Exchange Act and regulations it has promulgated thereunder with respect to certain segments of the physical and futures energy commodities market including oil and natural gas. The FTC also prohibits manipulative or fraudulent conduct in the wholesale petroleum market with respect to sales of commodities, including crude oil, condensate and NGL. These agencies have substantial enforcement authority, including the ability to impose penalties for current violations which may potentially exceed $1 million per day for each violation. Additional rules and legislation pertaining to those and other matters may be considered or adopted by these agencies from time to time. Failure to comply with those regulations in the future could subject us to criminal and civil penalties.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. For example, portions of our natural gas and crude oil gathering systems in Southern Reeves County, Texas are regulated by the RCT. Accordingly, we have filed tariffs with the RCT with respect to those systems. Our gathering operations are also subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather gas or crude oil. In addition, our gas and crude oil gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services.
Our oil and gas exploration and production and related activities are subject to extensive environmental regulations and to laws that can give rise to substantial liabilities from environmental contamination.
Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the emission and discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and non-hazardous and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws regardless of fault. Under a number of environmental laws, such liabilities may also be strict, joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.
We have incurred expenses in connection with environmental compliance, and we anticipate that we will continue to do so in the future. Failure to comply with extensive applicable environmental laws and regulations could result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective obligations, the occurrence of delays in permitting or performance of projects, and the issuance of administrative or judicial orders limiting operations or prohibiting certain activities. Some of our properties, including properties in which we have an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation. Some of our operations are located in environmentally sensitive environments, such as coastal waters, wetlands and other protected areas. Some of our operations are in areas particularly susceptible to damage by hurricanes or other destructive storms, which could result in damage to facilities and discharge of pollutants. In addition, claims are sometimes made or threatened against companies engaged in oil and natural gas exploration and production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against us as well as companies we have acquired. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and financial condition and results of operations.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of proposed legislation.
Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively impact the value of an investment in our common stock.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and gas that we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration by states or groupings of states of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment and has adopted regulations under existing provisions of the CAA that establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States on an annual basis, including, among others, onshore and offshore oil and natural gas
production facilities and onshore processing, transmission, storage and distribution facilities, which include certain of our operations. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align the reporting rules with the NSPS.
Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published NSPS, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand the previously issued NSPS Subpart OOOO requirements issued in 2012 by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. Moreover, in November 2016, the EPA issued a final ICR seeking information about methane emissions from facilities and operations in the oil and natural gas industry. The EPA has indicated that it intends to use the information from this request to develop Existing Source Performance Standards for the oil and natural gas industry. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France to prepare an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions but, rather, includes pledges to voluntarily limit or reduce future emissions.
The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that require reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us or, in the case of our pipeline or treating or dehydration services, our oil and natural gas exploration and production customers to incur increased costs that could have an adverse effect on our business, financial condition and results of operations. Moreover, such new legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and natural gas we or our customers produce and lower the value of our reserves as well as reduce demand for our pipeline and treating and dehydration services. 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, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. At this time, we have not developed a comprehensive plan to address the legal, economic, social or physical impacts of climate change on our operations.
The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act, the CFTC has issued final regulations to set 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 position limits rule was vacated by the U.S. District Court for the District of Columbia in September of 2012 although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definitions of “swap,” “security-based swap,” “swap dealer” and “major swap participant.” The Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects.
The Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and any new regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral that could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce
the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our financial condition and results of operations.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions or other similar state agencies, but several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances.” The EPA noted that the following hydraulic fracturing water cycle activities and local-or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Additionally, the EPA has taken the following actions: in 2014, asserted regulatory authority pursuant to the SDWA’s UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; in 2012 and June 2016, issued final regulations under the CAA governing performance standards, including first-time standards in 2016 for the capture of methane emissions released during hydraulic fracturing; in June 2016, published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants; and in 2014, issued an advanced notice of proposed rulemaking under the Toxic Substances Control Act that would require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. In June 2016, the U.S. District Court of Wyoming struck down this final rule, finding that the BLM lacked authority to promulgate the rule, and that decision is currently being appealed by the federal government.
From time to time, the U.S. Congress has considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states, including Texas and New Mexico, where we conduct operations, have adopted and other states are considering adopting legal requirements that could impose more stringent permitting, chemical disclosure and well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we or, in the case of our pipeline and treating or dehydration services, our customers operate, we or our customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded in the drilling of wells or in the volume that we or our customers are ultimately able to produce from reserves.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. The occurrence of these or similar developments may result in limitations being placed on allocations of water due to needs by third party businesses with more senior contractual or permitting rights to the water. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our operations and have a corresponding adverse effect on our business, results of operations and financial condition.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls, substantial changes to existing integrity management programs, or more stringent enforcement of applicable legal requirements could subject us to increased capital and operating costs and operational delays.
Certain of our pipelines are subject to regulation by PHMSA under the HLPSA with respect to oil and the NGPSA with respect to natural gas. The HLPSA and NGPSA govern the design, installation, testing, construction, operation, replacement and management of oil and natural gas pipeline facilities. These laws have resulted in the adoption of rules by PHMSA, that, among other things, require transportation pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquid pipelines, which regulations may impose more stringent requirements than found under federal law. Historically, our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. New laws or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays.
The HLPSA and NGPSA were amended by the 2011 Pipeline Safety Act, which increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of hazardous liquid or natural gas pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property or the environment.
The adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on our results of operations. For example, in January 2017, PHMSA issued a final rule that significantly extends and expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments, leak detection and repairs, regardless of the pipeline’s proximity to a high consequence area. The final rule also imposes new reporting requirements for certain unregulated pipelines, including all hazardous liquid gathering lines. However, the date of implementation of this final rule by publication in the Federal Register is uncertain given the recent change in presidential administrations. Additionally, in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as five dwellings within a potential impact area; and requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressure. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines.
A terrorist attack, anti-terrorist efforts or other armed conflict could adversely affect our business by decreasing our revenues and increasing our costs.
A terrorist attack, anti-terrorist efforts or other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a decrease in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Item 1B
Item 1B - Unresolved Staff Comments
None.
Item 2
Item 2 - Properties
Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. At December 31, 2016, we had interests in 2,726 gross (1,096.7 net) oil and gas wells and owned leasehold interests in approximately 423,000 gross (232,000 net) undeveloped acres.
Oil and Gas Reserves
Total Proved Reserves
The following table sets forth our estimated quantities of proved reserves as of December 31, 2016, all of which are located within the United States.
(a)
None of our oil and gas reserves are derived from non-traditional sources.
(b)
Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.
The present value of our future net cash flows from proved reserves, before deductions for estimated future income taxes, discounted at 10% (“PV-10”), totaled $166.6 million at December 31, 2016, which is net of $37.8 million of present value of estimated net abandonment costs. The commodity prices used to estimate proved reserves and their related PV-10 at December 31, 2016 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January 2016 through December 2016. The benchmark average prices for 2016 were $42.75 per barrel of oil and $2.49 per MMBtu of natural gas. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $36.60 per barrel of oil, $13.60 per barrel of NGL and $2.36 per Mcf of natural gas over the remaining life of our proved reserves. Operating costs were not escalated.
Adjustments to benchmark average prices, which are generally referred to as price differentials, were computed on a property-by-property basis by comparing historical first-day-of-the-month benchmark prices for oil and natural gas to the historical prices for oil, NGL and natural gas actually received by us. Historical price differentials vary by property based on each property’s production and marketing situation and include:
•
area-specific market adjustments, referred to as basis differentials, for oil, natural gas and NGL as discussed under “Item 1 - Business - Marketing Arrangements;”
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gravity, hydrogen sulfide content and other quality characteristics of produced oil;
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the volume of processed NGL derived from our natural gas production, including the mix of the NGL components between ethane, propane, butane and natural gasoline;
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the Btu content of natural gas production and the value of any imbedded NGL components that are reported as natural gas sales; and
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the amount of transportation and marketing fees levied on oil, gas and NGL production, which vary based on factors such as the distance of a property from its delivery point, available markets and other pricing adjustments that vary from contract to contract.
Price differentials per barrel of oil and NGL and per Mcf of natural gas are subject to change and may vary materially in the future from the computed price differentials at December 31, 2016. Adverse changes in our price differentials could reduce our cash flow from operations and the PV-10 of our proved reserves.
PV-10 is not a generally accepted accounting principle (“GAAP”) financial measure, but we believe it is useful as a supplemental disclosure to the standardized measure of discounted future net cash flows presented in our consolidated financial statements. To compute our standardized measure of discounted future net cash flows at December 31, 2016, we began with the PV-10 of our proved reserves, which is net of $37.8 million of the present value of our net abandonment costs, and deducted the present value of estimated future income taxes of $7.7 million, discounted at 10%. At December 31, 2016, our standardized measure of discounted future net cash flows totaled $159 million. While the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each company, the PV-10 of proved reserves is based on prices and discount factors that are consistent for all companies and can be used within the industry and by securities analysts to evaluate proved reserves on a more comparable basis.
The following table summarizes certain information as of December 31, 2016, regarding our estimated proved reserves in each of our principal producing areas.
(a)
Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.
The following table summarizes changes in our estimated proved reserves during 2016.
Extensions and discoveries. Extensions and discoveries in 2016 added 4,077 MBOE of proved reserves, replacing 82% of our 2016 production. These additions resulted primarily from our Delaware Basin program in Southern Reeves County, Texas. Of the total reserve additions, proved developed reserves accounted for 2,660 MBOE, while the remaining 1,417 MBOE were proved undeveloped reserves.
Revisions. The 168 MBOE of net downward revisions in proved reserves resulted from a combination of (1) net upward revisions of 11,670 MBOE related primarily to performance in our Delaware Basin program in Southern Reeves County, Texas and (2) downward revisions of 11,838 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves.
Sales of minerals-in-place. We sold substantially all of our assets in the Giddings Area in East Central Texas in December 2016, our interests in certain wells in Glasscock County, Texas in July 2016 and our interests in certain wells in Oklahoma in June 2016 resulting in a decrease of 10,728 MBOE.
Proved Undeveloped Reserves
Summary of changes in proved undeveloped reserves
The following table summarizes changes in our estimated proved undeveloped reserves during 2016.
We added 1,417 MBOE of proved undeveloped reserves from extensions and discoveries related to Delaware Basin drilling locations. Net upward revisions of 1,070 MBOE resulted primarily from the combination of (1) net upward revisions of 10,969 MBOE related to performance in our Delaware Basin program in Southern Reeves County, Texas and (2) downward revisions of 9,899 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves. We did not convert any proved undeveloped reserves to proved developed reserves in 2016.
Scheduled PUD locations at year-end 2016
Under SEC rules, we may classify undrilled locations as having PUD reserves only if we have adopted a development plan indicating that those locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time. We derive this development plan by first preparing a five-year projection of future sources and uses of funds as of each date of determination, giving consideration to many factors such as our expectations for commodity prices, oil and gas production, cash flow from operations, adequacy of liquidity and other financial resources, pre-drill well economics, and lease expirations, among others. Based on these financial projections, we classify those qualified undrilled locations that otherwise meet the criteria as PUD locations only to the extent we intend to develop those PUD reserves with expected available future capital sources within five years of first booking. Any other potential PUD locations that cannot be drilled within such five-year period are classified as probable reserves. Accordingly, all of our PUD reserves as of December 31, 2016 are scheduled for development within five years of first booking.
Considering the amount of 2017 lease expirations, we did not schedule any PUD locations for drilling in 2017. We scheduled estimated future capital spending for PUD development and related PUD reserves at year-end 2016, as follows: 2018 - $38 million and 3,704 MBOE; 2019 - $68.1 million and 7,003 MBOE; and 2020 - $33.8 million and 1,982 MBOE. Substantially all of these PUD locations are located in our core Delaware Basin play in Southern Reeves County, Texas. An additional $0.7 million of estimated future capital spending and 88 MBOE of proved undeveloped reserves is attributable to our general partner interest in an affiliated partnership, which is proportionately consolidated in our financial statements. If commodity prices materially decline from current levels, future PUD development assessments could result in a reduction in development capital expenditures and write-downs of proved undeveloped reserves.
Alternative pricing cases
In addition to the estimated proved reserves disclosed above in accordance with the commodities pricing required by the reserves rule (the “SEC Case”), the following table compares certain information regarding our SEC proved reserves to a Futures Pricing Case.
(a)
Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.
Futures Pricing Case. The Futures Pricing Case discloses our estimated proved reserves using future market-based commodities prices instead of the average historical prices used in the SEC Case. Under the Futures Pricing Case, we used monthly futures contract prices, as quoted on the NYMEX on December 31, 2016, as benchmark prices for 2017 through 2021, and escalated prices at 3% per year for all subsequent years beginning 2022. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in weighted average adjusted prices of $57.69 per barrel of oil, $21.32 per barrel of NGL and $3.33 per Mcf of natural gas over the remaining life of the proved reserves. We escalated operating costs at 3% per year beginning 2018.
Reserve estimation procedures
Overview
We have established a system of internal controls over our reserve estimation process, which we believe provides us reasonable assurance that reserve estimates have been prepared in accordance with the SEC and Financial Accounting Standards Board (the “FASB”) standards. These controls include oversight by trained technical personnel employed by us and by the use of qualified independent petroleum engineers to evaluate our proved reserves on an annual basis. Substantially all of our estimated proved reserves as of December 31, 2016 were derived from engineering evaluation reports prepared by Williamson Petroleum Consultants, Inc. (“Williamson”) and Ryder Scott Company, L.P. (“Ryder Scott”). Of our total SEC Case estimated proved reserves, Williamson evaluated 74.3% and Ryder Scott evaluated 24.6% on a BOE basis. These procedures also include oversight by our senior management and board of directors in reviewing and approving our annual estimates of proved reserves.
Qualifications of technical manager and consultants
Ronald D. Gasser, our Vice President - Engineering, is the person within the Company who is primarily responsible for overseeing the preparation of the reserve estimates. Mr. Gasser joined the Company in 2002 as a Senior Engineer working on acquisitions/divestitures and special projects, became Engineering Manager in 2006 and was promoted to his current position as Vice President - Engineering in October 2012. Mr. Gasser has 34 years of experience as a petroleum engineer, including 31 years directly involved in the estimation and evaluation of oil and gas reserves. Mr. Gasser holds a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers.
Williamson is an independent petroleum engineering consulting firm registered in the State of Texas, and John D. Savage, Executive Vice President - Engineering Manager of Williamson, is the technical person primarily responsible for evaluating the proved reserves covered by its report. Mr. Savage has 35 years of experience in evaluating oil and gas reserves, including 33 years of experience as a consulting reservoir engineer. Mr. Savage holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. He is a Registered Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers and the Society of Independent Professional Earth Scientists.
Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over 75 years. William K. Fry, Vice President of Ryder Scott, is the technical person primarily responsible
for evaluating the proved reserves covered by its report. Mr. Fry has over 30 years of experience in the estimation and evaluation of petroleum reserves. Mr. Fry holds a Bachelor of Science degree in Mechanical Engineering from Kansas State University. He is a Registered Professional Engineer in the State of Texas.
Technology used to establish proved reserves
Under current SEC standards, proved reserves are those quantities of oil and natural gas, 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 governmental 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 term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas will be recovered. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. “Reliable technology” is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our estimated proved reserves, we employ technologies that have been demonstrated to yield results with consistency and repeatability. The technological data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations. Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technological data to assess the reservoir continuity. In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities. Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs and completion flow data. When using production decline curve analysis or analogy to estimate proved reserves, we limit our estimates to the quantities of oil and gas derived through volumetric calculations.
Virtually all of our additions to proved reserves in 2016 were derived from wells drilled in Southern Reeves County, Texas. A significant amount of technological data is available in these areas, which we believe allows us to estimate with reasonable certainty the proved reserves and production decline rates attributable to most of our reserve additions through analogy to historical performance from wells in the same reservoirs. None of our additions to proved reserves for 2016 were estimated solely on volumetric calculations.
Processes and controls
Mr. Gasser and his engineering staff maintain a reserves database covering substantially all of our oil and gas properties utilizing Aries™, a widely used reserves and economics software package licensed by a unit of The Halliburton Company. Some of our properties are not evaluated since they are individually and collectively insignificant to our total proved reserves and related PV-10. Our engineering staff assimilates all technological and operational data necessary to evaluate our reserves and updates the reserves database throughout the year. Technological data is described above under “- Technology used to establish proved reserves.” Operational data include ownership interests, product prices, operating expenses and future development costs.
Using the most appropriate method available, Mr. Gasser applies his professional judgment, based on his training and experience, to project a production profile for each evaluated property. Mr. Gasser consults with other engineers and geoscientists within the Company as needed to validate the accuracy and completeness of his estimates and to determine if any of the technological data upon which his estimates were based are incorrect or outdated.
The engineering staff consults with our accounting department to validate the accuracy and completeness of certain operational data maintained in the reserves database, including ownership interests, average commodity prices, price differentials and operating costs.
Although we believe that the estimates of reserves prepared by our engineering staff have been prepared in accordance with professional engineering standards consistent with SEC and FASB guidelines, we engage independent petroleum engineering consultants to prepare annual evaluations of our estimated reserves. After Mr. Gasser and our engineering staff have made an internal evaluation of our estimated reserves, we provide copies of the Aries™ reserves database to Ryder Scott as it relates to
properties owned by our wholly owned subsidiary, Southwest Royalties, Inc., and to Williamson as it relates to properties owned by CWEI. In addition, we provide to the consultants for their analysis all pertinent data needed to properly evaluate our reserves. The services provided by Williamson and Ryder Scott are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about the evaluations performed by Williamson and Ryder Scott, see copies of their respective reports filed as exhibits to this Form 10-K.
Both Williamson and Ryder Scott use the Aries™ reserves database that we provide to them as a starting point for their evaluations. This process reduces the risk of errors that can result from data input and also results in significant cost savings to us. The petroleum engineering consultants generally rely on the technical and operational data provided to them without independent verification; however, in the course of their evaluation, if any issue comes to their attention that questions the validity or sufficiency of that data, the consultants will not rely on the questionable data until they have resolved the issue to their satisfaction. The consultants analyze each production decline curve to determine if they agree with our interpretation of the underlying technical data. If they arrive at a different conclusion, the consultants revise the estimates in the database to reflect their own interpretations.
After Williamson and Ryder Scott complete their respective evaluations, they return a modified Aries™ reserves database to our engineering staff for review. Mr. Gasser identifies all material variances between our initial estimates and those of the consultants and discusses the variances with Williamson or Ryder Scott, as applicable, in order to resolve the discrepancies. If any variances relate to inaccurate or incomplete data, corrected or additional data is provided to the consultants and the related estimates are revised. When variances are caused solely by judgment differences between Mr. Gasser and the consultants, we accept the estimates of the consultants.
Prior to completion of the final reserve estimates, our financial accounting group under the direction of Jaime R. Casas, Senior Vice President and Chief Financial Officer, assess compliance with the SEC five-year development rule and make recommendations to Mr. Gasser regarding the scheduled timing and ultimately any required downgrade of undrilled locations previously booked as proved undeveloped to probable. See discussion under “- Proved Undeveloped Reserves.” During this process, the financial accounting group (1) reviews changes in our drilling plans during the recently completed year, (2) assesses the impact that such changes may have had on the scheduled PUD drilling program as reflected in the prior year reserve report and (3) makes recommendations to defer drilling if permitted within the SEC five-year development rule or to downgrade affected PUD locations to probable.
Upon delivery of the final reserve estimates, our financial accounting group reconciles changes in reserve estimates during the year by source, consisting of changes due to extensions and discoveries, purchases/sales of minerals-in-place, revisions of previous estimates and production. Revisions of previous estimates are further analyzed by changes related to pricing and changes related to performance. All material fluctuations in reserve quantities identified through this analysis are discussed with Mr. Gasser. Although unlikely, if a material error in the estimated reserves is discovered through this review process, Mr. Gasser will submit the facts related to the error to the appropriate consultant for correction prior to the public release of the estimated reserves.
Senior management has historically been involved in the process of estimating our proved reserves. Mr. Casas has been involved in the review of pricing and ownership data maintained in the reserves database, including ownership interests, average commodity prices, price differentials and operating costs. Mr. Casas has also consulted with Mr. Riggs, President, on matters involving significant assumptions to the five-year forecasts required to assure reasonable expectations for future financing of PUD development projects, as well as significant changes in reserve estimates from year to year. Beginning with the year-end 2015 reserves estimates, we have added processes designed to more closely monitor our performance in drilling PUD locations in accordance with scheduled development plans set forth in the prior year reserve report. These enhanced processes include a detailed review by the Board of actual versus scheduled PUD drilling, including a discussion by the Board with management of the significant reasons for the material historical variances in year-to-year PUD development plans as reflected in our most recent year-end reserve reports.
Other information concerning our proved reserves
The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and PV-10 are based on various assumptions and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
Since January 1, 2016, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.
Delivery Commitments
As of December 31, 2016, we had no commitments to provide fixed and determinable quantities of oil or natural gas in the near future under contracts or agreements, other than through customary marketing arrangements that require us to nominate estimated volumes of natural gas production for sale during periods of one month or less.
Exploration and Development Activities
We drilled, or participated in the drilling of, the following numbers of wells during the periods indicated.
The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.
Productive Well Summary
The following table sets forth certain information regarding our ownership, as of December 31, 2016, of productive wells in the areas indicated.
Volumes, Prices and Production Costs
All of our oil and gas properties are located in the United States. The following table sets forth certain information regarding the production volumes of, average sales prices received from and average production costs associated with all of our sales of oil and gas production for the periods indicated.
(a)
Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.
(b)
Oil and gas sales includes $1.5 million for the year ended December 31, 2016, $4.5 million for the year ended December 31, 2015 and $7.7 million for the year ended December 31, 2014 of amortized deferred revenue attributable to the volumetric production payment (“VPP”) transaction effective March 1, 2012. In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. The calculation of average realized sales prices excludes production of 53,026 barrels of oil and 35,735 Mcf of gas for the year ended December 31, 2015 and 102,011 barrels of oil and 45,392 Mcf of gas for the year ended December 31, 2014 associated with the VPP.
(c)
No commodity derivatives were designated as cash flow hedges in the table above. All gains or losses on settled commodity derivatives were included in other income (expense) - gain (loss) on commodity derivatives.
(d)
Excludes property taxes and severance taxes.
Only one field, the Wolfbone Trend field in Southern Reeves County, Texas, accounted for 15% or more of our total proved reserves (on a BOE basis) as of December 31, 2016. The following table discloses our oil, gas and NGL production from this field for the periods indicated.
(a)
Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.
Development, Exploration and Acquisition Expenditures
The following table sets forth certain information regarding the costs we incurred in our development, exploration and acquisition activities during the periods indicated.
Acreage
The following table sets forth certain information regarding our developed and undeveloped leasehold acreage as of December 31, 2016 in the areas indicated. This table excludes options to acquire leases and acreage in which our interest is limited to royalty, overriding royalty and similar interests.
(a)
Net undeveloped acres are attributable to the following areas: Colorado - 29,804; Alabama - 15,133; East Texas - 13,587; Nevada - 8,535; Louisiana - 6,612; and Other - 13,881.
The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2016.
(a)
Acres expiring are based on contractual lease maturities. We may extend the leases prior to their expiration based upon planned activities or for other business activities.
Desta Drilling
Through our wholly owned subsidiary, Desta Drilling, we currently have eight drilling rigs available for our use or for contract drilling operations. The Desta Drilling rigs are primarily reserved for our use, but are available to conduct contract drilling operations for third parties. Due to the downturn in oil prices, all our rigs have been idle since November 2015.
Offices
We lease approximately 87,000 square feet of office space in Midland, Texas from a related partnership for our corporate headquarters. We also lease approximately 3,700 square feet in College Station, Texas from unaffiliated third parties.
Item 3
Item 3 - Legal Proceedings
In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. In October 2013, a judge ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million. A loss of $1.4 million was recorded for the year ended December 31, 2013 in connection with the judgment. CWEI appealed the judgment and on July 8, 2015, the El Paso Court of Appeals reversed the trial court judgment in its entirety and rendered judgment that Plaintiffs take nothing on all claims against CWEI and Chesapeake. Plaintiffs appealed the decision of the Court of Appeals to the Texas Supreme Court, and on October 21, 2016, the Texas Supreme Court denied Plaintiffs’ Petition for Review. Plaintiffs moved for rehearing on the denial, and CWEI’s and Chesapeake’s responses are due February 22, 2017.
CWEI has been named a defendant in three lawsuits filed in Louisiana, one by Southeast Louisiana Flood Protection Authority-East (“SELFPA”) and two by Plaquemines Parish, each alleging that historical industry operations have significantly damaged coastal marshlands.
In July 2013, the SELFPA case was filed in Orleans Parish and alleged that dredging and other oilfield operations of the 95 oil and gas company defendants caused degradation and destruction of the coastal marshlands which serve as a buffer protecting the coastal area of Louisiana from storms. The case was removed to Federal District Court. Legislation was enacted in Louisiana in 2014 in response to the suit which would effectively eliminate the claims, but in late 2014 the Louisiana state court judge declared the new law unconstitutional. A motion to dismiss the claims was granted in Federal District Court and the plaintiff has appealed to the United States Fifth Circuit Court of Appeals. Oral argument was heard on February 29, 2016. The Court has not yet ruled.
In November 2013, we were served with two separate suits filed by Plaquemines Parish in the 25th Judicial District Court of Plaquemines Parish, Louisiana (Designated Case Nos. 61-002 and 60-982). Multiple defendants are named in each suit, and each suit involves a different area of operation within Plaquemines Parish. Except as to the named defendants and areas of operation, the suits are identical. Plaintiff alleges that defendants’ oil and gas operations violated certain laws relating to the coastal zone management including failure to obtain permits, violation of permits, use of unlined waste pits, discharge of oil field wastes, including naturally occurring radioactive material, and that dredging operations exceeded unspecified permit limitations. Plaintiff makes no specific allegations against any individual defendant and seeks unspecified monetary damages and declaratory relief, as well as restoration, costs of remediation and attorney fees. The cases were removed to the U.S. District Court for the Eastern District of Louisiana but were remanded back to the state court in 2015. In November 2015, the Plaquemines Parish Council passed Resolution 15-389 requiring its attorneys to cease all work on the cases other than to dismiss all actions and lawsuits, but in April of 2016 the Parish voted to rescind such resolution. The State of Louisiana Department of Natural Resources, Office of Coastal Management has intervened in these cases and the Louisiana Attorney General has filed to supersede the Parish as Plaintiff. Status conferences were held in November 2016.
Our overall exposure to these suits is not currently determinable and we intend to vigorously defend these cases. We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these lawsuits to have a material adverse effect on our consolidated financial condition or results of operations.
Item 4
Item 4 - Mine Safety Disclosures
Not applicable.
PART II
Item 5
Item 5 - Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Price Range of Common Stock
Our common stock is quoted on the New York Stock Exchange (the “NYSE”) under the symbol “CWEI BC.” As of February 23, 2017, there were approximately 3,036 beneficial shareholders as reflected in security position listings. The following table sets forth, for the periods indicated, the high and low sales prices for our common stock, as reported on the NYSE as applicable:
The closing price of our common stock at February 23, 2017 was $138.36 per share.
