ITEM 1A. RISK FACTORS
RISK FACTORS
There are many factors that may affect our business and results of operations. If any of the following risks actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. Further, the risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business.
Risks Related to the Oil, Natural Gas and NGL Industry and Our Business
Oil and natural gas prices are volatile. An extended or further decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our oil, natural gas and NGL production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil, natural gas and NGL are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. For example, during the period from January 1, 2014 to December 31, 2018, NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $26.21 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. The duration and magnitude of the recent decline in oil prices cannot be predicted. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
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worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and NGL;
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the price and quantity of foreign imports;
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political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
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the level of global exploration and production;
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