Dividend Policy
We have never paid any cash dividends on our common stock, and our Board of Directors (the “Board”) does not currently anticipate paying any cash dividends to our shareholders in the foreseeable future. In addition, the terms of the revolving credit facility, the term loan credit facility and the indenture governing the $495.5 million (net of $4.5 million of original issue discount and debt issuance costs) in outstanding principal amount of 7.75% Senior Notes due 2019 (the “2019 Senior Notes”) (the “Indenture”) restrict the payment of cash dividends.
Unregistered Sales of Equity Securities
On July 22, 2016, we entered into an agreement to sell 5,051,100 shares of common stock to funds managed by Ares Management, LLC (“Ares”) for cash proceeds of $150 million, or approximately $29.70 per share, which transaction closed on August 29, 2016. In March 2016, in connection with the term loan credit facility with funds managed by Ares providing for the lenders to make secured term loans to us in the principal amount of $350 million (the “Refinancing”), we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share to Ares. In connection with the issuance of the warrants, we designated and issued to the initial warrant holders 3,500 shares of special voting preferred stock, $0.10 par value per share.
Item 6
Item 6 - Selected Financial Data
The following table sets forth selected consolidated financial data for CWEI as of the dates and for the periods indicated. The consolidated financial data for each of the years in the five-year period ended December 31, 2016 were derived from our audited consolidated financial statements. The data set forth in this table should be read in conjunction with “Item 7
Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with the accompanying consolidated financial statements, including the notes thereto.
Overview
We have been committed to drilling primarily developmental oil wells in two primary oil-prone regions, Southern Reeves County, Texas in the Delaware Basin, where we have a significant inventory of developmental drilling opportunities, and the Giddings Area. In 2016, we spent approximately $76.2 million in the Wolfbone area in Southern Reeves County, Texas on drilling, completion and leasing activities, and spent approximately $10.2 million on Austin Chalk/Eagle Ford Shale drilling and leasing activities.
Giddings Sale
In October 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing adjustments. We closed the sale on December 19, 2016.
Proposed Merger with Noble Energy
On January 13, 2017, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Noble Energy, Inc. (“Noble Energy”), Wild West Merger Sub, Inc., a Delaware corporation and indirect wholly owned subsidiary of Noble Energy (“Merger Sub”), and NBL Permian LLC, a Delaware limited liability company and indirect wholly owned subsidiary of Noble Energy (“Merger Sub II”), pursuant to which Noble Energy will acquire the Company in exchange for a combination of shares of common stock, par value $0.01 per share, of Noble Energy (“Noble Energy Common Shares”) and cash. Under the terms of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each share of the Company’s common stock issued and outstanding immediately prior to the Effective Time (other than common stock held in treasury and common stock held by shareholders who properly comply in all respects with the provisions of Section 262 of the General Corporation Law of the State of Delaware (“DGCL”) as to appraisal rights) and each unexercised warrant to purchase or otherwise acquire shares of common stock of the Company (each, a “CWEI Warrant”) issued and outstanding as of the Effective Time will be cancelled and extinguished and automatically converted into the right to receive, at the election of the shareholder or warrant holder, as applicable, and subject to proration as described below, one of the following forms of consideration (the “Merger Consideration”):
•
for each share of common stock, one of (i) 3.7222 Noble Energy Common Shares (the “Share Consideration”); (ii) (A) $34.75 in cash (subject to applicable withholding tax), without interest, and (B) 2.7874 Noble Energy Common Shares (the “Mixed Consideration”); or (iii) $138.39 in cash (subject to applicable withholding tax), without interest (the “Cash Consideration”); and
•
for each CWEI Warrant, either (i) the Share Consideration in respect of the number of shares of common stock of the Company that would be issued upon a cashless exercise of such CWEI Warrant immediately prior to the Effective Time (“Warrant Notional Common Shares”); (ii) the Mixed Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant; or (iii) the Cash Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant.
The Merger Agreement contains certain termination rights for both Noble Energy and the Company, including if the Merger is not consummated by July 17, 2017, and further provides that, upon termination of the Merger Agreement under certain circumstances, the Company may be required to pay Noble Energy a termination fee equal to $87 million. The closing of the Merger is expected to occur in the second quarter of 2017. See “Item 1 - Business - Company Profile - Recent Developments” for more information on the Merger.
Key Factors to Consider
The following summarizes the key factors considered by management in the review of our financial condition and operating performance for 2016.
•
Oil and gas sales, excluding amortized deferred revenues, decreased $54.1 million, or 25%, to $158.8 million in 2016 from $212.9 million in 2015. Production variances accounted for a decrease of $30.7 million and price variances accounted for a decrease of $23.4 million. Average realized oil prices were $38.58 per barrel in 2016 versus $44.76 per barrel in 2015, average realized gas prices were $2.31 per Mcf in 2016 versus $2.52 per Mcf in 2015 and average realized NGL prices were $13.26 per barrel in 2016 versus $13.07 per barrel in 2015. Amortized deferred revenue in 2016 totaled $1.5 million as compared to $4.5 million in 2015.
•
Oil, gas and NGL production per BOE/d decreased 14% in 2016, to 13,652 BOE/d, as compared to 15,818 BOE/d in 2015, with oil production decreasing 15% to 9,899 barrels per day, gas production decreasing 16% to 13,369 Mcf per day and NGL production increasing 1% to 1,525 barrels per day. Oil and NGL production accounted for approximately 84% of our total BOE production in 2016 compared to 83% in 2015. After giving effect to the sale of substantially all of our assets in the Giddings Area in East Central Texas in December 2016, the sale of our interests in certain wells in Glasscock County, Texas in July 2016 and the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production per BOE/d increased 1% in 2016 as compared to 2015.
•
Production costs decreased 19% from $87.6 million in 2015 to $70.9 million in 2016 due to lower oilfield service costs and decreased activity. After giving effect to a 14% decrease in total production, production costs on a BOE basis, excluding production taxes, averaged $12.68 per BOE in 2016 versus $13.23 per BOE in 2015.
•
Interest expense for 2016 was $93.7 million versus $54.4 million for 2015. The increase was due primarily to $44.3 million of incremental interest expense on funded indebtedness under our second lien term loan credit facility issued in connection with the Refinancing in March 2016. We elected to pay interest on the term loan facility in-kind for the quarterly periods ended June 30, 2016 and September 30, 2016 and resulted in an increase in the principal amount of the term loan to $377.2 million.
•
We account for the warrants issued in connection with the Refinancing as derivative instruments and carry the warrants as a non-current liability at their fair value. We recorded a $230 million loss on change in fair value in 2016 due primarily to the impact on the valuation model of a 730% increase in the market price of our common stock from $14.37 at March 15, 2016 to $119.26 at December 31, 2016.
•
We recorded a $20.3 million loss on commodity derivatives in 2016 (including a $7.4 million loss on settled contracts). For 2015, we recorded a $12.5 million gain on commodity derivatives (including a $12.5 million gain on settled contracts). Since we do not presently designate our commodity derivatives as cash flow hedges under applicable accounting standards, we recognize the full effect of changing prices on mark-to-market valuations as a current charge or credit to our results of operations.
•
Lower commodity prices also negatively impacted our results of operations due to asset impairments. During 2016, we recorded a provision for impairment of property and equipment of $7.6 million, of which $5.2 million related primarily to the impairment of certain proved non-core properties located in North Dakota, Oklahoma, California and the Cotton Valley area of Texas and $2.4 million related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values. By comparison, we recorded a provision for impairment of property and equipment in 2015 of $41.9 million, of which $37.9 million related to the impairment of certain proved non-core properties in the Permian Basin and Oklahoma and $4 million related to the impairment of certain drilling rigs and related equipment to reduce the carrying value of these properties to their estimated fair values.
•
We recorded a net gain of $118.8 million on sales of assets and impairment of inventory in 2016 compared to a net loss of $3 million in 2015. The 2016 gain related primarily to the sale of substantially all of our assets in the Giddings Area in
East Central Texas for $400 million, prior to closing adjustments, in December 2016 and the sale of our interests in certain wells in Glasscock County, Texas in July 2016. The 2015 loss related primarily to the write-down of inventory to reduce the carrying value to the estimated fair value offset by gains on the sale of selected leases and wells in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015, and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015.
•
We recorded an $8.4 million charge to fully impair the carrying value of our investment in Dalea Investment Group, LLC (“Dalea”) in 2016, as compared to a partial impairment of this investment of $2.6 million for 2015.
•
General and administrative (“G&A”) expenses for 2016 were $23 million compared to $22.8 million in 2015. G&A expense increased due primarily to increases in salary and personnel expense. Changes in compensation expense attributable to our APO Reward Plans (as defined in “Part III - Determining Compensation Levels - APO Plans”) accounted for a decrease of $7.9 million ($7.9 million credit in 2016 versus a negligible credit in 2015) which was due primarily to reductions in previously accrued compensation associated with the APO Reward Plans affected by the Giddings sale. Compensation expense related to issuances of restricted stock and stock options under the LTIP accounted for a $5.7 million increase.
•
We redeemed $100 million of 2019 Senior Notes in a tender offer in August 2016 and recorded a gain on early extinguishment of long-term debt during 2016 of $4 million.
•
Our estimated proved oil and gas reserves at December 31, 2016, decreased 25% to 34,754 MBOE from 46,569 MBOE at December 31, 2015. We replaced 82% of our oil and gas production in 2016 through extensions and discoveries of 4,077 MBOE, had net downward revisions of 168 MBOE and sales of minerals-in-place of 10,728 MBOE.
Oil and Gas Reserves
Total Proved Reserves
The following table summarizes changes in our estimated proved reserves during 2016.
Extensions and discoveries. Extensions and discoveries in 2016 added 4,077 MBOE of proved reserves, replacing 82% of our 2016 production. These additions resulted primarily from our Delaware Basin program in Southern Reeves County, Texas. Of the total reserve additions, proved developed reserves accounted for 2,660 MBOE, while the remaining 1,417 MBOE were proved undeveloped reserves.
Revisions. The 168 MBOE net downward revisions in proved reserves resulted from a combination of (1) net upward revisions of 11,670 MBOE related primarily to performance in our Delaware Basin program in Southern Reeves County, Texas and (2) downward revisions of 11,838 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves.
Sales of minerals-in-place. We sold substantially all of our assets in the Giddings Area in East Central Texas in December 2016, our interests in certain wells in Glasscock County, Texas in July 2016 and our interests in certain wells in Oklahoma in June 2016 resulting in a decrease of 10,728 MBOE.
Proved Undeveloped Reserves
Summary of changes in proved undeveloped reserves
The following table summarizes changes in our estimated proved undeveloped reserves during 2016.
We added 1,417 MBOE of proved undeveloped reserves from extensions and discoveries related to Delaware Basin drilling locations. Net upward revisions of 1,070 MBOE resulted primarily from the combination of (1) net upward revisions of 10,969 MBOE related to performance in our Delaware Basin program in Southern Reeves County, Texas and (2) downward revisions of 9,899 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves. We did not convert any proved undeveloped reserves to proved developed reserves in 2016.
Supplemental Information
The following unaudited information is intended to supplement the consolidated financial statements included in this Form 10-K with data that is not readily available from those statements.
(a)
Natural gas reserves have been converted to oil equivalents at the ratio of six Mcf of gas to one Bbl of oil.
(b)
Oil and gas sales includes $1.5 million for the year ended December 31, 2016, $4.5 million for the year ended December 31, 2015 and $7.7 million for the year ended December 31, 2014 of amortized deferred revenue attributable to the volumetric production payment (“VPP”) transaction effective March 1, 2012. In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. The calculation of average realized sales prices excludes production of 53,026 barrels of oil and 35,735 Mcf of gas for the year ended December 31, 2015 and 102,011 barrels of oil and 45,392 Mcf of gas for the year ended December 31, 2014 associated with the VPP.
(c)
No commodity derivatives were designated as cash flow hedges in the table above. All gains or losses on settled commodity derivatives were included in other income (expense) - gain (loss) on commodity derivatives.
(d)
Historical average daily production volumes have been reclassified to conform with current period presentation.
(e)
The average daily production related to interests in certain wells in Glasscock County, Texas sold in July 2016 was 49 total BOE/d for the year ended December 31, 2016, 104 total BOE/d for the year ended December 31, 2015 and 20 total BOE/d for the year ended December 31, 2014.
(f)
The average daily production related to assets in the Giddings Area in East Central Texas sold in December 2016 was 4,145 total BOE/d for the year ended December 31, 2016, 5,977 total BOE/d for the year ended December 31, 2015 and 5,176 total BOE/d for the year ended December 31, 2014.
(g)
The average daily production related to selected leases and wells in South Louisiana sold in September 2015 was 390 total BOE/d for the year ended December 31, 2015 and 535 total BOE/d for the year ended December 31, 2014.
(h)
Excludes wells being drilled or completed at the end of each period.
Operating Results
2016 Compared to 2015
The following discussion compares our results for the year ended December 31, 2016 to the year ended December 31, 2015. Unless otherwise indicated, references to 2016 and 2015 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales, excluding amortized deferred revenues, decreased $54.1 million, or 25%, to $158.8 million in 2016 from $212.9 million in 2015. Production variances accounted for $30.7 million of the decrease and price variances accounted for $23.4 million of the decrease. Oil and gas sales in 2016 also includes $1.5 million of amortized deferred revenue compared to $4.5 million in 2015 attributable to the VPP. Oil, gas and NGL production per BOE/d decreased 14% in 2016, to 13,652 BOE/d as compared to 15,818 BOE/d in 2015. Oil production decreased 15%, gas production decreased 16% and NGL production increased 1% in 2016 from 2015. After giving effect to the sale of substantially all of our assets in the Giddings Area in East Central Texas in December 2016, the sale of interests in certain wells in Glasscock County, Texas in July 2016 and the sale of selected leases and wells in South Louisiana in September 2015, oil, gas and NGL production per BOE/d in 2016 increased 1% compared to 2015. Oil and NGL production accounted for approximately 84% of our total BOE production in 2016 compared to 83% in 2015. In 2016, our realized oil price declined 14% compared to 2015, and our realized gas price decreased 8%. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.
Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 19% to $70.9 million in 2016 as compared to $87.6 million in 2015 due to lower oilfield service costs and decreased activity. After giving effect to a 14% decrease in total production, production costs excluding production taxes, averaged $12.68 per BOE in 2016 compared to $13.23 per BOE in 2015.
Oil and gas depletion expense decreased $16.4 million from 2015 to 2016 due to a $19.8 million decrease related to production variances and a $3.4 million increase related to rate variances. On a BOE basis, depletion expense increased 3% to $26.21 per BOE in 2016 from $25.54 per BOE in 2015. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.
We recorded a provision for impairment of property and equipment of $7.6 million during 2016, as compared to $41.9 million in 2015. The 2016 impairment included a charge of $5.2 million related primarily to proved non-core properties located in North Dakota, Oklahoma, California and the Cotton Valley area of Texas and a charge of $2.4 million related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values. The 2015 impairment included a charge of $37.9 million related primarily to proved non-core properties located in the Permian Basin and Oklahoma and a charge of $4 million related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value. If prices decline from current levels, we may incur future impairments. Although it is difficult to provide an estimate because of the numerous variables and management input decisions required to evaluate the amount of any asset impairments, they could be significant.
Exploration costs
We follow the successful efforts method of accounting; therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs and unproved acreage impairments are expensed. In 2016, we charged to expense $4.5 million of exploration costs, as compared to $7.8 million in 2015. The 2016 expense includes a charge of $1.8 million related to unproved leasehold impairments in East Texas and $0.9 million for the abandonment of exploratory wells in Oklahoma. By comparison, the 2015 expense includes a charge of $3.1 million for the abandonment of exploratory wells in South Louisiana and Oklahoma and $1.7 million related to unproved leasehold impairments in East Texas.
Contract drilling services
Drilling services revenues received by our wholly owned subsidiary, Desta Drilling, L.P. (“Desta Drilling”), along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss). Drilling rig services revenue related to external customers was negligible in 2016 and 2015 due to decreased demand for contract drilling services. Drilling services costs, net of eliminations, were $3.9 million
in 2016 compared to $5.2 million in 2015. Contract drilling depreciation for 2016 was $12 million compared to $12.2 million in 2015. As discussed above, we recorded a charge of $2.4 million in 2016 compared to $4 million in 2015 related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values. Due to the downturn in oil prices, all our rigs have been idle since November 2015.
General and Administrative
G&A expenses increased $0.2 million from $22.8 million in 2015 to $23 million in 2016. G&A expense increased due primarily to increases in salary and personnel expense. Changes in compensation expense related to our APO Reward Plans accounted for a $7.9 million decrease ($7.9 million credit in 2016 versus a negligible credit in 2015) which was due primarily to reductions in previously accrued compensation associated with the APO Reward Plans affected by the Giddings sale. Compensation expense related to issuances of restricted stock and stock options under the LTIP accounted for a $5.7 million increase.
Interest expense
Interest expense increased 72% from $54.4 million in 2015 to $93.7 million in 2016 due primarily to $44.3 million of incremental interest expense on funded indebtedness incurred under a second lien term loan credit facility issued in connection with the Refinancing. We elected to pay interest on the term loan facility in-kind for the quarterly periods ended June 30, 2016 and September 30, 2016 which resulted in an increase in the principal amount of the term loan to $377.2 million.
Gain on early extinguishment of long-term debt
We redeemed $100 million in aggregate principal amount of 2019 Senior Notes in a tender offer in August 2016 and recorded a $4 million gain on early extinguishment of long-term debt consisting of a $5 million discount and a $1 million write-off of debt issuance costs in 2016.
Loss on change in fair value of common stock warrants
We account for the warrants issued in connection with the Refinancing as derivative instruments and carry the warrants as a non-current liability at their fair value. We recorded a $230 million loss on change in fair value in 2016 due primarily to the impact on the valuation model of a 730% increase in the market price of our common stock from $14.37 at March 15, 2016 to $119.26 at December 31, 2016.
Gain/loss on commodity derivatives
We did not designate any commodity derivative contracts in 2016 or 2015 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on commodity derivatives. In 2016, we reported a $20.3 million loss on commodity derivatives (including a $7.4 million loss on settled contracts). In 2015, we reported a $12.5 million gain on commodity derivatives (including a $12.5 million gain on settled contracts). Because oil and gas prices are volatile, and because we do not account for our commodity derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on commodity derivatives can cause significant volatility in our results of operations.
Impairment of investments and other
We recorded an $8.4 million charge to fully impair the carrying value of our investment in Dalea in 2016, as compared to a partial impairment of $2.6 million in 2015.
Gain/loss on sales of assets and impairment of inventory
We recorded a net gain of $118.8 million on sales of assets and impairment of inventory in 2016 compared to a net loss of $3 million in 2015. The 2016 gain related primarily to the sale of substantially all of our assets in the Giddings Area in East Central Texas for $400 million, prior to closing adjustments, in December 2016 and the sale of our interests in certain wells in Glasscock County, Texas in July 2016. The 2015 loss related primarily to the write-down of inventory to reduce the carrying value to the estimated fair value offset by gains on the sale of selected leases and wells in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015, and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015.
Income taxes
Our estimated federal and state effective income tax rate in 2016 of (9.4)% differed from the statutory federal rate of 35% due primarily to permanent differences related to revaluation of the warrants issued in connection with the Refinancing, increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.
2015 Compared to 2014
The following discussion compares our results for the year ended December 31, 2015 to the year ended December 31, 2014. Unless otherwise indicated, references to 2015 and 2014 within this section refer to the respective annual periods.
Oil and gas operating results
Oil and gas sales, excluding amortized deferred revenues, decreased $197.7 million, or 48%, in 2015 from 2014. Price variances accounted for a $200.7 million decrease and production variances accounted for an increase of $3 million. Oil and gas sales in 2015 also includes $4.5 million of amortized deferred revenue versus $7.7 million in 2014 attributable to the VPP. In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. Reported production and related average realized sales prices exclude volumes associated with the VPP through July 2015. Oil, gas and NGL production in 2015 (on a BOE basis) remained unchanged compared to 2014. Oil production increased 2% in 2015 from 2014 while NGL production decreased 6% and gas production decreased 2% in 2015 from 2014. After giving effect to the sale of our interests in selected leases and wells in South Louisiana in September 2015 and the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014, oil, gas and NGL production in 2015 (on a BOE basis) increased 2% compared to 2014. Oil production increased 3% in 2015 from 2014, while NGL production decreased 6% and gas production decreased less than 1% in 2015 from 2014. The liquids component of our production mix accounted for approximately 83% oil and NGL in 2014 and 2015. In 2015, our realized oil price declined 48% compared to 2014, and our realized gas price decreased 42%. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.
Production costs, consisting of lease operating expenses, production taxes and other miscellaneous marketing costs, decreased 17% to $87.6 million in 2015, as compared to $105.3 million in 2014, due to reductions in production taxes associated with lower oil and gas sales and reduced costs of field services. Production costs on a BOE basis, excluding production taxes, averaged $13.23 per BOE in 2015 compared to $14.57 per BOE in 2014.
Oil and gas depletion expense increased $4.9 million from 2014 to 2015 due to a $4.6 million increase related to rate variances and a $0.3 million increase due to production variances. On a BOE basis, depletion expense increased 3% to $25.54 per BOE in 2015 from $24.73 per BOE in 2014. Depletion expense per BOE of oil and gas production is an operating metric that is indicative of our weighted average cost to find or acquire a unit of equivalent production. We may realize higher oil and gas depletion rates in future periods if our exploration and development activities result in higher finding costs.
We recorded a provision for impairment of property and equipment of $41.9 million during 2015, as compared to $12 million in 2014. The 2015 impairment included a charge of $37.9 million related primarily to proved non-core properties located in the Permian Basin and Oklahoma and a charge of $4 million related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values. The 2014 impairment related to certain non-core properties located in the Permian Basin and North Dakota to reduce the carrying value of these properties to their estimated fair values. Impairment of a proved property group is recognized when the estimated undiscounted future net cash flows of the property group are less than its carrying value.
Exploration costs
We follow the successful efforts method of accounting; therefore, our results of operations are adversely affected during any accounting period in which significant seismic costs, exploratory dry hole costs and unproved acreage impairments are expensed. In 2015, we charged to expense $7.8 million of exploration costs, as compared to $23 million in 2014. The expense for 2015 includes a charge of $3.1 million for the abandonment of exploratory wells in South Louisiana and Oklahoma and $1.7 million related to unproved leasehold impairments in East Texas. By comparison, the expense for 2014 includes a charge of $11.3 million related to unproved leasehold impairments in California and Oklahoma and $4.4 million for the abandonment of exploratory wells in South Louisiana and Oklahoma.
Contract drilling services
We primarily utilize drilling rigs owned by our wholly owned subsidiary, Desta Drilling, to drill wells in our exploration and development activities. Drilling services revenues received by Desta Drilling, along with the related drilling services costs pertaining to the net interest owned by CWEI, have been eliminated in our consolidated statements of operations and comprehensive income (loss). Drilling rig services revenue related to external customers was negligible in 2015 compared to $28 million in 2014 due to decreased demand for contract drilling services. Drilling services costs, net of eliminations, were $5.2 million in 2015 compared to $19.2 million in 2014. Contract drilling depreciation for 2015 was $12.2 million compared to $9.2 million in 2014. As discussed above, in 2015, we recorded an impairment of property and equipment of $4 million compared to none in 2014 related to the impairment of certain drilling rigs and related equipment to reduce the carrying value to their estimated fair values.
General and Administrative
G&A expenses decreased $11.7 million from $34.5 million in 2014 to $22.8 million in 2015. Changes in compensation expense attributable to our APO Reward Plans accounted for a net decrease of $4.6 million. The remaining decrease in expense in 2015 was largely attributable to salary and personnel reductions.
Interest expense
Interest expense increased 7% from $50.9 million in 2014 to $54.4 million in 2015 due primarily to an increase in borrowings under the revolving credit facility, which increased from an average daily principal balance of $41 million in 2014 to $159.4 million in 2015.
Gain/loss on commodity derivatives
We did not designate any commodity derivative contracts in 2015 or 2014 as cash flow hedges; therefore, all cash settlements and changes resulting from mark-to-market valuations have been recorded as gain/loss on commodity derivatives. In 2015, we reported a $12.5 million gain on commodity derivatives (including a $12.5 million gain on settled contracts). In 2014, we reported a $4.8 million gain on commodity derivatives (including a $7.1 million gain on settled contracts). Because oil and gas prices are volatile, and because we do not account for our commodity derivatives as cash flow hedges, the effect of mark-to-market valuations on our gain/loss on commodity derivatives can cause significant volatility in our results of operations.
Gain/loss on sales of assets and impairment of inventory
We recorded a net loss of $3 million on sales of assets and impairment of inventory in 2015 compared to a net gain of $9.1 million in 2014. The 2015 loss related primarily to the write-down of inventory to reduce the carrying value to the estimated fair value offset by gains on the sale of selected leases and wells in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015, and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015. The 2014 gain related primarily to the sale of the certain non-core Austin Chalk/Eagle Ford assets sold in March 2014 and the sale of a property in Ward County, Texas in February 2014. Gains on sales of assets are included in other operating revenues and loss on sales of assets and impairment of inventory are included in other operating expenses in our consolidated statements of operations and comprehensive income (loss).
Income taxes
Our estimated federal and state effective income tax rate in 2015 of 36% differed from the statutory federal rate of 35% due primarily to increases related to the effects of the Texas Margin Tax and certain non-deductible expenses, offset in part by tax benefits derived from excess statutory depletion deductions.
Liquidity and Capital Resources
Our primary financial resource is our base of oil and gas reserves. We pledge substantially all of our producing oil and gas properties to secure our obligations under the revolving credit facility and the term loan credit facility (see “- Revolving credit facility” and “- Term loan credit facility”). The banks under the revolving credit facility establish a borrowing base, in part, by making an estimate of the collateral value of our oil and gas properties. We believe the term loans have provided us with a source of dedicated liquidity; however, we intend to use cash on hand and borrow funds under the revolving credit facility as needed in the future to supplement our operating cash flow as a financing source for our capital expenditure program. Our ability to fund our capital expenditure program is dependent upon the level of product prices and the success of our development program in
replacing our existing oil and gas reserves and production. If product prices decrease, our operating cash flow may decrease and the banks under the revolving credit facility may require additional collateral or reduce our borrowing base, thus reducing funds available to fund our capital expenditure program. However, we may mitigate the effects of product prices on our cash flow and borrowing base through the use of commodity derivatives.
Our cash on hand at December 31, 2016 was $573 million. At December 31, 2016, we had $98.1 million available on the revolving credit facility after allowing for outstanding letters of credit totaling $1.9 million, as compared to $298.1 million of availability on the facility at December 31, 2015. Our indebtedness at December 31, 2016 was $848 million, consisting of $352.5 million including paid in-kind interest, net of original issue discount and debt issuance costs, under the second lien term loan credit facility and $495.5 million in outstanding principal amount of the 2019 Senior Notes, net of original issue discount and debt issuance costs.
Recent Events and Outlook for 2017
On January 13, 2017, we entered into the Merger Agreement with Noble Energy, Merger Sub and Merger Sub II, pursuant to which Noble Energy will acquire the Company in exchange for a combination of Noble Energy common shares and cash. The closing of the Merger is expected to occur in the second quarter of 2017. See “Item 1 - Business - Company Profile - Recent Developments” for more information on the Merger.
In October 2016, we entered into a definitive purchase and sale agreement with a third party to sell substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing adjustments. We closed the sale on December 19, 2016.
Capital expenditures
The following table summarizes, by area, our planned expenditures for exploration and development activities during 2017, as compared to our actual expenditures in 2016.
Our expenditures for exploration and development activities for the year ended December 31, 2016 totaled $91.3 million. We financed these expenditures in 2016 with cash flow from operating activities, a combination of proceeds from the Refinancing and our July 22, 2016 agreement to sell 5,051,100 shares of common stock to funds managed by Ares for cash proceeds of $150 million, or approximately $29.70 per share (the “Private Placement”) and proceeds from asset sales. We currently plan to spend approximately $164.8 million on exploration and development activities during fiscal 2017. Our actual expenditures during 2017 may vary significantly from these estimates since our plans for exploration and development activities may change during the year. Factors, such as changes in commodity prices, operating margins, the availability of capital resources, drilling results and other factors, could increase or decrease our actual expenditures during fiscal 2017.
Based on preliminary estimates, our internal cash flow forecasts indicate that our anticipated operating cash flows and cash on hand will be sufficient to finance our planned exploration and development activities in 2017. Although we believe the assumptions and estimates made in our forecasts are reasonable, these forecasts are inherently uncertain and cash flows may be less than expected, or capital expenditures may be more than expected. We will consider options for obtaining alternative capital
resources, including selling assets or accessing capital markets if necessary when we deem appropriate. Further significant and prolonged declines in prices could impact our ability to service our debt obligations and will further constrain our ability to use cash flows to drill to replace or increase our production and reserves.
Cash flow provided by operating activities
Substantially all of our cash flows from operating activities are derived from the production of our oil and gas reserves. We use these cash flows to fund our ongoing exploration and development activities in search of new oil and gas reserves. Variations in cash flows from operating activities may impact our level of exploration and development expenditures.
Cash flows provided by operating activities for the year ended December 31, 2016 decreased $41.4 million, or 79.4%, as compared to the corresponding period in 2015 due primarily to lower commodity prices and decreased production.
Revolving credit facility
We have a revolving credit facility with a syndicate of 16 banks led by JP Morgan Chase Bank, N.A. On March 8, 2016, we entered into an amendment to the revolving credit facility in connection with the Refinancing (see “- Term loan credit facility”). The amendment, among other things, reduced the borrowing base and the aggregate commitments of the lenders from $450 million to $100 million. The aggregate commitments may be increased to $150 million if we meet a minimum ratio of the discounted present value of our proved developed producing reserves to our debt under the revolving credit facility of 1.2 to 1.0. Increases in aggregate lender commitments require the consent of each lender.
The amendment also increased the applicable interest rates under our revolving credit facility by 0.75% at every borrowing base utilization level. At our election, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2.5% and 3.5% per year or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.5% and 2.5% per year. We are also required to pay a commitment fee on the unused portion of the commitments under the revolving credit facility of 0.5% per year. The applicable margin is determined based on the utilization of the borrowing base. Interest and fees are payable quarterly, except that interest on LIBOR-based tranches is due at maturity of each tranche but no less frequently than quarterly.
The revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1. The March 2016 amendment replaced a requirement that we maintain certain ratios of consolidated funded indebtedness to consolidated EBITDAX with a less restrictive ratio of debt outstanding solely under the revolving credit facility to consolidated EBITDAX to be less than 2.0 to 1.0.
The revolving credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 2019 Senior Notes are refinanced or extended in accordance with the terms of the revolving credit facility prior to October 1, 2018.
The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of options (1) through (3).
The revolving credit facility is collateralized by a first lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the revolving credit facility) attributed to our proved oil and gas interests evaluated in determining the borrowing base. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries.
At December 31, 2016, we had $98.1 million available under the revolving credit facility after allowing for outstanding letters of credit totaling $1.9 million. The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2016 was 2.5%. We were in compliance with all financial and non-financial covenants at December 31, 2016 and December 31, 2015. Under current commodities pricing, we expect that we will be in compliance with all financial covenants through 2017. Further deterioration in commodities pricing,
however, could result in non-compliance and cause us to seek to negotiate revisions to our loan covenants, which relief may not be obtainable from our bank lenders.
The failure to comply with the foregoing covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the revolving credit facility. Other events of default under the revolving credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding.
Working capital computed for loan compliance purposes differs from our working capital computed in accordance with generally accepted accounting principles (“GAAP”). Since compliance with financial covenants is a material requirement under the revolving credit facility, we consider the loan compliance working capital to be useful as a measure of our liquidity because it includes the funds available to us under the revolving credit facility and is not affected by the volatility in working capital caused by changes in fair value of commodity derivatives. Our GAAP reported working capital was $524.4 million at December 31, 2016 from working capital of $3.1 million at December 31, 2015. After giving effect to the adjustments, our working capital computed for loan compliance purposes was $635.4 million at December 31, 2016, as compared to $301.2 million at December 31, 2015.
The following table reconciles our GAAP working capital to the working capital computed for loan compliance purposes at December 31, 2016 and December 31, 2015.
As a condition to borrowing funds or issuing letters of credit under our revolving credit facility, we must remain in compliance with the financial and non-financial covenants, including financial ratios, in our revolving credit facility, as amended to date. We also must make certain representations and warranties to our bank lenders at the time of each borrowing. We were in compliance with all financial and non-financial covenants at December 31, 2016 and December 31, 2015. However, if we increase leverage and our liquidity is reduced, we may fail to comply with one or more of these covenants in the future. If we fail to meet any of these loan covenants, we would ask the banks to waive compliance, amend the revolving credit facility to allow us to become compliant or grant us sufficient time to obtain additional capital resources through alternative means. Although we believe our bank lenders are well secured under the terms of our revolving credit facility, there is no assurance that the bank lenders will waive or amend our covenants or other conditions to further lending. If a suitable arrangement could not be reached with the banks, the banks could accelerate the indebtedness and seek to foreclose on the pledged assets.
The lending group under the revolving credit facility includes the following institutions: JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., MUFG Union Bank, N.A., Compass Bank, Frost Bank, Toronto Dominion (Texas) LLC, KeyBank National Association, Natixis, New York Branch, UBS AG, Stamford Branch, Fifth Third Bank, U.S. Bank National Association, Whitney Bank, Bank of America, N.A., Branch Banking and Trust Company, Capital One, National Association and PNC Bank, National Association.
From time to time, we engage in other transactions with lenders under the revolving credit facility. Such lenders or their affiliates may serve as counterparties to our commodity and interest rate derivative agreements. As of December 31, 2016, JPMorgan Chase Bank, N.A. and Shell Trading Risk Management LLC were the counterparties to our commodity derivative agreements. Our obligations under commodity derivative agreements with our lenders are secured by the security documents executed by the parties under the revolving credit facility.
Term loan credit facility
On March 8, 2016, we entered into (1) a credit agreement with Ares providing for the issuance of second lien term loans and common stock warrants and (2) an amendment to the revolving credit facility with our banks. Upon closing of the Refinancing on March 15, 2016, we issued term loans to Ares in the principal amount of $350 million, net of original issue discount of $16.8 million, for cash proceeds of $333.2 million. Concurrently, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share to Ares for cash proceeds equal to the original issue discount from the issuance on the term loans. The warrants represent the right to acquire approximately 12.8% of our currently outstanding shares of common stock, or approximately 11.2% of our common shares on a fully exercised basis. In connection with the issuance of the warrants, we designated and issued to the initial warrant holders 3,500 shares of special voting preferred stock, $0.10 par value per share, granting them certain rights to elect two members of our Board. Aggregate cash proceeds from the transaction of approximately $340 million, net of transaction costs, were used to fully repay the then-outstanding indebtedness under the revolving credit facility of $160 million, plus accrued interest and fees.
Interest on the term loans is payable quarterly in cash at 12.5% per year; however, during the period from March 15, 2016 through March 31, 2018, we may elect to pay interest for any quarter in-kind at 15% per year. We paid interest for the period commencing from March 15, 2016 and ending March 31, 2016 in cash, and elected to pay interest for the quarters ended June 30, 2016 and September 30, 2016 in-kind. We paid interest for the quarterly period ending December 31, 2016 in cash. In February 2017, we elected to pay interest for the quarterly period ending March 31, 2017 in cash. Future quarterly elections to pay in-kind must be made 30 days prior to the beginning of each calendar quarter.
The term loan credit facility matures on March 15, 2021, but is subject to an earlier maturity on December 31, 2018, if we do not extend or refinance our existing 2019 Senior Notes on or prior to that date.
The term loan credit facility is collateralized by a second lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the term loan credit facility) attributed to our proved oil and gas interests. The obligations under the term loan credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries. Optional and mandatory prepayments made prior to September 15, 2020 are subject to make-whole or prepayment premiums.
The term loan credit facility also contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain an asset-to-secured debt coverage ratio as of each December 31 and June 30 of each year, beginning with December 31, 2018, of at least 1.2 to 1.0. We were in compliance with these covenants at December 31, 2016. Under current commodities pricing, we expect that we will be in compliance with all financial covenants through 2017. Further deterioration in commodities pricing, however, could result in non-compliance and cause us to seek to negotiate revisions to our loan covenants, which relief may not be obtainable from our bank lenders. Upon closing of the Private Placement, we entered into an amendment to the term loan facility, waiving certain restrictions to enable us to use proceeds from equity issuances and specified asset sales for debt reduction and capital expenditures.
The failure to comply with these covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the term loan credit facility. Other events of default under the term loan credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding.
Senior Notes
In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes. The 2019 Senior Notes, which are unsecured, were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year. In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million. In October 2013, we issued an additional $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. All of the 2019 Senior Notes are treated as a single class of debt securities under the same indenture. In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the year ended December 31, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million discount and a $1 million write-off of debt issuance costs. We may redeem some or all of the remaining 2019 Senior Notes at a redemption price (expressed as percentages of principal amount) equal to 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant generally restricts our ability to incur indebtedness if our ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) is less than 2.25 times. However, this restriction does not prevent us from incurring indebtedness under a credit facility (as defined in the Indenture) in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $500 million and (b) 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). These covenants are subject to a number of additional important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at December 31, 2016 and December 31, 2015.
Asset Sales
From time to time, we sell certain of our proved and unproved properties when we believe it is more advantageous to dispose of the selected properties than to continue to hold them. During the year ended December 31, 2016, we received cash proceeds aggregating $423.9 million from various sales of assets, including the sale of substantially all of our assets in the Giddings Area in East Central Texas for a sale price of $400 million, subject to customary closing adjustments, which sale closed on December 19, 2016. We may consider other selected sales as a source of additional funds to supplement cash flow from operations and borrowings under the credit facility to meet our capital needs.
Alternative capital resources
We believe we currently have adequate liquidity to enable us to fund our expected capital expenditures for 2017 through a combination of cash on hand and cash flow from operations.
Subject to any restrictions in the revolving credit facility and the term loan credit facility, we may also use other capital resources, including (1) entering into joint venture participation agreements with other industry or financial partners in our core development areas, (2) monetizing all or a portion of our core or non-core assets and (3) issuing additional debt or equity securities in private or public offerings, in order to finance a portion of our capital spending in fiscal 2017 and subsequent periods. While we believe we would be able to obtain funds through one or more of these alternative capital resources, if needed, there can be no assurance that these capital resources would be available on terms acceptable to us.
Contractual obligations and contingent commitments
The following table summarizes our contractual obligations as of December 31, 2016 by payment due date.
(a)
In addition to the principal payments presented, we expect to make annual interest payments of $39.1 million on the 2019 Senior Notes and $44.5 million on the Second Lien Term Loan.
Off-balance sheet arrangements
Currently, we do not have any material off-balance sheet arrangements.
Known Trends and Uncertainties
Operating Margins
We analyze, on a BOE produced basis, those revenues and expenses that have a significant impact on our oil and gas operating margins. Our weighted average oil and gas sales per BOE have declined from $72.59 per BOE in 2014, to $37.67 per BOE in 2015 and $32.09 per BOE in 2016. Our oil and gas depletion per BOE increased from $24.73 per BOE in 2014, to $25.54 per BOE in 2015 and $26.21 per BOE in 2016. Our production costs per BOE have decreased from $18.27 per BOE in 2014, to $15.17 per BOE in 2015 and $14.19 per BOE in 2016. The decrease in operating costs per BOE in 2016 from 2014 was due primarily to lower costs of field services, decreased production taxes resulting from lower commodity prices in 2016 and a reduction in production costs associated with the sale of non-core assets.
Oil and Gas Production
As with all companies engaged in oil and gas exploration and production, we face the challenge of natural production decline because oil and gas reserves are a depletable resource. With each unit of oil and gas we produce, we are depleting our proved reserve base, so we must be able to conduct successful exploration and development activities or acquire properties with proved reserves in order to grow our reserve base. Our production in 2016 decreased 14% to 5 MMBOE compared to 5.8 MMBOE in 2015, and we replaced 82% of our 2016 oil and gas production through extensions and discoveries. While these 2016 reserve additions will contribute favorably to our production in 2017, we do not expect this production to be sufficient to fully offset the natural production declines from our existing base of oil and gas reserves.
Impact of Downturn in Commodity Prices
Our business is subject to various trends and uncertainties, the most significant of which are related to commodity prices. The severe downturn in oil prices that began late in 2014 significantly reduced our cash flow from operations, causing us to suspend drilling operations in both of our core resource plays early in 2015 in order to preserve liquidity. Management quickly took decisive steps to reduce costs in an attempt to improve margins, but the combination of declining production attributable to suspended drilling activities and the impact of substantially lower oil and natural gas prices on cash flow will continue to have an adverse effect on our business if the downturn is prolonged. Further significant and prolonged declines in prices could impact our ability to service our debt obligations and will further constrain our ability to use cash flows to drill to replace or increase our production and reserves.
Low commodity prices also have an adverse impact on our oil and gas reserves. In our evaluation of year-end 2016 reserves, management took into account its outlook for future oil and natural gas prices and the availability of financial resources, including our cash on hand at December 31, 2016, to assess the future development plan for our proved undeveloped reserves as of December 31, 2016. Based on our current long-term outlook for commodity prices and our reasonable expectations for access to adequate financing required to fund future drilling, we scheduled for 2018 through 2020 aggregate future capital spending for proved undeveloped locations of $139.9 million with associated reserves of 12,689 MBOE at year-end 2016. Substantially all of these proved undeveloped locations are located in our core Delaware Basin play in Southern Reeves County, Texas. An additional $0.7 million of estimated future capital spending and 88 MBOE of proved undeveloped reserves is attributable to our general partner interest in an affiliated partnership, which is proportionately consolidated in our financial statements. If commodity prices are not sufficient to support future drilling, future assessments could result in a reduction in development capital expenditures and write-downs of proved undeveloped reserves.
The prolonged effects of lower oil prices, declining production and lower proved reserves may have an adverse effect on our ability to access the capital resources we need to grow our reserve base. If we continue limited drilling activities for a significant period of time, or if our future access to capital resources is limited, we will also likely further delay the development of our proved undeveloped reserves or ultimately suspend such development, which could result in further reductions in undeveloped reserves.
Application of Critical Accounting Policies and Estimates
Summary
In this section, we will identify the critical accounting policies we follow in preparing our consolidated financial statements and disclosures. Many of these policies require us to make difficult, subjective and complex judgments in the course of making estimates of matters that are inherently imprecise. We explain the nature of these estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our consolidated financial statements under different conditions or using different assumptions.
The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies and the financial statement accounts affected by these estimates and assumptions.
Significant Estimates and Assumptions
Oil and gas reserves
Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of and the interpretation of that data and judgment based on experience and training. Annually, we engage independent petroleum engineering firms to evaluate our oil and gas reserves. As a part of this process, our internal reservoir engineer and the independent petroleum engineers exchange information and attempt to reconcile any material differences in estimates and assumptions.
The techniques used in estimating reserves usually depend on the nature and extent of available data, and the accuracy of the estimates may vary accordingly. As a general rule, the degree of accuracy of reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table.
Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the standardized measure of discounted future net cash flows is extremely sensitive to prices and costs, and may vary materially based on different assumptions. Current Securities and Exchange Commission (“SEC”) financial accounting and reporting standards require that pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report. Varying pricing can result in significant changes in reserves and standardized measure of discounted future net cash flows from period to period, as illustrated in the following table.
Valuation of unproved properties
Estimating fair market value of unproved properties (also known as prospects) is very subjective since there is no quoted market for undeveloped exploratory prospects. The negotiated price of any prospect between a willing seller and willing buyer depends on the specific facts regarding the prospect, including:
•
the location of the prospect in relation to known fields and reservoirs, available markets and transportation systems for oil and gas production in the vicinity and other critical services;
•
the nature and extent of geological and geophysical data on the prospect;
•
the terms of the leases holding the acreage in the prospect, such as ownership interests, expiration terms, royalty interests, delay rental obligations, depth limitations, drilling and marketing restrictions, continuous development obligations, and similar terms;
•
the prospect’s risk-adjusted potential for return on investment, giving effect to such factors as potential reserves to be discovered, drilling and completion costs, prevailing commodity prices and other economic factors; and
•
the results of drilling activity in close proximity to the prospect that could either enhance or condemn the prospect’s chances of success.
Asset Retirement Obligations
We estimate the present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable state laws. We compute our liability for asset retirement obligations
by calculating the present value of estimated future cash flows related to each property. This requires us to use significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligations.
Effects of Estimates and Assumptions on Financial Statements
GAAP does not require, or even permit, the restatement of previously issued financial statements due to changes in estimates unless such estimates were unreasonable or did not comply with applicable SEC accounting rules. We are required to use our best judgment in making estimates and assumptions, taking into consideration the best and most current data available to us at the time of the estimate. At each accounting period, we make a new estimate using new data, and continue the cycle. You should be aware that estimates prepared at various times may be substantially different due to new or additional data. While an estimate made at one point in time may differ from an estimate made at a later date, both may be proper due to the differences in available data or assumptions. In this section, we will discuss the effects of different estimates on our consolidated financial statements.
Provision for DD&A
We compute our provision for DD&A on a unit-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for each of our producing properties (or appropriate groups of properties based on geographical and geological similarities):
•
DD&A Rate = Unamortized Cost / Beginning of Period Reserves
•
Provision for DD&A = DD&A Rate x Current Period Production
Reserve estimates have a significant impact on the DD&A rate. If reserve estimates for a property or group of properties are revised downward in future periods, the DD&A rate for that property or group of properties will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease.
Impairment of Unproved Properties
Each quarter, we review our unproved oil and gas properties to determine if there has been, in our judgment, an impairment in value of each prospect that we consider individually significant. To the extent that the carrying cost of a prospect exceeds its estimated value, we make a provision for impairment of unproved properties and record the provision as abandonments and impairments within exploration costs on our consolidated statements of operations and comprehensive income (loss). If the value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the prospect at a net cost that is lower than its estimated value. If the value is revised downward in a future period, an additional provision for impairment is made in that period.
Impairment of Proved Properties and Long-Lived Assets
Each quarter, we assess our producing properties for impairment. If we determine there has been an impairment in any of our producing properties (or appropriate groups of properties based on geographical and geological similarities), we will estimate the value of each affected property. In accordance with GAAP, the value for this purpose is a fair value using Level 3 inputs (as defined below in the Notes to Consolidated Financial Statements) instead of a standardized reserve value as prescribed by the SEC. We attempt to value each property using reserve classifications and pricing parameters similar to what a willing seller and willing buyer might use. These parameters may include escalations of prices instead of constant pricing, and they may also include the risk-adjusted value of reserves. To the extent that the carrying cost for the affected property exceeds its estimated fair value, we make a provision for impairment of proved properties. If the fair value is revised upward in a future period, we do not reverse the prior provision, and we continue to carry the property at a net cost that is lower than its estimated fair value. If the fair value is revised downward in a future period, an additional provision for impairment is made in that period. Accordingly, the carrying costs of producing properties on our balance sheet will vary from (and often will be less than) the present value of proved reserves for these properties.
Judgment Regarding Status of In-Progress Wells
On a quarterly basis, we review the status of each in-progress well to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (often referred to as a dry hole) prior to the issuance
of our consolidated financial statements, we write-off all costs incurred through the balance sheet date to abandonments and impairments expense, a component of exploration costs. Costs incurred on that dry hole after the balance sheet date are charged to exploration costs in the period incurred.
Occasionally, we are unable to make a final determination about the productive status of a well prior to issuance of our consolidated financial statements. In these cases, we leave the well classified as in-progress until we have had sufficient time to conduct additional completion or testing operations and to evaluate the pertinent geological and geophysical and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the in-progress status and the proper accounting treatment is recorded.
Asset Retirement Obligations
Our asset retirement obligations are recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to oil and gas properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the consolidated statements of operations and comprehensive income (loss). During 2016, we had an upward revision of our estimated asset retirement obligations of $11.3 million based on a review of current plugging and abandonment costs. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to DD&A expense and accretion expense. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
Recent Accounting Pronouncements
In August 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. We are currently evaluating the method of adoption and impact this standard may have on our financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation.” ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Upon adoption, we expect to record a cumulative-effect adjustment to reclassify approximately $7.5 million of excess tax benefits that were not previously recognized because the related tax deduction had not reduced taxes payable. We plan to adopt ASU 2016-09 during the quarter ended March 31, 2017 to be effective as of January 1, 2017.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. We do not plan to early adopt the standard. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space and vehicles. We are currently in the process of reviewing all contracts that could be applicable to this new guidance. We believe this new guidance will have a moderate impact to our consolidated balance sheet due to the recognition of lease-related assets and liabilities that were not previously recognized.
In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes.” This ASU requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. Adoption of the new guidance will affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements.
In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively, with early adoption permitted. The adoption of this standard will not have a material impact on our consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net debt issuance costs directly related to our senior notes and our second lien term loan to be classified as a direct deduction from the carrying amount of the related senior notes and second lien term loan. We adopted this ASU as of March 31, 2016 and reclassified $7.3 million of debt issuance costs at December 31, 2015 from a non-current asset to a direct deduction in long-term debt. The debt issuance costs related to our revolving credit facility remains classified as a non-current asset due to the revolving nature of that facility.
In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Certain disclosures are required should substantial doubt exist. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year after the date that the financial statements are issued. This ASU was effective beginning December 31, 2016; however, no additional disclosures as contemplated by this ASU were warranted.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements and related disclosures. Based on our initial evaluation, though not currently quantified, the adoption of the standard is not expected to have a material impact on the timing of revenue recognized, results of operations or cash flows.
Item 7A
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
Our business is impacted by fluctuations in commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe our strategy for managing such risk and quantify the potential effect of market volatility on our financial condition and results of operations.
Oil and Gas Prices
Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market commodity prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, many of which are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas commodity prices with any degree of certainty. Sustained weakness in oil and gas commodity prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to commodity price fluctuations, can reduce the borrowing base under the revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas commodity prices can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2016 reserve estimates, we project that a $1 decline in the price per barrel of oil and a $0.50 decline in the price per Mcf of gas from year-end 2016 would reduce our gross revenues for the year ending December 31, 2017 by $3.7 million.
From time to time, we utilize commodity derivatives, consisting primarily of swaps, floors and collars to attempt to optimize the price received for our oil and natural gas production. We do not enter into commodity derivatives for trading purposes. When using swaps to hedge our oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally New York Mercantile Exchange (“NYMEX”) futures prices), resulting in a net amount due to or from the counterparty. When purchasing floors, we receive a fixed price (put strike price) if the market price
falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. The commodity derivatives we use differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. In addition to commodity derivatives, we may, from time to time, sell a portion of our gas production under short-term contracts at fixed prices.
The decision to initiate or terminate commodity hedges is made by management based on its expectation of future market price movements. We have no set goals for the percentage of our production we hedge and we do not use any formulas or triggers in deciding when to initiate or terminate a hedge. If we enter into swaps or collars and the floating market price at the settlement date is higher than the fixed price or the fixed ceiling price, we will forego revenue we would have otherwise received. If we terminate a swap, collar or floor because we anticipate future increases in market prices, we may be exposed to downside risk that would not have existed otherwise.
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2016. Settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps:
Costless Collars:
We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil may have on the fair value of our commodity derivatives. As of December 31, 2016, a $1 per barrel change in the price of oil would change the fair value of our commodity derivatives by approximately $1.6 million.
Interest Rates
We are exposed to interest rate risk on our long-term debt with a variable interest rate. At December 31, 2016, our fixed rate debt had a carrying value of $495.5 million and an approximate fair value of $505.7 million, based on current market quotes. We estimate that the hypothetical change in the fair value of our long-term debt resulting from a 100-basis point change in interest rates would be approximately $10.3 million.
Item 8
Item 8 - Financial Statements and Supplementary Data
For the financial statements and supplementary data required by this Item 8, see the Index to Consolidated Financial Statements on page.
Item 9
Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A
Item 9A - Controls and Procedures
Disclosure Controls and Procedures
In September 2002, the Board adopted a policy designed to establish disclosure controls and procedures that are adequate to provide reasonable assurance that our management will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in our reports to the SEC and other communications with our shareholders. Our disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.
With respect to our disclosure controls and procedures:
•
management has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report;
•
this evaluation was conducted under the supervision and with the participation of our management, including our chief executive and chief financial officers; and
•
it is the conclusion of our chief executive and chief financial officers that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Company in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.
Internal Control Over Financial Reporting
Management designed our internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
•
provide reasonable assurance that transactions are recorded as necessary to permit preparation of our consolidated financial statements in accordance with GAAP and that our receipts and expenditures are being made only in accordance with authorizations of management and the Board; and
•
provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of our assets that could have a material effect on our consolidated financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Changes in Internal Control Over Financial Reporting
No changes in internal control over financial reporting were made during the year ended December 31, 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 defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). Based on this assessment, management has concluded that, as of December 31, 2016, our internal control over financial reporting is effective based on those criteria.
KPMG LLP has issued an audit report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016, the contents of which are shown below.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Clayton Williams Energy, Inc.:
We have audited Clayton Williams Energy, Inc.’s (the Company) internal control over financial reporting as of December 31, 2016, based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Clayton Williams Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2016 and 2015, and the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016, and our report dated March 2, 2017 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Dallas, Texas
March 2, 2017
Item 9B
Item 9B - Other Information
Our executive officers have historically participated in certain after-payout, or APO, incentive plans (the “APO Incentive Plans”), which were created to incentivize our executives to find, acquire, develop and produce oil and gas reserves in a cost-effective manner and to reward those executives for the successful management of projects that produced value to our shareholders. We expect to terminate and make final payments under the APO incentive plans based on the aggregate value of the interests held by the plan participants during the second quarter of 2017. For more information on the APO Incentive Plans, see “Item 11 - Executive Compensation - Compensation Discussion and Analysis - Determining Compensation Levels - Long-Term Incentive Compensation.”
The following table sets forth the estimated aggregate payments each named executive officer would have received in connection with the termination of the APO Incentive Plans on January 1, 2017:
PART III
Item 10
Item 10 - Directors, Executive Officers and Corporate Governance
Executive Officers
The following table sets forth certain information regarding our executive officers as of March 2, 2017.
Information regarding Messrs. Williams and Riggs is included below under “Board of Directors - Directors.”
PATRICK G. COOKE, age 55, is Senior Vice President and Chief Operating Officer of CWEI, having served in such capacity since October 2016. Prior to joining the Company, Mr. Cooke was Texas Business Unit Manager for Noble Energy, Inc., which he held from August 2015 until October 2016. From November 2012 until August 2015, Mr. Cooke served as Director of Operations for Noble Energy’s Eastern Mediterranean Business in Israel. Mr. Cooke began his career in the Permian Basin in 1985 with Amoco Production Company. He worked for Amoco and BP for 28 years in various engineering and operations roles throughout the world, including US onshore, US Gulf of Mexico (shelf and deepwater), North Sea, and Egypt offshore. Mr. Cooke is a graduate of Texas A&M University, with a Bachelor of Science degree in Chemical Engineering.
JAIME R. CASAS, age 46, is Senior Vice President and Chief Financial Officer of CWEI, having served in such capacity since October 2016. Prior to joining the Company, Mr. Casas was Vice President and Chief Financial Officer of the general partner of LRR Energy, L.P., a publicly traded exploration and production master limited partnership, which he held from June 2011 to October 2015. From 2009 to 2011, Mr. Casas served as Vice President and Chief Financial Officer of Laredo Energy, a privately held oil and gas company. Prior to 2009, Mr. Casas worked in various positions and industry groups in the investment banking divisions at Credit Suisse and Donaldson, Lufkin & Jenrette. Mr. Casas is a graduate of Texas A&M University, with a
Bachelor of Business Administration degree, and the Wharton School of the University of Pennsylvania, with a Master of Business Administration.
SAMUEL L. LYSSY, JR., age 54, is Vice President - Exploration of CWEI, having served in such capacity since October 2012. Prior to that, Mr. Lyssy had served as Exploration Manager of the Company since 1995. In 1984, Mr. Lyssy earned his Bachelor of Science degree in Geology from St. Mary’s University in San Antonio, Texas and in 1990 earned his Master of Science degree in Geology from the University of Texas at San Antonio. He has been a member of the American Association of Petroleum Geologists since 1997.
Board of Directors
Directors
The following table sets forth certain information regarding our directors as of March 2, 2017.
CLAYTON W. WILLIAMS, JR., age 85, is Chairman of our Board of Directors (the “Board”), Chief Executive Officer and a director of the Company, having served in such capacities since September 1991. Prior to March 2015, Mr. Williams also served as President of the Company. For more than the past ten years, Mr. Williams has also been the chief executive officer and a director of certain entities that are controlled directly or indirectly by Mr. Williams, referred to as the Williams Entities. See “Item 13 - Certain Relationships and Related Transactions, and Director Independence.” Mr. Williams beneficially owns, either individually or through his affiliates, approximately 17.6% of the outstanding shares of the Company’s common stock. See “Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” Mr. Williams is the Company’s Chief Executive Officer and one of the Company’s largest shareholders. Mr. Williams has extensive knowledge of the oil and gas industry, as well as relationships with chief executives and other senior management of oil and gas companies and oilfield service companies throughout the United States. He actively participates in all facets of the Company’s business and has significant influence in matters voted on by the Company’s shareholders, including the election of five of the Company’s Board members.
MEL G. RIGGS, age 62, is President and a director of the Company, having served in such capacities since March 2015. Previously, Mr. Riggs served as Executive Vice President and Chief Operating Officer of the Company, beginning in December 2010, and Senior Vice President and Chief Financial Officer, beginning in September 1991. Mr. Riggs has served as a director of the Company since May 1994. Mr. Riggs is the sole general partner of The Williams Children’s Partnership, Ltd., referred to as WCPL, a limited partnership in which the adult children of Clayton W. Williams, Jr. are the limited partners. WCPL holds approximately 17.3% of the outstanding shares of the Company’s common stock. As the sole general partner, Mr. Riggs has the power to vote or direct the voting of the shares of the Company’s common stock held by WCPL. See “Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.” Mr. Riggs also serves as an officer and director of certain of the Williams Entities. Since July 2009, Mr. Riggs has also served as a director of TransAtlantic Petroleum Ltd., a publicly owned company engaged internationally in the acquisition, development, exploration and production of crude oil and natural gas. Mr. Riggs has served in a leadership position in the Company from its inception and has demonstrated his value as a proven leader. Mr. Riggs has extensive knowledge in strategic planning, is an expert in financial matters and is highly qualified to make strategic and operational decisions on behalf of the Company. Mr. Riggs actively participates in all facets of the Company’s business and has significant influence in matters voted on by the Company’s shareholders, including the election of five of the Company’s Board members.
JORDAN R. SMITH, age 82, is a director of the Company, the chairman of the Audit Committee and a member of the Compensation and Nominating and Governance Committees of the Board. Mr. Smith has served as a director of the Company since July 2000. He is President of Ramshorn Investments, Inc., a wholly owned subsidiary of Nabors Industries, having served in such capacity for more than the past five years. Ramshorn Investments, Inc. is engaged in oil and gas exploration and production. Mr. Smith
has served on the Board of the University of Wyoming Foundation and the Board of the Domestic Petroleum Council. Mr. Smith was chosen as a director nominee because he is an experienced geologist with a high level of technical expertise in the oil and gas industry. In addition, Mr. Smith’s leadership experience with publicly owned companies and overall business background provides the Company with valuable judgment in the conduct of the Company’s business.
DAVIS L. FORD, age 79, is a director of the Company, the chairman of the Nominating and Governance Committee and a member of the Audit and Compensation Committees of the Board. Dr. Ford has served as a director of the Company since February 2004. He has been President of Davis L. Ford & Associates, an environmental engineering and consulting firm, for more than the past five years and is also an adjunct professor at the University of Texas at Austin. Dr. Ford is a distinguished engineering graduate of both Texas A&M University and the University of Texas at Austin and is also a member of the National Academy of Engineering. Dr. Ford’s extensive experience as an environmental engineer specializing in matters pertaining to the oil and gas industry provides the Company with valuable insight into environmental risks and associated regulations. In addition, Dr. Ford’s years of experience in business and his educational background provides the Company with sound advice in the conduct of its business.
P. SCOTT MARTIN, age 60, is a director of the Company, the chairman of the Compensation Committee and a member of the Nominating and Governance Committee of the Board. Mr. Martin has served as a director since he was elected to the Board as a Preferred Director by the holders of the Company’s special voting preferred stock on March 31, 2016. Mr. Martin is the Founder, Chief Executive Officer and Senior Partner of BlackBrush Oil & Gas, LP. BlackBrush is a San Antonio-based oil and gas production and pipeline enterprise that operates over 300,000 gross acres in South Texas. BlackBrush is a controlled portfolio company of funds managed by Ares. Mr. Martin has more than 30 years of energy-related experience in management, accounting, finance, enterprise valuation and mergers and acquisitions, including the last twelve years in various roles at BlackBrush.
NATHAN W. WALTON, age 39, is a director of the Company. Mr. Walton does not currently serve on any Committee of the Board. Mr. Walton has served as a director since he was elected to the Board as a Preferred Director by the holders of the Company’s special voting preferred stock on March 31, 2016. Mr. Walton is a Partner in the Private Equity Group of Ares Management, L.P. and joined Ares in 2006. Additionally, Mr. Walton serves on the Investment Committee of the Ares EIF funds. He also serves on the Boards of Directors of Halcon Resources Corporation, Development Capital Resources, LP, Verdad Resources Holdings LLC and the parent company of BlackBrush Oil & Gas, LP.
RONALD D. SCOTT, age 58, is a director of the Company having served in such capacity since August 2016. Mr. Scott does not currently serve on any Committee of the Board. Mr. Scott has over 30 years of industry experience, much of it in the Permian Basin. Mr. Scott is Chief Executive Officer of Development Capital Resources, LP and Neoteric Energy. Most recently, Mr. Scott was President and Chief Executive Officer of True Oil Company, a private equity backed oil and gas firm. Prior to that, he was President and Chief Operating Officer of Midland-based Henry Petroleum and its successor companies, Henry Resources and HPC Energy. In these endeavors, Mr. Scott successfully led company operations of 20,000 BOE per day spread across 100 wells while incorporating an 8-rig drilling program. Mr. Scott successfully led the sale and re-start of multiple companies during this time. Mr. Scott began his career with Exxon Corporation holding various supervisory and managerial assignments in Engineering, Operations, Planning and Financial Accounting and Reporting. In addition to the Permian Basin, he had assignments covering operational areas in the Gulf Coast / Gulf of Mexico region, California and the Rocky Mountains. Mr. Scott was the Technical Manager for Exxon’s multi-billion dollar onshore operations in the Western United States prior to joining Henry Petroleum. Mr. Scott also serves on the Boards of Directors of Halcon Resources Corporation, BlackBrush Oil & Gas, LP and Pardus Oil and Gas. Mr. Scott holds Master and Bachelor of Science degrees in Electrical Engineering and is a Registered Petroleum Engineer in Texas.
Ted Gray, Jr. served as a director until his resignation from the Board on January 5, 2017. Mr. Gray served on the Audit, Compensation and Nominating and Governance Committees of the Board at the time of his resignation. Robert L. Parker served as a director until his resignation from the Board on March 30, 2016. Mr. Parker served on the Audit, Compensation and Nominating and Governance Committees of the Board at the time of his resignation.
Role of the Board
The business and affairs of the Company are managed under the direction of the Board. The Board has responsibility for establishing broad corporate policies and for overall performance and direction of the Company. Members of the Board stay informed of the Company’s business by participating in Board and committee meetings, by reviewing analyses and reports sent to them regularly, and through discussions with the Chief Executive Officer and other officers. There are no family relationships among any of our directors or executive officers.
Board Structure
The Board currently consists of seven directors. Five of the directors are elected by the holders of the Company’s common stock, and two of the directors are elected by the holders of the Company’s special voting preferred stock, as described below. The five directors elected by the holders of the Company’s common stock are divided into three classes of members. One class of directors is elected each year to hold office for a three-year term and until successors of such class are duly elected and qualified. The directors currently serving on the Board are Clayton W. Williams, Jr., Mel G. Riggs, Davis L. Ford, Jordan R. Smith, P. Scott Martin, Nathan W. Walton and Ronald D. Scott. Effective August 29, 2016, Ronald D. Scott was appointed to the Board. Mr. Scott was nominated to the Board by Ares Management, LLC (“Ares”) pursuant to a Stockholder Agreement between the Company and Ares that was entered into in connection with the closing of the sale of 5,051,100 shares of the Company’s common stock to Ares.
Preferred Directors
Pursuant to the Certificate of Designation of Special Voting Preferred Stock of the Company filed with the Secretary of State of the State of Delaware on March 15, 2016, referred to as the Certificate of Designation, the shares of the Company’s special voting preferred stock grant the holders thereof the right to elect up to two members to the Board, referred to as the Preferred Directors, subject to reductions based on the number of unexercised warrants held by the holders of the special voting preferred stock. On March 31, 2016, the holders of the special voting preferred stock elected Nathan W. Walton and P. Scott Martin to the Board as the Preferred Directors.
Information Regarding Meetings of Non-Management Directors
The Company’s Corporate Governance Guidelines provide that non-management directors will have regularly scheduled meetings in executive session. The Board currently consists of two management directors and five non-management directors. During 2016, certain of the non-management directors served on the standing Board committees, specifically the Audit Committee, the Compensation Committee and the Nominating and Governance Committee. Executive sessions of the Company’s non-management directors were held in connection with these committee meetings, with the applicable committee chair presiding at any executive session held in connection with such meeting.
During 2017, the Board intends to hold executive sessions of the Company’s non-management directors in connection with our regularly scheduled board meetings and at least one meeting consisting solely of its independent directors. A non-management director (determined on a rotating basis) will preside at each executive session held in connection with such meeting. An independent director (determined on a rotating basis) will preside at the meeting of independent directors.
Director Independence
A majority of the directors serving on the Board qualify as independent directors under regulations of the Securities and Exchange Commission (“SEC”), and under the corporate governance listing standards of the New York Stock Exchange, referred to as the NYSE, and also qualify as “outside directors” for purposes of Section 162(m) of the Internal Revenue Code, referred to as the Tax Code. In determining independence, each year the Board affirmatively determines, among other things, whether the directors have any material relationships with the Company (either directly or as a partner, shareholder or officer of an organization that has a relationship with the Company). When determining if such a relationship exists, the Board considers all relevant facts and circumstances, not merely from the director’s standpoint, but from that of the persons or organizations with which the director has an affiliation, and, if applicable, the frequency or regularity of the services, whether the services are being carried out at arm’s length in the ordinary course of business, and whether the services are being provided substantially on the same terms to the Company as those prevailing at the time from unrelated parties for comparable transactions. Such relationships can include commercial, banking, industrial, consulting, legal, accounting, charitable and familial relationships. Applying these independence standards, the Board has determined that Messrs. Ford, Martin, Smith and Scott are all independent directors, except that Messrs. Martin and Scott are not independent directors for purposes of the Audit Committee.
In reaching these conclusions regarding independence, the Board considered the following with respect to Messrs. Martin and Scott. P. Scott Martin, Founder, Chief Executive Officer and Senior Partner of BlackBrush Oil & Gas, LP, (“BlackBrush”), was elected to the Board by the holders of the Company’s special preferred voting stock, all of which is currently owned by funds managed by Ares Management, L.P. Funds managed by Ares also own a controlling interest in BlackBrush. Ronald D. Scott, former President and Chief Executive Officer of True Oil Company, was recommended to the Nominating and Governance Committee by funds managed by Ares. Funds managed by Ares also led an investor group in an equity capital commitment in True Oil Company. The Board has determined that Messrs. Martin’s and Scott’s relationship with Ares does not interfere with
their exercise of independent judgment in carrying out the responsibilities of a director of the Company, and that they are independent directors under the applicable NYSE corporate governance listing standards and federal securities laws. However, the Board has determined that Messrs. Martin and Scott may not meet the enhanced independence standards under the NYSE rules and Rule 10A-3(b)(1) of the Securities Exchange Act of 1934, referred to as the Exchange Act, for purposes of Audit Committee membership, and, accordingly, has decided not to consider Messrs. Martin or Scott for election to the Audit Committee. The Board has determined that Mr. Walton is not an independent director under NYSE listing standards and federal securities laws due to the positions he holds with Ares, as described above.
Board Committees
The Board has three standing committees: Compensation, Nominating and Governance, and Audit. The Board has determined that each member of these committees is independent consistent with federal securities laws and the NYSE corporate governance listing standards.
Compensation Committee
The Compensation Committee held nine meetings during 2016. Directors Martin (Chairman), Ford and Smith currently serve on the Compensation Committee. Mr. Gray served as a director and Chairman of the Compensation Committee until his resignation from the Board on January 5, 2017, and Mr. Parker served as a director on the Compensation Committee until his resignation from the Board on March 30, 2016. The purposes of the Compensation Committee are:
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To review, evaluate, and approve the agreements, plans, policies and programs of the Company to compensate its executive officers and directors;
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To review the Compensation Discussion and Analysis prepared by management and proposed for inclusion in the Company’s proxy statement for its annual meeting of shareholders and to determine whether to recommend to the Board that the Compensation Discussion and Analysis be included in such proxy statement;
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To produce the Compensation Committee report as required by Item 407(e)(5) of Regulation S-K for inclusion in the proxy statement in accordance with applicable rules and regulations;
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To provide assistance to the Board in discharging its responsibilities relating to the compensation of the executive officers and directors of the Company; and
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To perform such other functions as the Board may assign to the Committee from time to time.
The specific responsibilities of the Compensation Committee are identified in the Compensation Committee’s charter, which is available on the Company’s website at www.claytonwilliams.com under “Investors/Corporate Governance.”
Pursuant to its charter, the Compensation Committee may appoint subcommittees for any purpose that the Compensation Committee deems appropriate and delegate to these subcommittees any power and authority the Compensation Committee deems appropriate. Historically the Compensation Committee has not delegated any of its powers and authority and, at this time, the Compensation Committee does not intend to delegate its powers and authority to any subcommittee.
Agendas for meetings of the Compensation Committee are generally prepared by members of senior management in consultation with the Chairman of the Compensation Committee. Compensation Committee meetings are regularly attended by members of senior management. The Compensation Committee also regularly meets in executive session without the Company’s officers being present. In addition, in accordance with the Compensation Committee’s charter, the Chief Executive Officer may not be present when the Committee is voting or deliberating on his compensation. The Compensation Committee has the authority to annually review and make recommendations to the Board with respect to incentive compensation plans and equity-based plans.
The Compensation Committee has the authority to secure the services of independent consultants and advisors and the Company’s legal, accounting and human resources departments to support the Compensation Committee in fulfilling its responsibilities. The Compensation Committee has authority under its charter to retain, approve fees for, and terminate independent consultants and advisors as it deems necessary to assist in the fulfillment of its responsibilities. A detailed description of the processes and procedures of the Compensation Committee for the consideration and determination of executive and director compensation can be found under “Executive Compensation - Compensation Discussion and Analysis.”
None of the individuals serving on the Compensation Committee, including Messrs. Parker and Gray during their service on the committee, has ever been an officer or employee of the Company. All of the members of the Compensation Committee,
including Messrs. Parker and Gray during their service on the committee, satisfy the independence requirements of federal securities laws and the NYSE corporate governance listing standards. Additionally, all of the members of the Compensation Committee, including Messrs. Parker and Gray during their service on the committee, qualify as “non-employee directors” for purposes of Rule 16b-3 under the Exchange Act, and as “outside directors” for purposes of Section 162(m) of the Tax Code.
Nominating and Governance Committee
The Nominating and Governance Committee met three times in 2016. Directors Ford (Chairman), Martin and Smith currently serve on the Nominating and Governance Committee. Mr. Gray served as a director on the Nominating and Governance Committee until his resignation from the Board on January 5, 2017, and Mr. Parker served as a director on the Nominating and Governance Committee until his resignation from the Board on March 30, 2016. The purposes of the Nominating and Governance Committee are:
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To identify individuals qualified to become Board members, consistent with criteria approved by the Board, and to select the director nominees for election at the annual meetings of shareholders or for appointment to fill vacancies;
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To recommend to the Board director nominees for each committee of the Board;
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To advise the Board about appropriate composition of the Board and its committees;
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To advise the Board about and recommend to the Board appropriate corporate governance practices and to assist the Board in implementing those practices;
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To lead the Board in its annual review of the performance of the Board and its committees; and
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To perform such other functions as the Board may assign to the Committee from time to time.
The specific responsibilities of the Nominating and Governance Committee are identified in the Nominating and Governance Committee’s charter, which is available on the Company’s website at www.claytonwilliams.com under “Investors/Corporate Governance.” There have been no changes to the procedures by which shareholders may recommend nominees to the Board since the filing of the Company’s proxy statement for its annual meeting of shareholders on April 28, 2016.
Audit Committee
The Audit Committee held six meetings during 2016 and took action by unanimous written consent once. Directors Smith (Chairman) and Ford currently serve on the Audit Committee. Mr. Gray served as a director on the Audit Committee until his resignation from the Board on January 5, 2017, and Mr. Parker served as Chairman of the Audit Committee until his resignation from the Board on March 30, 2016. The Company is not currently in compliance with Section 303A.07(a) of the New York Stock Exchange Listed Company Manual because the Audit Committee consists of only two members following Mr. Gray’s resignation on January 5, 2017. The purposes of the Audit Committee are:
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To assist the Board in fulfilling its oversight responsibilities regarding the:
•Integrity of the Company’s financial statements;
•Company’s compliance with legal and regulatory requirements;
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Qualifications, independence and performance of the independent registered public accounting firm engaged for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Company (the “independent auditors”);
•Effectiveness and performance of the Company’s internal audit function;
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To annually prepare an Audit Committee report and publish the report in the Company’s proxy statement for its annual meeting of shareholders, in accordance with applicable rules and regulations; and
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To perform such other functions as the Board may assign to the Committee from time to time.
All of the members of the Audit Committee, including Messrs. Parker and Gray during their service on the committee, qualify as an independent director under the federal securities laws and the NYSE corporate governance listing standards. The Board has determined that no member of the Audit Committee, including Messrs. Parker and Gray during their service on the committee, meets all of the criteria needed to qualify as an “audit committee financial expert” as defined by SEC regulations. The Board believes that each of the current members, including Messrs. Parker and Gray during their service on the committee, of the Audit Committee has sufficient knowledge and experience in financial matters to perform his duties on the Audit Committee. In addition, the Audit Committee has engaged, at the Company’s expense, Davis Kinard & Co., certified public accountants, as a financial accounting consultant to independently advise the Audit Committee in the area of technical accounting issues and to assist the Audit Committee in fully understanding any matters that may come before the Audit Committee, including matters related to:
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Generally accepted accounting principles and the application of such principles in connection with accounting for estimates, accruals and reserves;
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Internal controls and procedures for financial reporting; and
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Other Audit Committee functions.
The specific responsibilities of the Audit Committee are identified in the Audit Committee’s charter, which is available on the Company’s website at www.claytonwilliams.com under “Investors/Corporate Governance.” The Audit Committee serves as an independent and objective party to oversee the accounting and financial reporting practices of the Company and the audits of its financial statements. The Audit Committee has the sole authority and responsibility with respect to the selection, engagement, compensation, oversight, evaluation and, where appropriate, dismissal of the independent auditors and any other public accounting firm engaged by the Company. The independent auditors, and any other public accounting firm engaged by the Company, report directly to the Audit Committee.
Report of the Audit Committee
The following is the report of the Audit Committee with respect to the Company’s audited financial statements for the year ended December 31, 2016.
During 2016, the Audit Committee consisted of Messrs. Parker, Ford, Gray and Smith. The Audit Committee acts pursuant to the Audit Committee charter, as amended and restated in May 2014. Each member of the Audit Committee qualifies as an “independent” director under federal securities laws and NYSE corporate governance listing standards. Mr. Parker resigned from the Board and as Chairman of the Audit Committee effective March 30, 2016. Mr. Gray resigned from the Board and as a member of the Audit Committee effective January 5, 2017.
In March 2017, the Audit Committee reviewed and discussed the Company’s audited financial statements with management and representatives of KPMG LLP, the Company’s independent auditors. Particular attention was paid to the selection, application and disclosure of the Company’s critical accounting policies. The Audit Committee also discussed with KPMG LLP the matters required to be discussed by Auditing Standard No. 16, as adopted by the Public Company Accounting Oversight Board. The Audit Committee received the written disclosures and the letter from KPMG LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the Audit Committee concerning independence, and has discussed with KPMG LLP their independence from the Company and management. The Audit Committee considered whether the non-audit services provided by KPMG LLP are compatible with their independence.
Based on the review and discussions referred to above, the Audit Committee took the following actions:
•
Ratified management’s selection, application and disclosure of critical accounting policies as set forth in the Company’s audited financial statements for the year ended December 31, 2016;
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Recommended to the Board that the Company’s audited financial statements be included in its Annual Report on Form 10-K for the year ended December 31, 2016; and
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Reviewed the Audit Committee charter, assessed the charter for adequacy, and determined that the charter, as stated, was adequate.
AUDIT COMMITTEE
Jordan R. Smith, Chairman
Davis L. Ford
Director Compensation
Retainer and Fees
During 2016, compensation for non-employee directors consisted of an annual retainer fee of $45,000 plus a $7,500 fee for each Board meeting attended and a $1,000 fee for attending a committee meeting held on a day other than the same day of a Board meeting, including special committee meetings. The chairmen of the Audit, Compensation, and Nominating and Governance Committees each receive additional retainers of $15,000, $10,000 and $8,500 respectively.
Compensation for non-employee directors is reviewed annually by the Compensation Committee.
Stock Option Awards
As of April 2016, non-employee directors are eligible to receive awards pursuant to the Company’s Long-Term Incentive Plan.
Director Compensation Table
The table below summarizes the compensation paid to the Company’s non-employee directors for the fiscal year ended December 31, 2016. Columns (d) through (g) have been deleted from the SEC-prescribed tabular format because the Company did not provide compensation to its directors in 2016 other than fees and stock awards.
DIRECTOR COMPENSATION TABLE
(a)
Reflects the grant date fair value.
Compensation Committee Interlocks and Insider Participation
The Compensation Committee consists of Directors Martin (Chairman), Ford and Smith. Mr. Gray served as a director and Chairman of the Compensation Committee until his resignation from the Board on January 5, 2017, and Mr. Parker served as a director on the Compensation Committee until his resignation from the Board on March 30, 2016. None of these committee members has or had a relationship with the Company that is or was required to be disclosed under the rules of the SEC.
Corporate Governance Documents
The Company maintains a corporate governance page on its website at www.claytonwilliams.com under “Investors/Corporate Governance” where you can find the following documents:
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The Company’s Corporate Governance Guidelines;
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The Company’s Code of Conduct & Ethics;
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The Company’s Financial Code of Conduct; and
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The charters of the Company’s Audit, Compensation and Nominating and Governance Committees.
The Company will also provide a printed copy of these documents, free of charge, to shareholders who request copies in writing from Patti Hollums, Director of Investor Relations, Clayton Williams Energy, Inc., 6 Desta Drive, Suite 6500, Midland, Texas 79705.
Communications with the Board
Communications by shareholders or by other parties may be sent to the Board by mail or overnight delivery and should be addressed to the Board c/o, Clayton Williams Energy, Inc., 6 Desta Drive, Suite 6500, Midland, Texas 79705, Attention: Secretary. Communications directed to the Board or to one or more Board members, including any independent director or the independent directors as a group, will be forwarded directly to the designated member or members and may be made anonymously.
Section 16(a) Beneficial Ownership Reporting Compliance
Based solely upon a review of Forms 3, 4 and 5 and amendments thereto furnished to the Company pursuant to the rules and regulations promulgated under Section 16(a) of the Exchange Act, during and with respect to the Company’s last fiscal year and upon certain written representations received by the Company, the Company believes that all filing requirements applicable to officers, directors and 10% beneficial owners under Section 16(a) were satisfied, except Mr. Gregory S. Welborn, Vice President - Land, filed a late Form 3 on September 2, 2016 to report his initial statement of beneficial ownership of the Company’s common stock, which should have been filed within 10 days of March 1, 2006.
Item 11
Item 11 - Executive Compensation
Compensation Discussion and Analysis
General
The Compensation Committee consists of Messrs. Ford, Martin and Smith, all of whom are independent directors under current federal securities laws and the NYSE corporate governance listing standards, “non-employee directors” for purposes of Rule 16b-3 under the Exchange Act, and “outside directors” for purposes of Section 162(m) of the Tax Code. The Compensation Committee establishes the salaries of all corporate officers, including the named executive officers set forth in the Summary Compensation Table below, and directs and administers the Company’s incentive compensation plans. The Compensation Committee also reviews with the Board its recommendations relating to the future direction of corporate compensation practices and benefit programs.
Throughout this Form 10-K, the following individuals are referred to as the named executive officers:
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Clayton W. Williams, Jr., Chairman of the Board and Chief Executive Officer
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Mel G. Riggs, President
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Patrick G. Cooke, Senior Vice President and Chief Operating Officer
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Michael L. Pollard, former Senior Vice President and Chief Financial Officer
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Jaime R. Casas, Senior Vice President and Chief Financial Officer
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Samuel L. Lyssy, Jr., Vice President - Exploration
Compensation Philosophy and Principles
The Compensation Committee recognizes that the oil and gas exploration and production industry is highly competitive and that experienced professionals have significant career mobility. The Company competes for executive talent with a large number of exploration and production companies, some of which have significantly larger market capitalization than the Company. Comparatively, the Company is a smaller company in a highly competitive industry, and its ability to attract, retain and reward its executive officers and other key employees is essential to maintaining an advantageous position in the oil and gas business. The Company’s comparatively smaller size within its industry and its relatively small executive management team provide unique challenges in this industry, and therefore, are substantial factors in the design of the executive compensation program. The Compensation Committee’s goal is to maintain compensation programs that are effective in attracting and retaining talented individuals within the independent oil and gas industry. Each year, the Compensation Committee reviews the executive compensation program to assess whether the program remains comparable with those of similar companies, considers the program’s effectiveness in creating adequate incentives for executives to find, acquire, develop and produce oil and gas reserves in a cost-effective manner, and determines what changes, if any, are appropriate.
The Compensation Committee has adopted a compensation policy that it believes to be a balance between fair and reasonable cash compensation and incentives linked to the Company’s performance, taking into consideration compensation of individuals with similar duties who are employed by its peers in the industry. The policy takes into account the cyclical nature of the oil and gas business, which may result in traditional performance standards being skewed due to erratic commodity prices. An analysis of the Company’s goals has resulted in a policy that places an emphasis on increasing the Company’s proved oil and gas reserves and production, coupled with maintaining an acceptable balance between its overhead and profit margin. As described more fully below, the Compensation Committee may, in addition to base salaries, award bonuses and direct participation incentives in exploration and production projects based upon the performance of the Company and the efforts of individual executives and key employees.
In determining the form and amount of compensation payable to the Company’s executive officers, the Compensation Committee is guided by the following objectives and principles:
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Compensation levels should be sufficiently competitive to attract, motivate and retain key executives. The Compensation Committee aims to ensure that the Company’s executive compensation program attracts, motivates and retains outstanding
talent and rewards that talent to the extent the Company achieves and maintains a competitive position in its industry. Total compensation (i.e., maximum achievable compensation) should increase with position and responsibility.
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Compensation should relate directly to performance, and incentive compensation should constitute a substantial portion of total compensation. The Compensation Committee aims to foster a pay-for-performance culture, with a significant portion of total compensation being contingent, directly or indirectly, on Company or individual performance. Accordingly, a substantial portion of total compensation should be tied to and vary with the Company’s financial, operational and strategic performance, as well as individual performance.
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Long-term incentive compensation should align the interests of executives with the Company’s shareholders. Awards of long-term incentive compensation encourage executives to focus on the Company’s long-term strategic growth and prospects and incentivize executives to manage the Company from the perspective of its shareholders.
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Retirement benefits should comprise an element of executive compensation. The Company does not offer retirement benefits to its executive officers other than through its tax-qualified 401(k) plan. Therefore, the Compensation Committee has designed the Company’s long-term incentive compensation to also provide a competitive level of replacement income upon retirement.
The Company’s executive compensation program is designed to reward the achievement of objectives regarding Company growth and productivity, but it also takes into consideration the role and responsibilities of individual executive officers within the Company and internal pay equity. Therefore, the Company’s executive compensation is designed:
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To encourage the Company’s executive officers to maintain a thorough and dynamic understanding of the competitive environment and to position the Company as a respected force within its industry;
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To incentivize the Company’s executive officers to develop strategic opportunities that benefit the Company and its shareholders;
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To sustain an internal culture focused on performance and the development of the Company’s assets into producing properties;
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To require the Company’s executive officers and other key employees to share the risks facing its shareholders, and to enable them to share in the rewards associated with the successful development of the Company’s assets into producing properties; and
•
To implement a culture of compliance and unwavering commitment to operate the Company’s business with the highest standards of professional conduct and compliance.
Advisory Vote on Executive Compensation
In 2014, the Company held its second shareholder advisory vote on the compensation paid to the named executive officers in 2013, which resulted in more than 99% of votes cast approving such compensation. As recommended by the Board, shareholders expressed their preference for an advisory vote on executive compensation once every three years, and the Company has implemented that recommendation.
The Compensation Committee evaluated the results of the 2014 advisory vote on executive compensation and the overwhelming support expressed by shareholders at the Company’s 2014 meeting. The Compensation Committee also considered many other factors in evaluating the Company’s executive compensation programs as discussed in this compensation discussion and analysis, including the Compensation Committee’s assessment of the interaction of the Company’s compensation programs with its corporate business objectives, evaluations of the Company’s programs by its external compensation consultant, and review of comparative compensation data which included information regarding a selected group of peers. Each of these factors was evaluated in the context of the Compensation Committee’s duty to act as the directors believe to be in the shareholders’ best interests. While each of these factors bore on the Compensation Committee’s decisions regarding the Company’s named executive officers’ compensation, the Compensation Committee did not make any changes to its executive compensation program and policies as a result of the 2014 “say on pay” advisory vote. Given the support shareholders expressed for the Company’s executive compensation programs at the Company’s 2014 annual meeting, the Compensation Committee generally elected to continue to apply the same principles in determining the types and amounts of compensation to be paid to the named executive officers in 2014.
Setting Executive Compensation
Management’s Role in Setting Executive Compensation
Mr. Riggs, in consultation with Mr. Williams, evaluates all executive officers, including the named executive officers other than himself, and makes recommendations to the Compensation Committee regarding base salary levels and the amounts of any incentive bonus payments and long-term incentive awards to be granted to all executive officers. In 2016, Mr. Pollard assisted in this evaluation and preparation of compensation recommendations. No executive makes recommendations with respect to his own compensation. Additionally, Messrs. Williams, Riggs and Pollard (and, after Mr. Pollard’s departure, Mr. Casas) regularly attend Compensation Committee meetings. These recommendations are given significant weight by the Compensation Committee but are not necessarily determinative of the compensation decisions made by the Compensation Committee. These recommendations are used as points of reference, not as a replacement for the Compensation Committee’s own judgment of internal pay equity or the individual performance of an executive that the Compensation Committee also considers when making compensation decisions.
Use of Independent Consultants
The Compensation Committee charter provides the Compensation Committee with the authority to retain and terminate any compensation consulting firm or other advisor it deems appropriate.
The Compensation Committee engaged Longnecker & Associates, or L&A, to conduct a market compensation analysis and to provide recommendations regarding the total direct compensation packages of the Company’s named executive officers. In selecting L&A as its compensation consultant, the Compensation Committee assessed the independence of L&A pursuant to SEC rules and considered, among other things, whether L&A provides any other services to the Company, fees paid to L&A as a percentage of its revenue, the policies of L&A that are designed to prevent any conflict of interest between L&A, the Compensation Committee and the Company, any personal or business relationship between L&A and a member of the Compensation Committee or one of the Company’s executive officers and whether L&A owned any shares of the Company’s common stock. L&A was engaged directly by the Compensation Committee, reports exclusively to the Compensation Committee and does not provide any additional services to the Company. The Compensation Committee has concluded that L&A is independent and does not have any conflicts of interest. While management did cooperate with L&A in collecting data with respect to the Company’s compensation programs, the Compensation Committee determined that management had not attempted to influence L&A’s review or recommendations.
Market Compensation Analysis
In June 2016, the Compensation Committee reviewed a comparative analysis of the compensation paid to the Company’s Chief Executive Officer and other executive officers to compensation data for a peer group of independent exploration and production companies compiled and presented by L&A.
The Company’s compensation peer group was determined by senior management with assistance from L&A. The Compensation Committee concluded that the group of companies selected was an appropriate peer group for the comparison of salary and other compensation payable to the Company’s executive officers, including its Chief Executive Officer and its other named executive officers. The peer companies represented a wide range of independent exploration and production companies of similar size to the Company that operate in some of the same geographical areas as the Company.
The 2016 peer group was comprised of the following companies:
The objective of the Compensation Committee in reviewing market pay levels within the peer group is to ensure that compensation payable to its executive officers is competitive and not out of market. As noted, however, market pay levels are only one factor considered, with pay decisions ultimately reflecting an evaluation of individual contributions of an executive officer and the executive’s value to the Company.
The data provided by L&A revealed the following with respect to the compensation provided by the Company to its executive officers (including its named executive officers) and the performance of the Company in comparison with its peer group:
•
Base salaries for executive officers, on average, are aligned with the 50th percentile of the comparative compensation data (specifically 107% of the 50th percentile).
•
Targeted total annual cash (including base salary and the average of the last three years of annual discretionary incentive bonuses to the Company’s executive officers) are aligned with the 25th percentile of the comparative compensation data (specifically 100% of the 25th percentile).
•
The annual long term incentive compensation paid by the Company to the executive officers, based on three-year historical data, was below the 25th percentile of the comparative compensation data (specifically 55% of the 25th percentile) and, based on the average of three-year historical and projected payments over the next three years, is 68% of the 25th percentile of the comparative compensation data.
•
Total annual direct compensation paid to the Company’s executive officers was also below the 25th percentile of the comparative compensation data, both with respect to historical and the average of historical and projected comparisons (specifically 80% and 86% of historical and average total direct compensation, respectively, of the 25th percentile).
The Compensation Committee does not believe that it is appropriate to establish compensation levels based exclusively or primarily on benchmarking to the Company’s peers. The Compensation Committee looks to external market data only as a reference point in reviewing and establishing individual pay components and total compensation and ensuring that the Company’s executive compensation is competitive in the marketplace. The Compensation Committee does not attempt to set total compensation or any component of compensation within a specific percentile of the Company’s peer group. However, the Compensation Committee recognizes the competitive market for hiring and retaining oil and gas executives in the Permian Basin area and the consequent need to provide compensation to the Company’s executives that is competitive with the 50th percentile of market compensation in order to retain and attract talented and experienced employees. Therefore, the reports provided by L&A were instructive to the Compensation Committee insofar as they enabled the Compensation Committee to (1) verify that base salaries are competitive, (2) recognize that historic incentive payments continue to be considerably below market, and (3) recognize that total direct compensation continues to be below market.
Determining Compensation Levels
The Compensation Committee annually reviews and determines the individual pay components of the Company’s executive officers. In its 2016 review, the Compensation Committee considered (1) recommendations of Mr. Riggs, based on individual responsibilities and performance, (2) historical compensation levels for each executive officer, (3) industry conditions and the Company’s future objectives and challenges, (4) the overall effectiveness of the executive compensation program, (5) the overwhelming support expressed by shareholders in the 2014 advisory vote on executive compensation, and (6) the recommendations of L&A.
Historically, the base compensation of the Company’s named executive officers has been less than 50% of the total compensation of the named executive officers, with the bulk of the remainder of compensation consisting of discretionary bonuses and long-term incentives, and with other annual compensation consisting of less than 5% of the total compensation. This is not due to any specific policy, practice or formula regarding the proper allocation between different elements of total compensation, but does reflect the desire of the Compensation Committee to emphasize variable components of compensation to foster a pay-for-performance culture. In 2016, base compensation was on average 6% of the total compensation of the Company’s named executive officers, ranging between 1% and 38% of total compensation as reported in the Summary Compensation Table below.
The components of compensation paid to executive officers in 2016 were:
•
Base salary;
•
Discretionary bonus;
•
Long-term incentive awards; and
•
Other annual compensation.
Compensation of executive officers has generally consisted of these elements since 2001, although equity compensation was incorporated into the form of long-term incentive awards utilized by the Company in 2016.
The Compensation Committee has reviewed all components of the compensation of the Chief Executive Officer and the other named executive officers, including salary, bonus and long-term incentive compensation, the dollar value to the executive and the cost to the Company of all perquisites and other personal benefits, and the projected future payouts under non-equity long- term incentive awards described below. In addition, as described above, the Compensation Committee has reviewed the compensation of executive officers set forth in comparative compensation data. The Compensation Committee has reviewed the compensation policies of the Company and discussed the increased competition encountered by the Company in attracting and retaining qualified employees.
Based upon recommendations provided by Messrs. Williams, Riggs and Pollard (and in the future, Mr. Casas), and upon its own judgment, the Compensation Committee approved the base salary, discretionary bonus, long-term incentive awards and other annual compensation of each of the Company’s executive officers in 2016. The Compensation Committee believes these approved forms and levels of compensation are reasonable, appropriate and consistent with the Company’s compensation philosophy and principles. Further, the Compensation Committee believes the Company’s executive compensation program is effective because (1) the Company has retained its executive team in a competitive industry, and (2) the Company has demonstrated its ability to find, acquire, develop and produce oil and gas reserves in a cost-effective manner.
Base Salary
Base salary is set by the Compensation Committee at a level based on each executive officer’s position, level of responsibility, and individual performance. While it is the general intent of the Compensation Committee that a significant portion of the total compensation paid to the executive officers be attributable to variable compensation, either in the form of discretionary bonuses or long-term incentive awards, when base salaries of executives are set by the Compensation Committee (most recently in the second quarter of the year), it cannot be certain of the amount of total variable compensation that will be paid due to the nature of the Company’s long-term incentive compensation program discussed in greater detail below. The Compensation Committee believes that its reliance on variable compensation fosters a pay-for-performance culture by tailoring annual compensation to the success of projects in which an executive officer is involved, while ensuring that the executive will continue to receive a consistent base amount of compensation.
Bonus
Bonuses are discretionary and are paid if and when the Compensation Committee determines they are appropriate to reward exceptional individual performance and to encourage loyalty to the Company and the interests of its shareholders. The Compensation Committee believes that such bonuses serve both as a reward for performance and an incentive for future extraordinary performance in anticipation of such recognition.
Executive officers of the Company, including Messrs. Williams, Riggs and Pollard (and in the future, Mr. Casas), may recommend bonuses to the Compensation Committee for their approval to reward individual performance. Annual bonuses may also be used to compensate particular executives and key employees who the Compensation Committee determines are less than fully compensated at a particular point in time due to the failure of the long-term incentive awards granted to the employee to result in payment. As is described in greater detail below, the nature of the Company’s long-term incentive award program is such that an award could fail to ever result in payment through no lack of effort by the executive and in circumstances where the performance of the Company as a whole is very good. Although as a general policy, the Compensation Committee believes that executives should share the risks and rewards of the Company’s shareholders, if over a period of time an executive is undercompensated due to the nature of the Company’s long-term incentive program, the Compensation Committee will consider paying additional cash bonuses to the executive.
In 2016, bonuses paid to the Company’s executive officers were generally based on management recommendations to award the named executive officers for their individual performance. Bonuses were not paid pursuant to pre-established performance criteria communicated to the executives. Instead, bonuses were paid periodically throughout the year upon completion of various projects to the executives involved in such projects, as recommended by management and approved by the Compensation Committee. Specifically, the Company paid cash bonuses of approximately $100,000 each to Messrs. Riggs and Pollard, respectively, for services performed in 2016 related to the successful completion of the Ares transaction.
Finally, the Company has historically paid Christmas bonuses to all employees, including executive officers, in amounts ranging from one-third to one-half of a month’s base salary. In 2016, the named executive officers received Christmas bonuses
equal to approximately one-half of a month’s base salary. The discretionary bonuses paid to each of the named executive officers in 2016 is quantified below in the section titled “- Summary Compensation Table.”
Long-Term Incentive Compensation
In recent years, long-term incentive compensation available to the Company’s executive officers has consisted of non-equity awards. In 2016, the Compensation Committee reviewed its long-term incentive compensation arrangements in light of its objective of aligning the interests of executives with those of the Company’s shareholders.
In a low commodity price environment with depressed stock prices the Compensation Committee desired to restructure the Company’s long-term incentive compensation vehicles to increase alignment between executive pay and stock price performance and to avoid the potential for increasing cash compensation of executives in a climate of stock price uncertainty. Consequently, the Company adopted, and its shareholders approved, the Company’s Long-Term Incentive Plan (the “LTIP”) to provide for the grant of equity based long-term incentive compensation to employees.
Following approval of the LTIP, the Compensation Committee did not create new compensatory arrangements under the APO Incentive Plan, described in greater detail below, or add any new wells to existing arrangements under the APO Incentive Plan. The APO Incentive Plan as it exists currently will continue in place and participants will be entitled to receive payments pursuant to the terms of the APO Incentive Plan much in the same way that the previously established APO Working Interest Grant and APO Working Interest Trusts, as described below, continued in existence after their replacement by the APO Incentive Plan. Long-term incentive awards granted in 2016 consisted solely of stock options and restricted stock awards granted under the LTIP. Given his current stock ownership, Mr. Williams did not receive any equity awards pursuant to the LTIP. The Compensation Committee determined that the appropriate mix of stock options and restricted stock would be, for most positions, 75% restricted stock and 25% options. Consequently, if a named executive officer was granted awards with respect to 24,000 shares, 18,000 would constitute restricted stock and 6,000 would constitute options. This mix provides retention value to the Company and stockholder alignment, in the form of unvested shares of restricted stock, as well as the incentive to increase shareholder value, since stock options only have value to the extent the Company’s share price increases. Messrs. Riggs, Cooke and Casas’ mix of restricted stock to stock options is 50% of each type of award given their responsibility in long-term strategic planning and the desire to align their compensation, to a greater degree than the other executives, to a long-term increase in shareholder value.
The stock options and restricted stock awards granted to the Company’s named executive officers generally vest (and, in the case of options, become exercisable) in one-third increments on the first, second and third anniversaries of the date of grant of the awards. Subject to the terms of any employment agreement between a named executive officer and the Company, the options and restricted stock awards, to the extent unvested, will be forfeited upon termination of the named executive officer’s service relationship. The stock options are designed to be incentive stock options to the extent permitted by the Tax Code. The number of awards granted to the named executive officers can be found in the table below under “- Grants of Plan-Based Awards.”
Equity awards will likely be the Company’s preferred method of providing long-term incentive compensation to its employees. However, the Company’s historic cash-based incentive plans have not been terminated and may still provide for ongoing cash compensation to the executives who were previously granted awards under those arrangements. A description of those historic arrangements follows.
APO Plans
The executive officers, key employees and consultants of the Company participate in an after-payout, or APO, incentive plan, referred to as the APO Incentive Plan. The APO Incentive Plan was created to incentivize the Company’s executives to find, acquire, develop and produce oil and gas reserves in a cost-effective manner, and to reward those executives for the successful management of projects that produce value to the Company’s shareholders. The APO Incentive Plan provides for the creation of a series of partnerships (either limited partnerships or tax partnerships) through which the Company contributes a portion of its working interests in wells drilled or acquired within certain geographical areas. Under the APO Incentive Plan, the Company pays all costs and receives all revenues relative to the contributed working interests until it achieves “Payout,” which is generally the return of its costs, plus interest. After Payout, the officers, key employees and consultants who were granted the right to participate in the partnership receive at least 99% of the partnership’s subsequent revenues and pay at least 99% of its subsequent expenses. The Compensation Committee believes that aligning a portion of the executive officers’ long-term compensation to the performance of the Company’s exploration, development and acquisition programs is both a reward for the acquisition and development of such properties and an incentive to manage the properties in a manner that will maximize the long-term success for both the Company and themselves.
From 2002 through 2005, APO Incentive Plan awards were structured as limited partner interests in Texas limited partnerships. Since 2006, the APO Incentive Plan awards have been structured as participation agreements that are intended by the participants to be treated as partnerships solely for federal and state income tax purposes. Although the economics of the APO Incentive Plan awards in the Texas limited partnership structure and the participation agreement structure have remained unchanged, the current practice of utilizing participation agreements is preferable to, and is less burdensome for the Company to administer than, the limited partnership structure.
Although the percentage of the Company’s contributed working interests varies from partnership to partnership, contributions under the APO Incentive Plan currently range from 5% to 7.5% of the Company’s working interests in the applicable wells, depending on the nature of the underlying project. The percentage of working interests contributed is determined in the discretion of the Compensation Committee after considering recommendations made by Mr. Williams.
At the time APO Incentive Plan awards are granted, the ultimate amount payable to the participants under the award is not determinable. Each APO Incentive Plan award represents a potential working interest in one or more wells in a limited geographic area. Potentially, the award may never become payable, or it may become payable at an indeterminable future date. The participants who receive specific APO Incentive Plan awards, and the size of the APO Incentive Plan award granted to each participant, are determined at the discretion of the Compensation Committee after considering recommendations made by Mr. Williams. Generally, each particular working interest in a geographic area is awarded to the executive officers and key employees primarily responsible for that project. The size of the APO Incentive Plan award granted to each participant out of that particular working interest is generally determined based upon his or her potential individual impact on the success of the project.
Once granted, an APO Incentive Plan award is fully vested and is not forfeitable, except in circumstances of fraud against the Company by a participant. However, the Company retains the right to grant new APO Incentive Plan awards in the same geographic area. This allows the Company to effectively limit a participant’s award to the then-existing wells, without preserving a participant’s future interest in further drilling activity in that same geographic area.
No awards were made under the APO Incentive Plan in 2016. A detailed description of all awards made under the APO Incentive Plan, historically, and amounts paid to the named executive officers in 2016 pursuant to existing APO Incentive Plan awards can be found under “- Summary Compensation Table,” “- Narrative Disclosure to Summary Compensation Table” and “- Supplemental Information About the APO Plans.”
In 2008, the Compensation Committee authorized the formation of the APO Reward Plan to reward eligible executive officers, key employees and consultants for continued quality service to the Company, and to encourage retention of those employees and service providers by providing them the opportunity to receive bonus payments that are based on certain profits derived from a portion of the Company’s working interest in specified areas where the Company is conducting drilling and production enhancement operations. Since 2010, the APO Reward Plan has been the Company’s principal vehicle for providing new long-term incentive compensation awards to the Company’s executives.
The wells subject to the APO Reward Plan are mutually exclusive from any wells subject to a participation agreement created under the APO Incentive Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan pursuant to which the Company pays participants a bonus equal to a portion of APO cash flows received by the Company pursuant to its working interest. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the APO Reward Plan, increasing the retention value of the APO Reward Plan to the Company. Participants are entitled to receive distributions with respect to awards under the APO Reward Plan from and after the date of grant; however, in the event a participant terminates employment with the Company prior to the vesting date, the award will be forfeited to the Company and the participant will not be entitled to participate in future distributions.
In 2016, no awards were granted under the APO Reward Plan. A detailed description of all awards made under the APO Reward Plan, historically, and amounts paid to the named executive officers in 2016 pursuant to APO Reward Plan awards can be found under “- Summary Compensation Table,” “- Narrative Disclosure to Summary Compensation Table” and “- Supplemental Information About the APO Plans.”
APO Working Interest Grant
In May 2003, the Compensation Committee approved the grant of 5% of the Company’s after-Payout working interests in certain acreage in New Mexico to key employees, other than Mr. Williams, who contributed to the success of that project. In connection with the grant, the participants received a cash payment equal to the net revenues attributable to the distributed interests from the date Payout status was achieved (May 2002) through June 2003, and received an assignment of their proportionate share
of the working interests in the acreage effective July 1, 2003. The working interests conveyed were and are fully vested and non-forfeitable. All net revenues, consisting of oil and gas sales, net of production taxes and other expenses, attributable to the distributed interests are paid to the participants in proportion to each participant’s ownership interest in the grant. Messrs. Riggs and Pollard received payments in 2016 from the APO Working Interest Grant as described in the footnotes under “- Summary Compensation Table.”
APO Working Interest Trusts
In 2001, prior to adopting the current structure of the APO Incentive Plan, the Compensation Committee approved the creation of six trusts through which the Company’s executive officers and key employees, excluding Mr. Williams, received after-Payout working interests in wells drilled by the Company. These trusts were structured so that the participants were beneficiaries of the assigned working interest once Payout was achieved. The working interests conveyed were and are fully vested and non-forfeitable. Upon dissolution, each trust distributed to the beneficiaries a fractional direct ownership in the working interests held by the trust. Two of the trusts achieved Payout status and have been dissolved. Four of the trusts did not achieve Payout status and have been dissolved, with the working interests being reassigned to the Company. Messrs. Riggs, Pollard and Lyssy received payments in 2016 from the APO Working Interest Trusts as described in the footnotes under “- Summary Compensation Table.”
Other Compensation
The Company’s executive officers also participate in the employee benefit programs that are provided to its full-time employees generally, including its group health plan, group life insurance program, and its 401(k) Plan & Trust, which provides for matching contributions equal to 100% of participant deferrals up to 6% of compensation for purposes of the plan. In addition, certain of the Company’s executive officers receive a monthly automobile allowance and the Company pays various club membership dues and personal expenses on behalf of certain executive officers.
The named executive officers and other management employees are provided use of charter aircraft for business purposes. From time to time, a portion of a business trip will constitute “commuting” with respect to an executive officer. This portion of the business trip is treated as “personal use” of the aircraft by the Company and the taxable value of such use is imputed as income to the named executive officer. The personal use of charter aircraft is measured by the incremental cost to the Company based on the personal portion of flight hours associated with any charter flight that is predominately used for a business purpose. Incremental costs include aggregate variable (rather than fixed) costs associated with the personal portion of the flight hours, including fuel costs, landing fees, catering charges, pilot overnight expenses and other similar charges incurred by the Company. Generally, the Company does not provide any officer with the use of charter aircraft for trips that are not primarily related to Company business.
Employment Agreements
The Company has entered into employment agreements with certain of its senior executives, including each of the named executive officers. The employment agreements are effective for an initial term of three years, and will be automatically extended for an additional one year period on the third anniversary date of the effective date of the agreement (and on the fourth and fifth anniversary dates of the effective date), unless, at least 90 days prior to any such anniversary date, either party gives notice of non-renewal.
The employment agreements grant specified benefits to the executives upon certain changes in their employment status and in the event of a change in control. The agreements also provide that the executives will maintain confidentiality of non-public and proprietary information of the Company and, except for Mr. Williams, will not compete with the Company for a period of one year after a termination for which benefits are received. Mr. Williams’ covenants regarding competition with the Company are governed by a pre-existing agreement described in more detail under “- Potential Payments Upon Termination or Change in Control.”
In 2016, the employment agreements were amended and restated to extend the term of the agreements and to make certain other immaterial amendments. As amended and restated, the employment agreements have a three-year term and an annual one-year evergreen provision providing for automatic extensions of up to three years (for a total of six years).
The Compensation Committee believes that it is in the Company’s best interests as well as the best interests of its shareholders to offer such benefits to these senior executives. The Company competes for executive talent in a highly competitive market in which peers routinely offer similar benefits to senior executives. The Compensation Committee believes that providing change of employment and change in control benefits to senior executives eliminates, or at least reduces, any reluctance of senior management to pursue potential change in control transactions that may be in the best interests of shareholders. In addition, the
income security provided by the competitive change in control arrangements helps eliminate any distraction caused by uncertain personal financial circumstances during the negotiations of a potential change in control transaction, a period during which the Company will require focused and thoughtful leadership to ensure a successful outcome.
Deductibility of Executive Compensation
Section 162(m) of the Tax Code places a limit of $1,000,000 on the amount of compensation the Company may deduct for federal income tax purposes in any one year with respect to the Company’s Chief Executive Officer and the next three most highly compensated officers (other than the Chief Financial Officer). However, performance-based compensation that meets certain requirements is excluded from this $1,000,000 limitation.
In reviewing the effectiveness of the executive compensation program, the Compensation Committee considers the anticipated tax treatment to the Company and to the named executive officers of various payments and benefits. However, the deductibility of certain compensation payments depends upon the timing of payments under long-term incentive awards, as well as interpretations and changes in the tax laws and other factors beyond the Compensation Committee’s control. For these and other reasons, including to maintain flexibility in compensating the named executive officers in a manner designed to promote varying corporate goals, the Committee will not necessarily, or in all circumstances, limit executive compensation to that which is deductible under Section 162(m) of the Tax Code and has not adopted a policy requiring all compensation to be deductible. In addition, base salaries, bonuses and the long-term incentives currently paid to the Company’s named executive officers do not comply with the performance-based compensation exclusion under Section 162(m) of the Tax Code and are subject to the $1,000,000 limitation on deductibility.
The Compensation Committee will consider various alternatives to preserving the deductibility of compensation payments and benefits to the extent reasonably practicable and to the extent consistent with its other compensation objectives.
Compensation Committee Report
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.
COMPENSATION COMMITTEE
P. Scott Martin, Chairman
Davis L. Ford
Jordan R. Smith
Summary Compensation Table
The following table summarizes, with respect to the named executive officers, information relating to the compensation earned for services rendered in all capacities during fiscal years 2016, 2015 and 2014. Column (h) has been deleted from the SEC-prescribed tabular format because the Company does not sponsor a pension plan.
SUMMARY COMPENSATION TABLE
(a)
Reflects the aggregate grant date fair value of restricted stock awarded under the Company’s LTIP, which was computed in accordance with Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) Topic 718 without regard to forfeitures. Please see Note 11 to our consolidated financial statements on this Annual Report on Form 10-K for the year ended December 31, 2016, for a discussion of the assumptions used in determining the grant date fair value of these awards. Shares will vest ratably over three years in equal installments on the first, second and third anniversaries of the date of grant. Mr. Pollard’s shares became fully vested upon his resignation as of October 1, 2016. See the Grants of Plan-Based Awards table for information on restricted stock awarded in 2016.
(b)
Reflects the aggregate grant date fair value of stock options granted under the Company’s LTIP, which was computed in accordance with FASB ASC Topic 718 without regard to forfeitures. Options represent the right to purchase shares of common stock at a price per share equal to fair market value on the date of grant. Please see Note 11 to our consolidated financial statements on this Annual Report on Form 10-K for the year ended December 31, 2016, for a discussion of the assumptions used in determining the grant date fair value of these awards. Options will vest ratably over three years in equal installments on the first, second and third anniversaries of the date of grant. Vesting of these options is not contingent upon the satisfaction of any performance goals, although none of the options may be exercised before the first anniversary or after the tenth anniversary of the date of grant. See the Grants of Plan-Based Awards table for information on stock options granted in 2016.
(c)
Amounts shown as Non-Equity Incentive Plan Compensation in the Summary Compensation Table for 2016 include compensation derived from various non-equity awards described under “- Compensation Discussion and Analysis - Long-Term Incentive Compensation” and, in the case of Mr. Lyssy, payments from overriding royalty interests and selected working interests granted prior to the Company’s initial public offering in 1993 (identified in the table below as “Other”). See “- Supplemental Information About the APO Plans” and “- Pension Benefits and Nonqualified Deferred Compensation” below for additional information. Following is a summary of amounts earned in 2016 by source:
(d)
This column includes compensation derived from, among other things, Company contributions to the Company’s 401(k) plan and executive perquisites consisting of an auto allowance, social club dues and personal use of charter aircraft. For more information on this compensation, see “- All Other Compensation from Summary Compensation Table” and “- Perquisites and Other Personal Benefits” below.
Narrative Disclosure to Summary Compensation Table
As a percentage of Mr. Williams’ total compensation for the year ended December 31, 2016, his base salary accounted for 38%, his incentive compensation (including discretionary bonuses) accounted for 60% and all other forms of compensation accounted for 2%.
Components of compensation as a percentage of total compensation (base salary, incentive compensation and other, respectively) for all other named executive officers for 2016 were: Mr. Riggs - 5%, 95% and 0%; Mr. Cooke - 1%, 99% and 0%; Mr. Pollard - 16%, 83% and 1%; Mr. Casas - 1%, 99% and 0%; and Mr. Lyssy - 11%, 88% and 1%.
Supplemental Information About the APO Plans
The following table sets forth certain information regarding all active APO Plans as of December 31, 2016.
(a)
Ownership interests in participation agreements, which are usually stated in percentages, have been converted to equivalent units on the basis of 1% equals 1 unit.
The following table sets forth the number of units awarded under each active APO Plan as of December 31, 2016. Each unit represents 1% of the working interest assigned with respect to each plan.
(a)
Under the terms of the APO Incentive Plan, units are fully vested when awarded.
(b)
All APO Reward Plans were fully vested as of December 31, 2016.
The following table sets forth estimated future payouts to named executive officers under the APO Plans, as well as other non-equity award plans.
(a)
Estimated future payouts have been computed based on the future net revenues from proved oil and gas reserves attributable to interests held by the named executive officers at December 31, 2016. These reserve estimates were made using guidelines established by the SEC, except that the Company used monthly futures contract prices, as quoted on the New York Mercantile Exchange (“NYMEX”) on December 31, 2016, as benchmark prices for 2017 through 2021, and escalated prices at 3% per year for all subsequent years beginning 2022 and the resulting cash flows are undiscounted. These benchmark prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in weighted average adjusted prices of $57.69 per barrel of oil, $21.32 per barrel of NGL and $3.33 per Mcf of natural gas over the remaining life of the proved reserves. The Company escalated operating costs at 3% per year beginning 2018. Because of the uncertainties inherent in estimating quantities of proved reserves and future product prices and costs, it is not possible to predict estimated future payouts with any degree of certainty.
All Other Compensation from Summary Compensation Table
The following table contains a breakdown of the compensation and benefits included under the “All Other Compensation” column in the Summary Compensation Table for 2016.
ALL OTHER COMPENSATION
(a)
See “- Perquisites and Other Personal Benefits” below for further detail on these amounts.
(b)
Constitutes a matching contribution equal to 100% of a participant’s deferrals up to 6% of the participant’s compensation for purposes of the Company’s 401(k) plan.
(c)
Related to consulting services provided during 2016.
Perquisites and Other Personal Benefits
The following table contains a breakdown of the perquisites and other personal benefits included in the “All Other Compensation” supplemental table above for 2016.
PERQUISITES AND OTHER PERSONAL BENEFITS
Grants of Plan-Based Awards
The following table provides information regarding grants of plan-based awards made to the Company’s named executive officers during 2016.
2016 GRANTS OF PLAN-BASED AWARDS
(a)
Shares will vest ratably over three years in equal installments on the first, second and third anniversaries of the date of grant. Mr. Pollard’s shares became fully vested upon his resignation as of October 1, 2016.
Outstanding Equity Awards at Fiscal Year-End, Option Exercises and Stock Vested
The following table provides information with respect to restricted stock and stock options held by each of the Company’s named executive officers as of December 31, 2016.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
(a)
Shares will vest ratably over three years in equal installments on the first, second and third anniversaries of the date of grant.
(b)
Market value based on December 31, 2016 closing price of $119.26.
Stock Vested
The following table provides information concerning each restricted stock vested during 2016 on an aggregated basis with respect to each of the Company’s named executive officers.
(a)
Calculated by multiplying the closing price of the Company’s common stock on the vesting date of October 1, 2016 ($85.44) by the number of shares vesting on such date. Mr. Pollard’s shares became fully vested upon his resignation as of October 1, 2016.
Pension Benefits and Nonqualified Deferred Compensation
The Company does not sponsor or maintain either a defined benefit pension plan or a traditional nonqualified deferred compensation plan for the benefit of the Company’s employees.
Potential Payments Upon Termination or Change in Control
The Company has entered into employment agreements with each of the named executive officers. Under the agreements, the Company is required to provide compensation to these officers in the event the executive’s employment is terminated under certain circumstances. The agreements provide the named executive officers with minimum base salaries and certain other compensation and benefits. Under the agreements, the minimum base salary of each named executive officer is automatically increased by the amount of any increases in base salary approved by the Compensation Committee. The current employment agreements are effective for an initial term of three years, and will be automatically extended for an additional one year period on the third anniversary date of the effective date of the agreement (and on the fourth and fifth anniversary dates of the effective date), unless, at least 90 days prior to any such anniversary date, either party gives notice of non-renewal.
If a named executive officer becomes disabled or dies, the agreements provide for a lump sum payment of 18 months of base salary, payable within 90 days of termination or by March 15 of the year following termination, if earlier, and 12 months of continued health benefits. If a named executive officer’s employment is terminated by the Company without cause or by the executive for good reason, or if the Company gives a notice of non-renewal to the executive, the executive will receive a lump sum payment equal to either 200% (for Messrs. Williams, Riggs, Cooke and Casas) or 150% (for Mr. Lyssy) of his annualized compensation, consisting of base salary, average bonus for the most recent three years, automobile allowance, and 401(k) matching
contributions, payable within 90 days of termination or by March 15 of the year following termination, if earlier, plus 18 months of continued health benefits. If a named executive officer’s employment is terminated by the Company without cause or by the executive for good reason, or if the Company gives notice of non-renewal to the executive, in each case, within 24 months from a change in control, the executive will receive a lump sum payment equal to either 300% (for Messrs. Williams, Riggs, Cooke and Casas) or 200% (for Mr. Lyssy) of his annualized compensation, consisting of base salary, average bonus for the most recent three years, automobile allowance, and 401(k) matching contributions, payable within 90 days of termination or by March 15 of the year following termination, if earlier, plus 18 months of continued health benefits. The named executive officers are also entitled to accelerated vesting of all non-equity incentive awards (except that awards under the APO Incentive Plan are still subject to forfeiture in the event of fraud against the Company by a participant) if they are terminated due to death or disability, or by the Company without cause, by the executive for good reason, or pursuant to a non-renewal notice given by the Company (including such a termination occurring within 24 months of a change in control). In addition, upon such termination events, equity awards will become vested with respect to an additional 12 months unless such termination occurs within 24 months of a change in control in which case, with respect to Messrs. Riggs, Cooke and Casas, equity awards will become vested with respect to an additional 24 months.
For purposes of the employment agreements, the terms listed below have been given the following meanings:
(a) “cause” means the executive (1) has been convicted of a misdemeanor involving intentionally dishonest behavior or that the Company determines will have a material adverse effect on the Company’s reputation or any felony, (2) has engaged in conduct that is materially injurious to the Company or its affiliates, (3) has engaged in gross negligence or willful misconduct in performing his duties, (4) has willfully refused without proper legal reason to perform his duties, (5) has breached a material provision of the employment agreement or another agreement with the Company, or (6) has breached a material corporate policy of the Company. If any act described in clause (4), (5) or (6) could be cured, the Company will give the executive written notice of such act and will give the executive 10 days to cure.
(b) “change in control” encompasses certain events including (1) a change in the majority of the board of directors serving on the board as of July 20, 2005 unless such change was authorized by a majority of the directors in place on that date (or approved by the majority of the directors in place on that date), (2) a third party, including a group of third parties acting together, acquires more than 35%, and Mr. Williams, his affiliates and certain other related persons own less than 25%, of the total voting power of Company’s voting stock, (3) the sale of all or substantially all of the Company’s assets, and (4) the adoption of a plan or a proposal for the liquidation or dissolution of the Company. Except in the case of Mr. Williams’ employment agreement, “change in control” also includes the resignation or removal for any reason of Mr. Williams as the Company’s Chairman of the Board and Chief Executive Officer, including by reason of the death or disability of Mr. Williams.
(c) “disability” means disability (as defined in a long-term disability plan sponsored by the Company) for purposes of determining a participant’s eligibility for benefits and, if multiple definitions exist, will refer to the definition of disability that would, if the participant so qualified, provide coverage for the longest period of time. If the executive is not covered by a long-term disability plan sponsored by the Company, “disability” will mean a “permanent and total disability” as defined in Section 22(e)(3) of the Internal Revenue Code, as certified by a physician acceptable to both the Company and the executive.
(d) “good reason” means, without the express written consent of the executive, (1) a material breach by the Company of the employment agreement, (2) a material reduction in the executive’s base salary, (3) a material diminution in the executive’s authority, duties or responsibilities or the assignment of duties to the executive that are not materially commensurate with the executive’s position, or (4) a material change in the geographic location at which the executive must normally perform services. The executive must give the Company notice of any alleged good reason event within 60 days and the Company shall have 30 days to remedy such event.
The employment agreements contain confidentiality provisions, as well as covenants not to compete, during the employment term and continuing until the first anniversary of the date of termination, and not to solicit, during the employment term and continuing until the second anniversary of the date of termination, subject to some limited exceptions. The non-competition covenant does not apply if an executive is terminated for cause by the Company or voluntarily without good reason by the executive, unless the Company continues to pay the executive his base salary for a period of 12 months. Mr. Williams’ non-competition and non-solicitation obligations are governed by the Consolidation Agreement entered into with Mr. Williams and certain Williams Entities in May 1993. Termination of any of the named executive officers’ employment due to a breach of one of these provisions would constitute a termination for cause. The employment agreements do not prohibit the waiver of a breach of these covenants. In addition, the employment agreements also condition payment of severance payments and health care continuation coverage upon the named executive officer’s execution of a release within forty-five days of termination of employment (and nonrevocation thereafter).
In connection with Mr. Pollard’s separation from employment on October 1, 2016, he was granted a lump sum severance payment in 2017 of $1,300,977, his 25,000 outstanding shares of restricted stock became vested and he became eligible to continue participation in the Company’s group health plan on the same terms and conditions as active employees for a period of 18 months following his resignation. The value of his restricted stock (determined by multiplying the closing price of the Company’s stock on October 1, 2016 by the 25,000 shares vesting) was $2,136,000. The value of Mr. Pollard’s group health plan continuation coverage (determined by multiplying by 18 the monthly group health plan premium subsidy provided by the Company to active employees with the same coverage elections as Mr. Pollard) was $4,680. Mr. Pollard also agreed to provide transitional consulting services to the Company for a period of six months following his resignation. For services provided prior to November 1, 2016, Mr. Pollard was compensated at an hourly rate of $200. For services performed on and after November 1, 2016, Mr. Pollard was and will be compensated at an hourly rate of $250.
The following table quantifies compensation and/or other benefits that would become payable under the employment agreements and other arrangements if the employment of each named executive officer had terminated on December 31, 2016, and/or in the event the Company were to undergo a change in control on December 31, 2016. Due to the number of factors that affect the amount of any benefits provided upon the events discussed below, actual amounts paid or distributed may be different.
(a)
Represents an amount equal to the monthly premium payable pursuant to the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (i.e., COBRA) for group health plan continuation multiplied by (a) twelve (in the event of a termination due to death or disability) or (b) eighteen (in the event of a termination by the Company without cause, by the executive for good reason, due to non-renewal by the Company, or associated with a change in control).
(b)
Vesting of restricted stock and stock options accelerates for each of the named executive officers as stated above. All outstanding unvested restricted stock and stock options that would be subject to accelerated vesting were valued based on the Company’s closing stock price of $119.26 on December 31, 2016.
Securities Authorized for Issuance under Equity Compensation Plans
In June 2016, shareholders approved the Clayton Williams Energy, Inc. LTIP, which was adopted by the Compensation Committee of the Board in April 2016. The LTIP was adopted in order to enable us to attract and retain highly qualified employees, directors and consultants and to provide equity-based compensation to those individuals that will align their interests with the interests of our shareholders. The LTIP provides for the granting of restricted stock awards, restricted stock units, stock options, stock appreciation rights, dividend-equivalent awards, other stock-based awards, cash awards, performance awards, and any combination of such awards. A total of 1,400,000 shares of our common stock have been reserved for issuance under the LTIP and are expected to consist of new shares of the Company. During the year ended December 31, 2016, grants of option awards under the LTIP were made as disclosed in the table below.
(a)
The securities listed do not include restricted stock awarded under the Company’s LTIP.
NARRATIVE DISCLOSURE OF COMPENSATION POLICIES AND PRACTICES AS THEY RELATE TO RISK MANAGEMENT
In accordance with the requirements of Regulation S-K, Item 402(s), to the extent that risks may arise from the Company’s compensation policies and practices that are reasonably likely to have a material adverse effect on the Company, we are required to discuss those policies and practices for compensating the employees of the Company (including employees that are not named executive officers) as they relate to the Company’s risk management practices and the possibility of incentivizing risk-taking. The Company has determined that the compensation policies and practices established with respect to the Company’s employees are not reasonably likely to have a material adverse effect on the Company and, therefore, no such disclosure is necessary. The Compensation Committee and the Board are aware of the need to routinely assess the Company’s compensation policies and practices and will make a determination as to the necessity of this particular disclosure on an annual basis.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth certain information regarding the beneficial ownership of the Company’s common stock based upon 17,629,338 shares outstanding as of February 23, 2017, by:
•
Each person who is the beneficial owner of 5% or more of the outstanding common stock (based upon copies of all Schedule 13Gs, Schedule 13Ds and, if applicable, Form 4s and Form 5s provided to the Company);
•
Each director of the Company and each nominee for director;
•
The named executive officers; and
•
All officers and directors of the Company as a group.
Beneficial ownership is determined in accordance with the regulations of the SEC. Under SEC regulations, persons who have power to vote or dispose of shares of common stock, either alone or jointly with others, are deemed to be beneficial owners. Because the voting or dispositive power of certain shares listed in the following table is shared, the same securities in such cases are listed opposite more than one name in the table and the sharing of voting or dispositive power is described in the referenced footnote. The total number of shares of common stock of the Company listed below for directors and executive officers as a group eliminates such duplication. Unless otherwise noted, the persons and entities named below have sole voting and investment power with respect to the shares listed opposite each of their names and their address is Clayton Williams Energy, Inc., 6 Desta Drive, Suite 6500, Midland, Texas 79705.
*
Less than 1 percent of the shares outstanding.
(a)
The mailing address of The Williams Children’s Partnership, Ltd. and Mr. Williams is 6 Desta Drive, Suite 3000, Midland, Texas 79705. The Williams Children’s Partnership, Ltd. is a family partnership comprised of Mr. Williams’ five adult children.
(b)
Consists of (a) an aggregate of 1,247,488 shares owned by CWPLCO, Inc. and beneficially owned by Mr. Williams due to Mr. Williams’ control of CWPLCO, Inc., (b) 1,771,219 shares owned by CW Stock Holdco, L.P. and beneficially owned by Mr. Williams due to Mr. Williams’ control of CW Stock Holdco, L.P., (c) 11,044 shares owned by Mr. Williams’ wife, (d) 588 shares owned by a trust of which Mrs. Williams is the trustee, (e) 17,839 shares held in the Company’s 401(k) Plan & Trust over which Mr. Williams exercises investment control, (f) 49,179 shares in trusts of which Mr. Williams is the Trustee, (g) 5,749 shares in a trust for the benefit of Mr. Williams of which Mrs. Williams is the Trustee, and (h) 7,421 shares owned by Mr. Williams’ grandchildren for which Mrs. Williams is custodian.
(c)
Includes (a) 3,655 shares held in the Company’s 401(k) Plan & Trust over which Mr. Riggs exercises investment control, (b) 1,382 shares over which Mr. Riggs exercises control under a Power of Attorney, (c) 3,041,412 shares owned by The Williams Children’s Partnership, Ltd. over which Mr. Riggs exercises investment control, and (d) 100,000 shares of restricted stock. Mr. Riggs is the sole member of LPL/Williams GP, LLC, which is the general partner of The Williams Children’s Partnership, Ltd. Mr. Riggs has a pecuniary interest in only 0.002% of the stock held by The Williams Children’s Partnership, Ltd. and disclaims beneficial ownership of the remaining 99.998% of the stock.
(d)
Includes warrants currently exercisable for an aggregate of 2,251,364 shares. According to an Amendment to Schedule 13D and a Form 4 filed with the SEC on January 17, 2017, Ares Management, LLC has sole voting power with regard to zero shares, shared voting power with regard to 8,344,869 shares, sole dispositive power with regard to zero shares, and shared dispositive power with regard to 8,344,869 shares.
(e)
Consists of 21 shares held in the Company’s 401(k) Plan & Trust over which Mr. Cooke exercises investment control and 65,000 shares of restricted stock.
(f)
Consists of 44 shares held in the Company’s 401(k) Plan & Trust over which Mr. Casas exercises investment control and 65,000 shares of restricted stock.
(g)
Consists of 25 shares held in the Company’s 401(k) Plan & Trust over which Mr. Lyssy exercises investment control and 30,000 shares of restricted stock.
(h)
Consists of 2,368 shares held in the Company’s 401(k) Plan & Trust over which Mr. Pollard exercises investment control and 19,000 shares of restricted stock.
Item 13
Item 13 - Certain Relationships and Related Transactions, and Director Independence
The Audit Committee reviews, approves and monitors all transactions involving the Company and “related persons” (directors and executive officers or their immediate family members, or shareholders owning 5% or greater of the Company’s outstanding stock) in which the amount exceeds $120,000 and in which the related person has a direct or indirect material interest. The Audit Committee will approve the transaction only if they determine that it is in the best interest of the Company. While the Audit Committee has not adopted a formal written policy for reviewing related party transactions, in considering the transaction, the Audit Committee will consider all relevant factors, including as applicable:
•
The Company’s business rationale for entering into the transaction;
•
The alternatives to entering into a related party transaction;
•
Whether the transaction is on terms comparable to those available to third parties;
•
The potential for the transaction to lead to an actual or apparent conflict of interest and any safeguards imposed to prevent such actual or apparent conflicts; and
•
The overall fairness of the transaction to the Company.
The Audit Committee will periodically monitor the transaction to ensure that there are no changed circumstances that would render it advisable for the Company to amend or terminate the transaction.
In the event a transaction arises that would require the review of the Audit Committee, management or the affected director or executive officer will bring the matter to the attention of the Chairman of the Audit Committee. If a member of the Audit Committee is involved in the transaction, he will be recused from all discussions and decisions about the transaction. Any such transaction must be approved in advance wherever practicable, and if not practicable, it must be ratified as promptly as practicable. The Audit Committee will review the transactions annually to determine whether they continue to be in the Company’s best interest.
In 2016, we entered into two significant transactions with Ares, which currently beneficially owns 42.0% of our common stock and possesses the right to elect up to two members of our Board and to recommend one other director to the Nominating and Governance Committee for appointment to the Board. In March 2016, we entered into a refinancing transaction with Ares, pursuant to which we issued term loans to Ares in the principal amount of $350 million, net of original issue discount of $16.8 million, for cash proceeds of $333.2 million (the “Refinancing”). Concurrently, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share to Ares for cash proceeds equal to the original issue discount from the issuance on the term loans. In connection with the issuance of the warrants, we designated and issued to funds managed by Ares, as the initial warrant holders, 3,500 shares of special voting preferred stock, granting them certain rights to elect two members of our Board. In addition, in July 2016, we sold 5,051,100 shares of common stock to funds managed by Ares for cash proceeds of $150 million, or approximately $29.70 per share. In connection with the sale, we granted Ares the right to recommend one director nominee to the Nominating and Governance Committee for appointment to the Board. For more information on our transactions with Ares, see “Item 1 - Business - Recent Developments - Ares Transactions.”
Mr. Clayton W. Williams, Jr., the Company’s Chairman of the Board and Chief Executive Officer, is also the Chief Executive Officer and a director of the Williams Entities, which Mr. Williams directly or indirectly controls. The Company and the Williams Entities are parties to an agreement, which the Company refers to as the Service Agreement, pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, the Company provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services and general accounting services to the Williams Entities, as well as technical services with respect to the operation of certain oil and gas properties owned by the Williams Entities. The Williams Entities provide business entertainment to or for the benefit of the Company.
The following table summarizes the charges to and from the Williams Entities for the year ended December 31, 2016.
(a)
Rent amounts were paid to ClayDesta Buildings, L.P., a Texas limited partnership referred to as CDBLP, of which the Company owns 33.5% and affiliates of the Company own 25.8%. A Williams Entity provides property management services to the buildings owned and operated by CDBLP.
(b)
Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams.
Certain of the Company’s employees and vendors are “immediate family members” (as defined under SEC regulations) of Mr. Clayton W. Williams, Jr., Chairman of the Board and Chief Executive Officer. As a result, compensation paid to such employees may be deemed to be transactions by the Company with a related person. Following is a summary of each relationship and transaction or series of similar transactions for which the amount involved exceeded $120,000 for the year ended December 31, 2016. No other immediate family members of Mr. Williams received compensation in excess of $120,000 for the year ended December, 31, 2016, except the following.
•
Gregory S. Welborn serves as Vice President - Land for the Company and is the son-in-law of Mr. Williams. For the year ended December 31, 2016, Gregory S. Welborn received compensation from the Company aggregating $1.97 million which included $1.4 million of compensation related to the grant date fair value of restricted stock and stock options.
Item 14
Item 14 - Principal Accounting Fees and Services
Audit Fees
KPMG LLP audited the effectiveness of the Company’s internal control over financial reporting and the consolidated financial statements of the Company for the years ended December 31, 2016 and 2015 and reviewed the consolidated financial statements for the interim quarters during 2016 and 2015. For these services, the Company paid KPMG LLP fees totaling $900,000 for 2016 and $966,000 for 2015. In addition, the Company paid KPMG LLP $9,000 in 2016 for other professional services rendered in connection with a registration statement filed on Form S-8.
Audit-Related Fees
KPMG LLP did not provide any audit-related services to the Company in 2016 or 2015.
Tax Fees
KPMG LLP did not provide any tax compliance services to the Company in 2016 or 2015.
All Other Fees
KPMG LLP did not provide any other services to the Company in 2016 or 2015.
Pre-Approval Policy and Procedures
The Audit Committee must give prior approval to any management request for any amount or type of service (audit, audit-related and tax services or, to the extent permitted by law, non-audit services) the Company’s independent auditor provides. All audit, audit-related and tax services rendered by KPMG LLP in 2016 were approved by the Audit Committee before KPMG LLP was engaged for such services. No services of any kind were approved pursuant to a waiver permitted pursuant to 17 CFR 210.2-01(c)(7)(i)(C) (Rule 2-01(c)(7)(i)(C) of Regulation S-X). Review and approval of such services for 2016 occurred during the regularly scheduled meetings of the Audit Committee.
PART IV
Item 15
Item 15 - Exhibits, Financial Statement Schedules
Financial Statements and Schedules
For a list of the consolidated financial statements and financial statement schedules filed as part of this Form 10-K, see the Index to Consolidated Financial Statements on page.
Exhibits
The following exhibits are filed as a part of this Form 10-K, with each exhibit that consists of or includes a management contract or compensatory plan or arrangement being identified with a “†”:
*
Filed herewith.
**
Incorporated by reference to the filing indicated.
***
Furnished herewith.
†
Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.
††
Filed under the Company’s Commission File No. 001-10924.
GLOSSARY OF TERMS
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this Form 10-K.
3-D seismic. An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.
BOE. One barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.
Bbl. One barrel, or 42 U.S. gallons of liquid volume.
Bcf. One billion cubic feet.
Btu. One British thermal unit. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or gas.
Credit facility. A line of credit provided by a group of banks, secured by oil and gas properties.
DD&A. Depreciation, depletion and amortization of the Company’s property and equipment.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.
Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the cost of the operation.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.
Gross acres or wells. The total acres or wells in which the Company has a working interest.
Horizontal drilling. A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons.
LIBOR. London Interbank Offered Rate.
MBbls. One thousand barrels.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet.
MMbtu. One million British thermal units.
MMBbls. One million barrels.
MMBOE. One million barrels of oil equivalent.
MMcf. One million cubic feet.
Natural gas liquids. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.
Net acres or wells. The sum of fractional ownership working interests in gross acres or wells.
Net production. Oil and gas production that is owned by the Company, less royalties and production due others.
NYMEX. New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded.
Oil. Crude oil or condensate.
Operator. The individual or company responsible for the exploration, development and production of an oil or gas well or lease.
Present value of proved reserves (“PV-10”). The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, debt service and future income tax expense, or (ii) depreciation, depletion and amortization.
Productive wells. Producing wells and wells mechanically capable of production.
Proved Developed Reserves. Proved reserves that can be expected to be recovered (i) 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 (ii) 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 reserves. Those quantities of oil and gas, 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. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved undeveloped reserves (PUD). 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. (i) Reserves on undrilled acreage shall be 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. (ii) 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. (iii) Under no circumstances shall estimates for undeveloped reserves 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.
Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Standardized measure of discounted future net cash flows. Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) estimated future income taxes.
Undeveloped acreage. Leased acreage on which wells have not been drilled or completed in a particular formation to a point that would permit the production of economic quantities of oil or gas, regardless of whether such acreage contains proved reserves.
Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.
Workover. Operations on a producing well to restore or increase production.
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.
CLAYTON WILLIAMS ENERGY, INC.
(Registrant)
By:
/s/ CLAYTON W. WILLIAMS, JR.
Clayton W. Williams, Jr.
Chairman of the Board and
Chief Executive Officer
Date:
March 2, 2017
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 and in the capacities and on the dates indicated.
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTAL INFORMATION
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations and Comprehensive Income (Loss)
Consolidated Statements of Shareholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Supplemental Information
Supplemental Quarterly Financial Data
S-1
Supplemental Oil and Gas Reserve Information
S-2
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
The Board of Directors and Shareholders
Clayton Williams Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Clayton Williams Energy, Inc. and subsidiaries (the Company) as of December 31, 2016 and 2015, and the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Clayton Williams Energy, Inc. and subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Clayton Williams Energy, Inc.’s internal control over financial reporting as of December 31, 2016, based on criteria established in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2017, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Dallas, Texas
March 2, 2017
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Nature of Operations
Clayton Williams Energy, Inc., a Delaware corporation, is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in its core area in Southern Reeves County, Texas. Unless the context otherwise requires, references to “CWEI” mean Clayton Williams Energy, Inc., the parent company, and references to “the Company,” “we,” “us” or “our” mean Clayton Williams Energy, Inc. and its consolidated subsidiaries. Approximately 17.6% of CWEI’s outstanding common stock is beneficially owned by Clayton W. Williams, Jr. (“Mr. Williams”), Chairman of the Board and Chief Executive Officer of the Company, and approximately 17.3% is owned by a partnership in which Mr. Williams’ adult children are limited partners, and Mel G. Riggs, our President, is the sole member in the general partner.
Ares Management, LLC (“Ares”) beneficially owns, either individually or through its affiliates, 42.0% of the outstanding shares of our common stock. In addition, Ares possesses the right to elect up to two members of our Board and to recommend one other director to the Nominating and Governance Committee of the Board for appointment to the Board. Through its elected and recommended Board members and substantial ownership of our common stock, Ares has significant influence in matters voted on by our shareholders, including the election of our Board members.
Substantially all of our oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, our results of operations and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global supply and demand for oil and natural gas, market uncertainties, weather conditions, domestic governmental regulations and taxes, political and economic conditions in oil producing countries, price and availability of alternative fuels and overall domestic and foreign economic conditions.
2. Summary of Significant Accounting Policies
Estimates and Assumptions
The preparation of these consolidated financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires our management to make 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 revenues and expenses during the reporting periods. Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:
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Provisions for depreciation, depletion and amortization and estimates of non-equity plans are based on estimates of proved reserves;
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Impairments of long-lived assets are based on estimates of future net cash flows and, when applicable, the estimated fair values of impaired assets;
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Exploration expenses related to impairments of unproved acreage are based on estimates of fair values of the underlying leases;
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Asset retirement obligations (“ARO”) are based on estimates regarding the timing and cost of future asset retirements;
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Valuation of derivative financial instruments are based on the fair value of commodity derivatives;
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Valuation of stock-based compensation is based on the grant date fair value;
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Valuation of common stock warrants are based on their fair value using the Black-Scholes method;
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Impairments of inventory are based on estimates of fair values of tubular goods and other well equipment held in inventory; and
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Exploration expenses related to well abandonment costs are based on the judgments regarding the productive status of in-progress exploratory wells.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Principles of Consolidation
The consolidated financial statements include the accounts of CWEI and its wholly owned subsidiaries. We account for our undivided interests in oil and gas limited partnerships using the proportionate consolidation method. Under this method, we consolidate our proportionate share of assets, liabilities, revenues and expenses of such limited partnerships. Less than 5% of our consolidated total assets and total revenues are derived from oil and gas limited partnerships. Substantially all intercompany transactions and balances associated with the consolidated operations have been eliminated.
Oil and Gas Properties
We follow the successful efforts method of accounting for oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.
Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
Pipelines and Other Midstream Facilities and Other Property and Equipment
Pipelines and other midstream facilities consist of pipelines to transport oil, natural gas and water, natural gas processing facilities and compressors. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while repairs and maintenance are charged to expense as incurred. The cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in operating income (loss) in the accompanying consolidated statements of operations and comprehensive income (loss).
Depreciation of pipelines and other midstream facilities and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which generally range from 3 to 30 years.
Contract Drilling
We conduct contract drilling operations through Desta Drilling, L.P. (“Desta Drilling”), a wholly owned subsidiary of CWEI. Desta Drilling recognizes revenues and expenses from daywork drilling contracts as the work is performed, but defers revenues and expenses from footage or turnkey contracts until the well is substantially completed or until a loss, if any, on a contract is determinable.
Property and equipment, including buildings, major replacements, improvements and capitalized interest on construction-in-progress, are capitalized and are depreciated using the straight-line method over estimated useful lives of 3 to 40 years. Upon disposition, the costs and related accumulated depreciation of assets are eliminated from the accounts and the resulting gain or loss is recognized.
Valuation of Property and Equipment
Our long-lived assets, including proved oil and gas properties and contract drilling equipment, are assessed for potential impairment in their carrying values, based on depletable groupings, whenever events or changes in circumstances indicate such impairment may have occurred. An impairment is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the difference in the carrying value and estimated fair value of the impaired asset.
Unproved oil and gas properties are periodically assessed, and any impairment in value is charged to exploration costs. The amount of impairment recognized on unproved properties which are not individually significant is determined by impairing the
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
costs of such properties within appropriate groups based on our historical experience, acquisition dates and average lease terms. The valuation of unproved properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values.
Asset Retirement Obligations
We recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the asset retirement obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.
Income Taxes
We utilize the asset and liability method to account for income taxes. Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in the consolidated statements of operations and comprehensive income (loss) in the period that includes the enactment date. We also record any financial statement recognition and disclosure requirements for uncertain tax positions taken or expected to be taken in a tax return. Financial statement recognition of the tax position is dependent on an assessment of a 50% or greater likelihood that the tax position will be sustained upon examination, based on the technical merits of the position. Any interest and penalties related to uncertain tax positions are recorded as interest expense.
Hedging Transactions
From time to time, we utilize commodity derivative instruments, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. All of our commodity derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a commodity derivative depends on both the intended purpose and the formal designation of the commodity derivative. Designation is established at the inception of a commodity derivative, but subsequent changes to the designation are permitted. For commodity derivatives designated as cash flow hedges and meeting the effectiveness guidelines under applicable accounting standards, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is measured quarterly based on relative changes in fair value between the commodity derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in fair value of commodity derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines are recorded in earnings as the changes occur. If designated as cash flow hedges, actual gains or losses on settled commodity derivatives are recorded as oil and gas revenues in the period the hedged production is sold, while actual gains or losses on interest rate derivatives are recorded in interest expense for the applicable period. Actual gains or losses from commodity derivatives not designated as cash flow hedges are recorded in other income (expense) as gain (loss) on commodity derivatives.
Stock-Based Compensation
Restricted stock and stock options issued to employees and directors are recorded at grant-date fair value. Stock-based compensation expense is recognized in our consolidated statement of operations and comprehensive income (loss) on an accelerated basis over the awards’ vesting periods based on their fair values on the dates of grant, net of an estimate for forfeitures. Stock-based compensation awards generally vest over a period ranging from one to three years. We utilize the Black-Scholes option pricing model to measure the fair value of stock options.
Common Stock Warrants
Common stock warrant liabilities are measured at fair value on a recurring basis until the underlying common stock warrants are exercised (see Note 3). We measure the fair value of the common stock warrant liabilities using the Black-Scholes method (Level 2 inputs). Inputs used to determine fair value under this method include our price volatility and expected remaining life.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Inventory
Inventory consists primarily of tubular goods and other well equipment which we plan to utilize in our exploration and development activities and is stated at the lower of average cost or estimated market value.
Capitalization of Interest
Interest costs associated with our inventory of unproved oil and gas property lease acquisition costs are capitalized during the periods for which exploration activities are in progress. During the years ended December 31, 2016, 2015 and 2014, we capitalized interest totaling approximately $0.1 million, $0.3 million and $1 million, respectively.
Cash and Cash Equivalents
We consider all cash and highly liquid investments with original maturities of three months or less to be cash equivalents.
Net Income (Loss) Per Common Share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted net income (loss) per share calculations for December 31, 2016, 2015 and 2014 include changes in potential shares attributable to dilutive stock options and restricted stock.
Fair Value Measurements
We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities are as follows:
Level 1 -
Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 -
Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 -
Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
Revenue Recognition and Gas Balancing
We utilize the sales method of accounting for oil, natural gas and natural gas liquids (“NGL”) revenues whereby revenues, net of royalties, are recognized as the production is sold to purchasers. The amount of gas sold may differ from the amount to which we are entitled based on our revenue interests in the properties. We did not have any significant gas imbalance positions at December 31, 2016, 2015 or 2014. Revenues from midstream services and drilling rig services are recognized as services are provided.
Comprehensive Income (Loss)
There were no differences between net income (loss) and comprehensive income (loss) in December 31, 2016, 2015 and 2014.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Concentration Risks
We sell our oil and natural gas production to various customers, serve as operator in the drilling, completion and operation of oil and gas wells, and enter into derivatives with various counterparties. When management deems appropriate, we obtain letters of credit to secure amounts due from our principal oil and gas purchasers and follow other procedures to monitor credit risk from joint owners and derivatives counterparties. Allowances for doubtful accounts at December 31, 2016 and 2015 relate to amounts due from joint interest owners.
Recent Accounting Pronouncements
In August 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. We are currently evaluating the method of adoption and impact this standard may have on our financial statements and related disclosures.
In March 2016, the FASB issued ASU 2016-09, “Compensation - Stock Compensation.” ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Upon adoption, we expect to record a cumulative-effect adjustment to reclassify approximately $7.5 million of excess tax benefits that were not previously recognized because the related tax deduction had not reduced taxes payable. We plan to adopt ASU 2016-09 during the quarter ended March 31, 2017 to be effective as of January 1, 2017.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. We do not plan to early adopt the standard. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space and vehicles. We are currently in the process of reviewing all contracts that could be applicable to this new guidance. We believe this new guidance will have a moderate impact to our consolidated balance sheet due to the recognition of lease-related assets and liabilities that were not previously recognized.
In November 2015, the FASB issued ASU No. 2015-17, “Income Taxes.” This ASU requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. Adoption of the new guidance will affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements.
In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” This ASU requires entities to measure most inventory at the lower of cost and net realizable value, thereby simplifying the current guidance under which an entity must measure inventory at the lower of cost or market. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively, with early adoption permitted. The adoption of this standard will not have a material impact on our consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-03, “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” which requires net debt issuance costs directly related to our senior notes and our second lien term loan to be classified as a direct deduction from the carrying amount of the related senior notes and second lien term loan. We adopted this ASU as of March 31, 2016 and reclassified $7.3 million of debt issuance costs at December 31, 2015 from a non-current asset to a direct deduction in long-term debt. The debt issuance costs related to our revolving credit facility remains classified as a non-current asset due to the revolving nature of that facility.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In August 2014, the FASB issued ASU No. 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Certain disclosures are required should substantial doubt exist. This evaluation is performed each annual and interim reporting period to assess conditions or events within one year after the date that the financial statements are issued. This ASU was effective beginning December 31, 2016; however, no additional disclosures as contemplated by this ASU were warranted.
In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” that outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. In summary, revenue recognition would occur upon the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The standard will be effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. In March 2016, the FASB released certain implementation guidance through ASU 2016-08 to clarify principal versus agent considerations. We are evaluating the guidance to determine the method of adoption and the impact this standard will have on our consolidated financial statements and related disclosures. Based on our initial evaluation, though not currently quantified, the adoption of the standard is not expected to have a material impact on the timing of revenue recognized, results of operations or cash flows.
3. Long-Term Debt
Long-term debt consists of the following:
Revolving Credit Facility
We have a revolving credit facility with a syndicate of 16 banks led by JP Morgan Chase Bank, N.A. On March 8, 2016, we entered into an amendment to the revolving credit facility in connection with the Refinancing (as defined below) (see “- Term Loan Credit Facility”). The amendment, among other things, reduced the borrowing base and aggregate commitments of the lenders from $450 million to $100 million. The aggregate commitments may be increased to $150 million if we meet a minimum ratio of the discounted present value of our proved developed producing reserves to our debt under the revolving credit facility of 1.2 to 1.0. Increases in aggregate lender commitments require the consent of each lender.
The amendment also increased the applicable interest rates under our revolving credit facility by 0.75% at every borrowing base utilization level. At our election, interest under the revolving credit facility is determined by reference to (1) LIBOR plus an applicable margin between 2.5% and 3.5% per year or (2) the greatest of (A) the prime rate, (B) the federal funds rate plus 0.5% or (C) one-month LIBOR plus 1% plus, in any of (A), (B) or (C), an applicable margin between 1.5% and 2.5% per year. We are also required to pay a commitment fee on the unused portion of the commitments under the revolving credit facility of 0.5% per
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
year. The applicable margin is determined based on the utilization of the borrowing base. Interest and fees are payable quarterly, except that interest on LIBOR-based tranches is due at maturity of each tranche but no less frequently than quarterly.
The revolving credit facility also contains various covenants and restrictive provisions that may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain a ratio of consolidated current assets to consolidated current liabilities of at least 1 to 1. The March 2016 amendment replaced a requirement that we maintain certain ratios of consolidated funded indebtedness to consolidated EBITDAX with a less restrictive ratio of debt outstanding solely under the revolving credit facility to consolidated EBITDAX to be less than 2.0 to 1.0.
The revolving credit facility matures in April 2019 and is subject to an accelerated maturity date of October 1, 2018 unless our existing 7.75% Senior Notes due 2019 (the “2019 Senior Notes”) are refinanced or extended in accordance with the terms of the revolving credit facility prior to October 1, 2018.
The borrowing base, which is based on the discounted present value of future net cash flows from oil and gas production, is redetermined by the banks semi-annually in May and November. We or the banks may also request an unscheduled borrowing base redetermination at other times during the year. If, at any time, the borrowing base is less than the amount of outstanding credit exposure under the revolving credit facility, we will be required to (1) provide additional security, (2) prepay the principal amount of the loans in an amount sufficient to eliminate the deficiency, (3) prepay the deficiency in not more than five equal monthly installments plus accrued interest, or (4) take any combination of options (1) through (3).
The revolving credit facility is collateralized by a first lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the revolving credit facility) attributed to our proved oil and gas interests evaluated in determining the borrowing base. The obligations under the revolving credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries.
At December 31, 2016, we had $98.1 million available under the revolving credit facility after allowing for outstanding letters of credit totaling $1.9 million. The effective annual interest rate on borrowings under the revolving credit facility, excluding bank fees and amortization of debt issue costs, for the year ended December 31, 2016 was 2.5%. We were in compliance with all financial and non-financial covenants at December 31, 2016 and December 31, 2015.
The failure to comply with the foregoing covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the revolving credit facility. Other events of default under the revolving credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding.
Term Loan Credit Facility
On March 8, 2016, we entered into the term loan credit facility with funds managed by Ares providing for the lenders to make secured term loans to us in the principal amount of $350 million (the “Refinancing”). As part of the Refinancing, we issued warrants to purchase 2,251,364 shares of our common stock at a price of $22.00 per share and required certain amendments to the revolving credit facility. The term loans were issued at an original issue discount of $16.8 million, which amount equaled the cash consideration received by us for the issuance of the related warrants and shares of special voting preferred stock. Aggregate cash proceeds from the Refinancing of approximately $340 million, net of transaction costs, were used to fully repay the then-outstanding balance on the revolving credit facility of $160 million, plus accrued interest and fees.
The warrants expire in 2026 and contain various anti-dilution provisions. Pursuant to FASB ASC 815-40, we account for the warrants as derivative instruments and carry the warrants as a non-current liability at their fair value, with the calculated increase or decrease in fair value each quarter being recognized in the statement of operations and comprehensive income (loss) (see Note 9). The warrants had a fair value of $16.8 million at the date of issuance and a fair value of $246.7 million at December 31, 2016. As a result, for the year ended December 31, 2016, we recorded a loss on revaluation of the warrant liability of $230 million.
Interest on the term loans is payable quarterly in cash at 12.5% per year; however, during the period from March 15, 2016 through March 31, 2018, we may elect to pay interest for any quarter in-kind at 15% per year. We paid interest for the period commencing from March 15, 2016 and ending March 31, 2016 in cash, and elected to pay interest for the quarterly periods ended June 30, 2016 and September 30, 2016 in-kind. We paid interest for the quarterly period ending December 31, 2016 in cash. In
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
February 2017, we elected to pay interest for the quarterly period ending March 31, 2017 in cash. Future quarterly elections to pay in-kind must be made 30 days prior to the beginning of each calendar quarter.
The term loan credit facility matures on March 15, 2021, but is subject to an earlier maturity on December 31, 2018, if we do not extend or refinance our existing 2019 Senior Notes on or prior to that date.
The term loan credit facility is collateralized by a second lien on substantially all of our assets, including at least 90% of the adjusted engineered value (as defined in the term loan credit facility) attributed to our proved oil and gas interests. The obligations under the term loan credit facility are guaranteed by each of CWEI’s material restricted domestic subsidiaries. Optional and mandatory prepayments made prior to September 15, 2020 are subject to make-whole or prepayment premiums.
The term loan credit facility also contains various covenants and restrictive provisions which may, among other things, limit our ability to sell assets, incur additional indebtedness, make investments or loans and create liens. One such covenant requires that we maintain an asset-to-secured debt coverage ratio as of each December 31 and June 30 of each year, beginning with December 31, 2018, of at least 1.2 to 1.0. We were in compliance with all covenants at December 31, 2016.
The failure to comply with these covenants will constitute an event of default (subject, in the case of certain covenants, to applicable notice and/or cure periods) under the term loan credit facility. Other events of default under the term loan credit facility include, among other things, (1) the failure to timely pay principal, interest, fees or other amounts due and owing, (2) the inaccuracy of representations or warranties in any material respect, (3) the occurrence of certain bankruptcy or insolvency events, and (4) the loss of lien perfection or priority. The occurrence and continuance of an event of default could result in, among other things, acceleration of all amounts outstanding.
On July 22, 2016, we entered into an agreement to sell 5,051,100 shares of common stock to funds managed by Ares for cash proceeds of $150 million, or approximately $29.70 per share (the “Private Placement”), which transaction closed on August 29, 2016. In connection with the Private Placement, we entered into an amendment to the term loan facility, waiving certain restrictions to enable us to use proceeds from equity issuances and specified asset sales for debt reduction and capital expenditures.
Senior Notes
In March 2011, we issued $300 million of aggregate principal amount of 2019 Senior Notes. The 2019 Senior Notes, which are unsecured, were issued at par and bear interest at 7.75% per year, payable semi-annually on April 1 and October 1 of each year. In April 2011, we issued an additional $50 million aggregate principal amount of the 2019 Senior Notes with an original issue discount of 1% or $0.5 million. In October 2013, we issued an additional $250 million of aggregate principal amount of the 2019 Senior Notes at par to yield 7.75% to maturity. All of the 2019 Senior Notes are treated as a single class of debt securities under the same indenture. In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the year ended December 31, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million discount and a $1 million write-off of debt issuance costs. We may redeem some or all of the 2019 Senior Notes at redemption prices (expressed as percentages of principal amount) equal to 100% beginning on April 1, 2017 or for any period thereafter, in each case plus accrued and unpaid interest.
The Indenture contains covenants that restrict our ability to: (1) borrow money; (2) issue redeemable or preferred stock; (3) pay distributions or dividends; (4) make investments; (5) create liens without securing the 2019 Senior Notes; (6) enter into agreements that restrict dividends from subsidiaries; (7) sell certain assets or merge with or into other companies; (8) enter into transactions with affiliates; (9) guarantee indebtedness; and (10) enter into new lines of business. One such covenant generally restricts our ability to incur indebtedness if our ratio of consolidated EBITDAX to consolidated interest expense (as these terms are defined in the Indenture) is less than 2.25 times. However, this restriction does not prevent us from incurring indebtedness under a credit facility (as defined in the Indenture) in an aggregate principal amount at any time outstanding not to exceed the greater of (a) $500 million and (b) 30% of Adjusted Consolidated Net Tangible Assets (as defined in the Indenture). These covenants are subject to a number of additional important exceptions and qualifications as described in the Indenture. We were in compliance with these covenants at December 31, 2016 and December 31, 2015.
4. Sales of Assets
In December 2016, we sold substantially all of our assets in the Giddings Area in East Central Texas for cash consideration of $400 million, subject to customary closing adjustments. In September 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $1.4 million. In July 2016, we sold our interests in certain wells in Glasscock County, Texas for approximately $19.4 million, subject to customary post-closing adjustments. In June 2016, we sold our interests in certain wells in Oklahoma for cash consideration of $1.5 million. In April 2016, we sold certain acreage in Burleson County, Texas for cash
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consideration of $2 million. In February 2016, we sold certain acreage in Burleson County, Texas for cash consideration of $0.8 million.
In December 2015, we sold certain acreage in Burleson County, Texas for cash consideration of $21.8 million. This acreage, located east of our contiguous acreage block, was sold under a three-year term assignment that may be extended beyond the stated term as long as the buyer maintains a 180-day continuous development program on the acreage. We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production in all wells currently situated on the acreage. We also reserved an overriding royalty interest to the extent the net revenue interest of any assigned lease exceeds 75%. In September 2015, we sold our interests in selected leases and wells in South Louisiana for $11.8 million subject to customary closing adjustments. In June 2015, we sold certain acreage in Burleson County, Texas for cash consideration of $22.1 million. We retained our rights to all depths and formations other than the Eagle Ford formation and also retained our interest in acreage and production associated with the Porter E Unit #1, our only Eagle Ford well situated on this acreage, a reversionary interest in acreage if the buyer fails to maintain a continuous development program and an overriding royalty interest in leases to the extent the net revenue interest exceeds 75%. During the first half of 2015, we sold our interests in selected leases in Oklahoma and sold our interests in certain wells in Martin and Yoakum Counties, Texas for proceeds totaling $7.3 million.
In September 2014, we sold our interests in approximately 7,500 net acres in the Delaware Basin in Ward and Winkler Counties, Texas to an unaffiliated third party for $29.3 million. In March 2014, we closed a transaction to sell our interests in selected wells and leases in Wilson, Brazos, La Salle, Frio and Robertson Counties, Texas for $71 million, subject to customary closing adjustments. At closing, $6.8 million of the total proceeds was placed in escrow pending resolution of certain title requirements. In May 2015, the title requirements were satisfied and the remaining proceeds were released. In February 2014, we sold a property in Ward County, Texas for $5.1 million, subject to customary closing adjustments.
Net proceeds from each of these transactions were used to repay the then-outstanding balance on the revolving credit facility and to fund a portion of our planned capital expenditures for 2016, 2015 and 2014.
5. Asset Retirement Obligations
We record the ARO associated with the retirement of our long-lived assets in the period in which they are incurred and become determinable. Under this method, we record a liability for the expected future cash outflows discounted at our credit-adjusted risk-free interest rate for the dismantlement and abandonment costs, excluding salvage values, of each oil and gas property. We also record an asset retirement cost to the oil and gas properties equal to the ARO liability. The fair value of the asset retirement cost and the ARO liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
The following table reflects the changes in ARO for the years ended December 31, 2016 and 2015:
6. Deferred Revenue from Volumetric Production Payment
In March 2012, Southwest Royalties, Inc. (“SWR”), a wholly owned subsidiary of CWEI, completed the mergers of each of the 24 limited partnerships of which SWR was the general partner, into SWR, with SWR continuing as the surviving entity in the mergers. To obtain the funds to finance the aggregate merger consideration, SWR entered into a volumetric production payment (“VPP”) with a third party for upfront cash proceeds of $44.4 million and deferred future advances aggregating $4.7 million. Under the terms of the VPP, SWR conveyed to the third party a term overriding royalty interest covering approximately 725 MBOE
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of estimated future oil and gas production from certain properties derived from the mergers. The scheduled volumes under the VPP relate to production months from March 2012 through December 2019 and were to be delivered to, or sold on behalf of, the third party free of all costs associated with the production and development of the underlying properties. Once the scheduled volumes were delivered to the third party, the term overriding royalty interest would terminate. SWR retained the obligation to prudently operate and produce the properties during the term of the VPP, and the third party assumed all risks associated with product prices. As a result, the VPP was accounted for as a sale of reserves, with the sales proceeds being deferred and amortized into oil and gas sales as the scheduled volumes were produced. The net proceeds from the VPP were recorded as a non-current liability in the consolidated balance sheets. Deferred revenue from the VPP was amortized over the life of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). In August 2015, we terminated the VPP covering 277 MBOE of oil and gas production from August 2015 through December 2019 for $13.7 million. The termination of the VPP was accounted for as a repurchase of reserves, with the repurchase price offsetting the non-current liability and the balance of the remaining non-current liability amortized over the original term of the VPP and recognized in oil and gas sales in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2016, we have no further obligations under the VPP.
The following table reflects the changes in deferred revenue during the years ended December 31, 2016 and 2015:
7. Income Taxes
Deferred tax assets and liabilities are the result of temporary differences between the consolidated financial statement carrying values and the tax basis of assets and liabilities. Significant components of net deferred tax liabilities at December 31, 2016 and 2015 are as follows:
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For the years ended December 31, 2016, 2015 and 2014, effective income tax rates were different than the statutory federal income tax rates for the following reasons:
(a)
Includes $80.5 million of permanent differences related to the change in fair value of common stock warrants in 2016.
We derive a tax deduction when options are exercised under our stock option plans. To the extent these tax deductions are used to reduce currently payable taxes in any period, we record a tax benefit for the excess of the tax deduction over cumulative book compensation expense as additional paid-in capital and as a financing cash flow in the accompanying consolidated financial statements. At December 31, 2016, our cumulative tax loss carryforwards were approximately $239.3 million, of which $22 million relates to excess tax benefits from exercise of stock options. The cumulative tax loss carryforwards are scheduled to expire if not utilized between 2027 and 2031.
In assessing the ability to realize deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. If it is more likely than not that some portion or all of the assets will not be realized, the assets are reduced by a valuation allowance. Based on our analysis of future taxable income, no valuation allowance is required.
CWEI and its subsidiaries file federal income tax returns with the United States Internal Revenue Service and state income tax returns in various state tax jurisdictions. As a general rule, the Company’s tax returns for fiscal years after 2012 currently remain subject to examination by appropriate taxing authorities. None of our income tax returns are under examination at this time. We do not have any uncertain tax positions as of December 31, 2016 and 2015.
8. Derivatives
Commodity Derivatives
From time to time, we utilize commodity derivatives, consisting of swaps, floors and collars, to attempt to optimize the price received for our oil and gas production. When using swaps to hedge oil and natural gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract, generally New York Mercantile Exchange (“NYMEX”) futures prices, resulting in a net amount due to or from the counterparty. In floor transactions, we receive a fixed price (put strike price) if the market price falls below the put strike price for the respective commodity. If the market price is greater than the put strike price, no payments are due from either party. Costless collars are a combination of puts and calls, and contain a fixed floor price (put strike price) and ceiling price (call strike price). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then we receive the fixed price and pay the market price. If the market price is between the call and the put strike prices, no payments are due from either party. Commodity derivatives are settled monthly as the contract production periods mature.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following summarizes information concerning our net positions in open commodity derivatives applicable to periods subsequent to December 31, 2016. Settlement prices of commodity derivatives are based on NYMEX futures prices.
Swaps:
Costless Collars:
Accounting for Commodity Derivatives
We did not designate any of our commodity derivatives as cash flow hedges; therefore, all changes in the fair value of these contracts prior to maturity, plus any realized gains or losses at maturity, were recorded as other income (expense) in our consolidated statements of operations and comprehensive income (loss).
Effect of Commodity Derivative Instruments on the Consolidated Balance Sheets
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Gross to Net Presentation Reconciliation of Commodity Derivative Assets and Liabilities
Our commodity derivative contracts are with JPMorgan Chase Bank, N.A. and Shell Trading Risk Management LLC.
Effect of Commodity Derivative Instruments Recognized in Earnings on the Consolidated Statements of Operations and Comprehensive Income (Loss)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Fair Value of Financial Instruments
Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Indebtedness under the revolving credit facility was estimated to have a fair value approximating the carrying amount since the interest rate is generally market sensitive.
Fair Value Measurements
We follow a framework for measuring fair value, which outlines a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. Fair value is defined as the price at which an asset could be exchanged in a current transaction between knowledgeable, willing parties at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, use of unobservable prices or inputs are used to estimate the current fair value, often using an internal valuation model. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the item being valued. We categorize our assets and liabilities recorded at fair value in the accompanying consolidated balance sheets based upon the level of judgment associated with the inputs used to measure their fair value.
Hierarchical levels directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities, are as follows:
Level 1 -
Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 -
Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.
Level 3 -
Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.
The financial assets and liabilities measured on a recurring basis at December 31, 2016 and December 31, 2015 were commodity derivatives and common stock warrants.
Common stock warrant liabilities are measured at fair value on a recurring basis until the underlying common stock warrants are exercised (see Note 3). We measure the fair value of the common stock warrant liabilities using the Black-Scholes method (Level 2 inputs). Inputs used to determine fair value under this method include our price volatility and expected remaining life.
The fair value of all commodity derivative contracts and common stock warrants are reflected on the consolidated balance sheets as detailed in the following schedule:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Fair Value of Other Financial Instruments
We estimate the fair value of the 2019 Senior Notes using quoted market prices. The fair value of our Second Lien Term Loan as of December 31, 2016 is based upon our discounted cash flow model. Fair value is compared to the carrying value in the table below:
10. Shareholders’ Equity and Earnings (Loss) Per Share
In August 2016, we completed the sale of 5,051,100 shares of our common stock to funds managed by Ares for cash proceeds of $150 million or approximately $29.70 per share. Net proceeds from the sale, after offering expenses of $2.7 million, were used to repay indebtedness and provide additional funds for general corporate purposes.
Earnings (Loss) Per Share
Basic earnings (loss) per share amounts have been computed based on the weighted average number of shares of common stock outstanding for the period. Diluted earnings (loss) per share include the effect of potentially dilutive shares outstanding for the period. For the year ended December 31, 2016, there were 282,000 shares that were not included in the computation of diluted earnings (loss) per share because their inclusion would have been anti-dilutive for the periods.
11. Compensation Plans
Long-Term Incentive Plan
In June 2016, shareholders approved the Clayton Williams Energy, Inc. Long-Term Incentive Plan (the “LTIP”), which was adopted by the Compensation Committee of the Board in April 2016. The LTIP was adopted in order to enable us to attract and retain highly qualified employees, directors and consultants and to provide equity-based compensation to those individuals that will align their interests with the interests of our shareholders. The LTIP provides for the granting of restricted stock awards, restricted stock units, stock options, stock appreciation rights, dividend-equivalent awards, other stock-based awards, cash awards, performance awards, and any combination of such awards. A total of 1,400,000 shares of our common stock have been reserved for issuance under the LTIP and are expected to consist of new shares of the Company. During the year ended December 31, 2016, grants of awards under the LTIP were made as disclosed in the tables below.
Stock Options
All outstanding nonqualified and incentive stock options under the LTIP expire seven years from the date of grant and vest ratably over a three-year period. The exercise price of stock options under the LTIP may not be less than the market value of the stock on the date of grant. The fair value of the stock options on the date of grant is expensed ratably over the applicable vesting period. We estimate the fair value of stock options granted using a Black-Scholes option valuation model, which requires us to make certain assumptions, as follows:
•
Expected volatility of the underlying common stock is based on our historical stock volatility;
•
Expected term of options granted is based on the mid-point between the final vesting date and the expiration date since our common stock does not have sufficient history to predict the expected term using historical data; and
•
Risk-free interest rate is based on the U.S. Treasury yield curve for the expected term of the options at the date of grant.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the weighted average grant date fair values and related assumptions for grants made during the year ended December 31, 2016:
The following table sets forth certain information regarding our stock options as of December 31, 2016:
As of December 31, 2016, the unrecognized compensation cost related to granted stock options was $11.8 million. Such cost is expected to be recognized over a weighted-average period of 2.7 years.
Restricted Stock Awards
Restricted stock awards granted under the LTIP as of December 31, 2016 vest over either a one-year or three-year period. The estimated fair value of restricted stock grants, computed based on the closing price of our common stock on the date of grant, is expensed ratably over the applicable vesting period.
The following table presents our restricted stock activity as of December 31, 2016:
The aggregate fair value of restricted stock awards granted during the year ended December 31, 2016 was $29.2 million. As of December 31, 2016, our unrecognized compensation cost related to unvested restricted stock awards was $24.6 million. Such cost is expected to be recognized over a weighted-average period of 2.6 years.
Stock-based compensation expense related to stock options and restricted stock awards was $5.7 million for the year ended December 31, 2016 and none for the years ended December 31, 2015 and 2014.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Non-Equity Award Plans
The Compensation Committee of the Board has adopted an after-payout (“APO”) incentive plan (the “APO Incentive Plan”) for officers, key employees and consultants who promote our drilling and acquisition programs. The Compensation Committee’s objective in adopting this plan is to further align the interests of the participants with ours by granting the participants an APO interest in the production developed, directly or indirectly, through the efforts of the participants. The plan generally provides for the creation of a series of partnerships or participation arrangements, which are treated as partnerships for tax purposes (the “APO Partnerships”), between us and the participants, to which we contribute a portion of our economic interest in wells drilled or acquired within certain areas. Generally, we pay all costs to acquire, drill and produce applicable wells and receive all revenues until we have recovered all of our costs, plus interest (“payout”). At payout, the participants receive 99% to 100% of all subsequent revenues and pay 99% to 100% of all subsequent expenses attributable to the economic interests that are subject to the APO Partnerships. Between 5% and 7.5% of our economic interests in specified wells drilled or acquired by us subsequent to October 2002 are subject to the APO Incentive Plan. We record our allocable share of the assets, liabilities, revenues, expenses and oil and gas reserves of these APO Partnerships in our consolidated financial statements. Participants in the APO Incentive Plan are immediately vested in all future amounts payable under the plan.
The Compensation Committee has also adopted an APO reward plan (the “APO Reward Plan”) which offers eligible officers, key employees and consultants the opportunity to receive bonus payments that are based on certain profits derived from a portion of our working interest in specified areas where we are conducting drilling and production enhancement operations. The wells subject to an APO Reward Plan are not included in the APO Incentive Plan. Likewise, wells included in the APO Incentive Plan are not included in the APO Reward Plan. Although conceptually similar to the APO Incentive Plan, the APO Reward Plan is a compensatory bonus plan through which we pay participants a bonus equal to a portion of the APO cash flows received by us from our working interest in wells in a specified area. Unlike the APO Incentive Plan, however, participants in the APO Reward Plan are not immediately vested in all future amounts payable under the plan. To date, we have granted awards under the APO Reward Plan in eight specified areas, each of which established a quarterly bonus amount equal to 7% or 10% of the APO cash flow from wells drilled or recompleted in the respective areas after the effective date set forth in each plan, which dates range from January 1, 2007 to June 11, 2014. As of June 23, 2016, all eight awards were fully vested. On May 4, 2016, the Compensation Committee amended the definition of a well in each plan to end the inclusion of new wells in all plans. A well is a well drilled by the employer in the area described provided that the well has a spud date between the effective date and May 4, 2016. All other terms of the plan remain unchanged. Future payments to participants in the plan will be based on the performance of only those wells that meet the revised definition of a well. The Compensation Committee expects to utilize the LTIP in lieu of future grants under the APO Reward Plan.
In January 2007, we granted awards under the Southwest Royalties Reward Plan (the “SWR Reward Plan”), a one-time incentive plan which established a quarterly bonus amount for participants equal to the APO cash flow from a 22.5% working interest in one well. The plan is fully vested and 100% of subsequent quarterly bonus amounts are payable to participants.
To continue as a participant in the APO Reward Plan or the SWR Reward Plan, participants must remain in the employment or service of the Company through the full vesting date established for each award. The full vesting date may be accelerated in the event of a change of control or sale transaction, as defined in the plan documents.
We recognize compensation expense related to the APO Partnerships based on the estimated value of economic interests conveyed to the participants. Estimated compensation expense applicable to the APO Reward Plan and the SWR Reward Plan is recognized over the applicable vesting periods, which range from two years to five years. Compensation expense related to non-equity award plans was $(7.9) million in 2016, $(0.03) million in 2015 and $4.6 million in 2014. Credits to expense resulted from the reversal of previously accrued compensation expense attributable to changes in estimates of future compensation expense.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accrued compensation under non-equity award plans is reflected in the accompanying consolidated balance sheets as detailed in the following schedule:
12. Transactions with Affiliates
The Company and other entities (the “Williams Entities”) controlled by Mr. Williams are parties to an agreement (the “Service Agreement”) pursuant to which the Company furnishes services to, and receives services from, such entities. Under the Service Agreement, as amended from time to time, CWEI provides legal, computer, payroll and benefits administration, insurance administration, tax preparation services, tax planning services, and financial and accounting services to the Williams Entities, as well as technical services with respect to certain oil and gas properties owned by the Williams Entities. The Williams Entities provide business entertainment to or for the benefit of CWEI.
The following table summarizes the charges to and from the Williams Entities for the years ended December 31, 2016, 2015 and 2014.
(a)
Rent amounts were paid to ClayDesta Buildings, L.P., a Texas limited partnership referred to as CDBLP, of which the Company owns 33.5% and affiliates of the Company own 25.8%. A Williams Entity provides property management services to the buildings owned and operated by CDBLP.
(b)
Consists primarily of hunting and fishing recreation for business associates and employees of the Company on land owned by affiliates of Mr. Williams.
Accounts receivable from affiliates and accounts payable to affiliates include, among other things, amounts for customary charges by the Company as operator of certain wells in which affiliates own an interest.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Other Operating Revenues and Expenses
Other operating revenues and expenses for the years ended December 31, 2016, 2015 and 2014 are as follows:
Gain on sales of assets for the year ended December 31, 2016 included the sale of substantially all of our assets in the Giddings Area in East Central Texas in December 2016 and the sale of our interests in certain wells in Glasscock County, Texas in July 2016 (see Note 4).
Gain on sales of assets for the year ended December 31, 2015 included the sale of selected leases and wells in South Louisiana in September 2015, the release of sales proceeds previously held in escrow pending resolution of title requirements associated with the sale of certain non-core Austin Chalk/Eagle Ford assets sold in March 2014, the sale of leases in Oklahoma in May and June 2015 and the sale of selected wells in Martin and Yoakum Counties, Texas in March 2015 (see Note 4).
Gain on sales of assets for the year ended December 31, 2014 included the sale of certain non-core Austin Chalk/Eagle Ford assets in March 2014 and the sale of a property in Ward County, Texas in February 2014 (see Note 4).
We maintain an inventory of tubular goods and other well equipment for use in our exploration and development drilling activities. Inventory is carried at the lower of average cost or estimated fair market value. We categorize the measurement of fair value of inventory as Level 2 under applicable accounting standards. To determine estimated fair value of inventory, we subscribe to market surveys and obtain quotes from equipment dealers for similar equipment. We then correlate the data as needed to estimate the fair value of the specific items (or groups of similar items) in our inventory. If the estimated fair values for those specific items (or groups of similar items) in our inventory are less than the related average cost, a provision for impairment is made.
14. Investment in Dalea Investment Group, LLC
In June 2012, we cancelled an $11 million note receivable in exchange for a 7.66% non-controlling membership interest in Dalea Investment Group, LLC (“Dalea”), an international oilfield services company formed in March 2012. Since the membership interests in Dalea are privately-held and are not traded in an active market, our investment in Dalea was carried at the lower of its initial cost of $11 million and its estimated fair value based on a qualitative assessment. We recorded an $8.4 million impairment on our investment in Dalea for the year ended December 31, 2016, $2.6 million for the year ended December 31, 2015 and none for the year ended December 31, 2014. As of December 31, 2016, our investment in Dalea was fully impaired compared to an estimated fair value of $8.4 million at December 31, 2015. We categorize the measurement of fair value of this investment as a Level 3 input.
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15. Commitments and Contingencies
Leases
We lease office space from affiliates and nonaffiliates under noncancelable operating leases. Rental expense pursuant to the office leases amounted to $1.9 million, $1.9 million and $1.8 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Future minimum payments under noncancelable leases at December 31, 2016 are as follows:
(a) Relates to vehicle leases.
Legal Proceedings
In February 2012, BMT O&G TX, L.P. filed a suit in the 143rd Judicial District in Reeves County, Texas to terminate a lease under our farm-in agreement with Chesapeake Exploration, L.L.C. (“Chesapeake”). Plaintiffs are the lessors and claim a breach of the lease which they allege gives rise to termination of the lease. CWEI denies a breach and argues in the alternative that (i) any breach was cured in accordance with the lease and (ii) a breach will not give rise to lease termination. In October 2013, a judge ruled that CWEI and Chesapeake are jointly and severally liable for damages to plaintiffs in the amount of approximately $2.9 million and attorney fees of $0.8 million. A loss of $1.4 million was recorded for the year ended December 31, 2013 in connection with the judgment. CWEI appealed the judgment and on July 8, 2015, the El Paso Court of Appeals reversed the trial court judgment in its entirety and rendered judgment that Plaintiffs take nothing on all claims against CWEI and Chesapeake. Plaintiffs have appealed the decision of the Court of Appeals to the Texas Supreme Court and on October 21, 2016, the Texas Supreme Court denied Plaintiffs’ Petition for Review. Plaintiffs moved for rehearing on the denial, and CWEI’s and Chesapeake’s responses are due February 22, 2017.
CWEI has been named a defendant in three lawsuits filed in Louisiana, one by Southeast Louisiana Flood Protection Authority-East (“SELFPA”) and two by Plaquemines Parish, each alleging that historical industry operations have significantly damaged coastal marshlands.
In July 2013, the SELFPA case was filed in Orleans Parish and alleged that dredging and other oilfield operations of the 95 oil and gas company defendants caused degradation and destruction of the coastal marshlands which serve as a buffer protecting the coastal area of Louisiana from storms. The case was removed to Federal District Court. Legislation was enacted in Louisiana in 2014 in response to the suit which would effectively eliminate the claims, but in late 2014 the Louisiana state court judge declared the new law unconstitutional. A motion to dismiss the claims was granted in Federal District Court and the plaintiff has appealed to the United States Fifth Circuit Court of Appeals. Oral argument was heard on February 29, 2016. The Court has not yet ruled.
In November 2013, we were served with two separate suits filed by Plaquemines Parish in the 25th Judicial District Court of Plaquemines Parish, Louisiana (Designated Case Nos. 61-002 and 60-982). Multiple defendants are named in each suit, and each suit involves a different area of operation within Plaquemines Parish. Except as to the named defendants and areas of operation, the suits are identical. Plaintiff alleges that defendants’ oil and gas operations violated certain laws relating to the coastal zone management including failure to obtain permits, violation of permits, use of unlined waste pits, discharge of oil field wastes, including naturally occurring radioactive material, and that dredging operations exceeded unspecified permit limitations. Plaintiff makes no specific allegations against any individual defendant and seeks unspecified monetary damages and declaratory relief, as well as restoration, costs of remediation and attorney fees. The cases were removed to the U.S. District Court for the Eastern District of Louisiana but were remanded back to the state court in 2015. In November 2015, the Plaquemines Parish Council
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
passed Resolution 15-389 requiring its attorneys to cease all work on the cases other than to dismiss all actions and lawsuits, but in April of 2016 the Parish voted to rescind such resolution. The State of Louisiana Department of Natural Resources, Office of Coastal Management has intervened in these cases and the Louisiana Attorney General has filed to supersede the Parish as Plaintiff. Status conferences were held in November 2016.
Our overall exposure to these suits is not currently determinable and we intend to vigorously defend these cases. We are also a defendant in several other lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these lawsuits to have a material adverse effect on our consolidated financial condition or results of operations.
16. Impairment of Property and Equipment
We impair our long-lived assets, including oil and gas properties and contract drilling equipment, when estimated undiscounted future net cash flows of an asset are less than its carrying value. The amount of any such impairment is recognized based on the difference between the carrying value and the estimated fair value of the asset. We categorize the measurement of fair value of these assets as Level 3 inputs. We estimate the fair value of the impaired property by applying weighting factors to fair values determined under three different methods: (1) discounted cash flow method; (2) flowing daily production method; and (3) proved reserves per BOE method. We then assign applicable weighting factors based on the relevant facts and circumstances. We utilize all three methods when that information is available, or if not will utilize the discounted cash flow method. We recorded provisions for impairment of property and equipment aggregating $7.6 million in 2016, $41.9 million in 2015 and $12 million in 2014 to reduce the carrying value of those properties to their estimated fair values. The 2016 provision of $7.6 million included $5.2 million related to the write-down of non-core properties in North Dakota, Oklahoma, California and the Cotton Valley area of Texas and $2.4 million related to the write-down of certain drilling rigs and related equipment to reduce the carrying values of these properties to their estimated fair values. The 2015 provision of $41.9 million included $37.9 million related primarily to the write-down of certain non-core properties in the Permian Basin and Oklahoma and $4 million related to the write-down of certain drilling rigs and related equipment to reduce the carrying values of these properties to their estimated fair values. The 2014 provision of $12 million related to the write-down of certain non-core properties in the Permian Basin and North Dakota.
Unproved properties are nonproducing and do not have estimable cash flow streams. Therefore, we estimate the fair value of individually significant prospects by obtaining, when available, information about recent market transactions in the vicinity of the prospects and adjust the market data as needed to give consideration to the proximity of the prospects to known fields and reservoirs, the extent of geological and geophysical data on the prospects, the remaining terms of leases holding the acreage in the prospects, recent drilling results in the vicinity of the prospects, and other risk-related factors such as drilling and completion costs, estimated product prices and other economic factors. Individually insignificant prospects are grouped and impaired based on remaining lease terms and our historical experience with similar prospects. Based on the assessments previously discussed, we will impair our unproved oil and gas properties when we determine that a prospect’s carrying value exceeds its estimated fair value. We categorize the measurement of fair value of unproved properties as Level 3 inputs. We recorded provisions for impairment of unproved properties aggregating $2.3 million, $2.8 million and $15.4 million in 2016, 2015 and 2014, respectively, and charged these impairments to abandonments and impairments in the accompanying consolidated statements of operations and comprehensive income (loss).
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. Costs of Oil and Gas Properties
The following table sets forth certain information with respect to costs incurred in connection with the Company’s oil and gas producing activities during the years ended December 31, 2016, 2015 and 2014.
The following table sets forth the net capitalized costs for oil and gas properties as of 2016 and 2015.
18. Segment Information
We have two reportable operating segments, which are (1) oil and gas exploration and production and (2) contract drilling services. The following tables present selected financial information regarding our operating segments for the years ended December 31, 2016, 2015 and 2014.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
_______
(a)
Includes impairment of property and equipment.
(b)
Includes the following expenses: production, exploration, midstream services, drilling rig services, accretion of ARO, G&A expenses and other operating expenses.
(c)
Includes impairment of our investment in Dalea.
19. Guarantor Financial Information
In March and April 2011, we issued $350 million of aggregate principal amount of 2019 Senior Notes. In October 2013, we issued $250 million of aggregate principal amount of the 2019 Senior Notes. The 2019 Senior Notes issued in October 2013 and the 2019 Senior Notes originally issued in March and April 2011 are treated as a single class of debt securities under the Indenture. In August 2016, we redeemed $100 million in aggregate principal amount of the 2019 Senior Notes in a tender offer and for the year ended December 31, 2016 recorded a $4 million gain on early extinguishment of long-term debt, consisting of a $5 million discount and a $1 million write-off of debt issuance costs (see Note 3). Presented below is condensed consolidated financial information of CWEI (the “Issuer”) and the Issuer’s material wholly owned subsidiaries. Other than CWEI Andrews Properties, GP, LLC, the general partner of CWEI Andrews Properties, L.P., an affiliated limited partnership formed in April 2013, all of the Issuer’s wholly owned and active subsidiaries (“Guarantor Subsidiaries”) have jointly and severally, irrevocably and unconditionally guaranteed the performance and payment when due of all obligations under the 2019 Senior Notes. The guarantee by a Guarantor Subsidiary of the 2019 Senior Notes may be released under certain customary circumstances as set forth in the Indenture. CWEI Andrews Properties, GP, LLC, is not a guarantor of the 2019 Senior Notes and its accounts are reflected in the “Non-Guarantor Subsidiary” column in this Note 19.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The financial information which follows sets forth our condensed consolidating financial statements as of and for the periods indicated.
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. Subsequent Events
Proposed Merger with Noble Energy
On January 13, 2017, we entered into the Merger Agreement with Noble Energy, Merger Sub and Merger Sub II, pursuant to which Noble Energy will acquire the Company in exchange for a combination of Noble Energy Common Shares and cash. Under the terms of the Merger Agreement, at the Effective Time of the Merger, each share of the Company’s common stock issued and outstanding immediately prior to the Effective Time (other than common stock held in treasury and common stock held by shareholders who properly comply in all respects with the provisions of Section 262 of the DGCL as to appraisal rights) and each unexercised CWEI Warrant issued and outstanding as of the Effective Time will be cancelled and extinguished and automatically converted into the right to receive, at the election of the shareholder or warrant holder, as applicable, and subject to proration as described below, one of the following forms of Merger Consideration:
•
for each share of common stock, one of (i) 3.7222 Noble Energy Common Shares (the “Share Consideration”); (ii) (A) $34.75 in cash (subject to applicable withholding tax), without interest, and (B) 2.7874 Noble Energy Common Shares (the “Mixed Consideration”); or (iii) $138.39 in cash (subject to applicable withholding tax), without interest (the “Cash Consideration”); and
•
for each CWEI Warrant, either (i) the Share Consideration in respect of the number of shares of common stock of the Company that would be issued upon a cashless exercise of such CWEI Warrant immediately prior to the Effective Time (“Warrant Notional Common Shares”); (ii) the Mixed Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant; or (iii) the Cash Consideration in respect of the number of Warrant Notional Common Shares represented by such CWEI Warrant.
The Merger Agreement contains certain termination rights for both Noble Energy and the Company, including if the Merger is not consummated by July 17, 2017, and further provides that, upon termination of the Merger Agreement under certain circumstances, the Company may be required to pay Noble Energy a termination fee equal to $87 million. The closing of the Merger is expected to occur in the second quarter of 2017.
Purchase of Net Mineral Acres in Southern Reeves County, Texas
In January 2017, we purchased approximately 1,900 net mineral acres in Southern Reeves County, Texas from a private seller, for cash consideration totaling $44.3 million. The acreage is located in and around our existing contiguous acreage block. Also included in the deal was a non-operated gross working interest of approximately 26% in an existing horizontal well.
We have evaluated events and transactions that occurred after the balance sheet date of December 31, 2016 and have determined that no other events or transactions have occurred that would require recognition in the consolidated financial statements or disclosures in these notes to the consolidated financial statements.
CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION
(UNAUDITED)
Supplemental Quarterly Financial Data
The following table summarizes results for each of the four quarters in the years ended 2016 and 2015.
(a)
Includes gains on sales of assets related to the sale of substantially all of our assets in the Giddings Area in East Central Texas in December 2016.
(b)
The sum of the individual quarterly net income (loss) per share amounts may not agree to the total for the year since each period’s computation is based on the weighted average number of common shares outstanding during each period.
S-1
CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION (Continued)
(UNAUDITED)
Supplemental Oil and Gas Reserve Information
The estimates of proved oil and gas reserves utilized in the preparation of the consolidated financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the FASB. All of our reserves are located in the United States. For information about our results of operations from oil and gas activities, see the accompanying consolidated statements of operations and comprehensive income (loss).
We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.
We did not have any capital costs relating to exploratory wells pending the determination of proved reserves for the years ended 2016, 2015 and 2014.
The following table sets forth estimated proved reserves together with the changes therein (oil and NGL in MBbls, gas in MMcf, gas converted to MBOE by dividing MMcf by six) for the years ended 2016, 2015 and 2014.
S-2
CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION (Continued)
(UNAUDITED)
The 168 MBOE of net downward revisions in proved reserves for 2016 resulted from a combination of (1) net upward revisions of 11,670 MBOE related primarily to performance in our Delaware Basin program, and (2) downward revisions of 11,838 MBOE related to the effects of lower commodity prices on the estimated quantities of proved reserves.
The standardized measure of discounted future net cash flows relating to estimated proved reserves as of 2016, 2015 and 2014 was as follows:
Changes in the standardized measure of discounted future net cash flows relating to estimated proved reserves for the years ended 2016, 2015 and 2014 were as follows:
S-3
CLAYTON WILLIAMS ENERGY, INC.
SUPPLEMENTAL INFORMATION (Continued)
(UNAUDITED)
The estimated present value of future cash flows relating to estimated proved reserves is extremely sensitive to prices used at any measurement period. Average prices for 2016, 2015 and 2014 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for the period from January through December during each respective calendar year. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties. The average prices used for each commodity for the years ended 2016, 2015 and 2014 were as follows:
S-4
Index of Exhibits
*
Filed herewith.
**
Incorporated by reference to the filing indicated.
***
Furnished herewith.
†
Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.
††
Filed under the Company’s Commission File No. 001-10924.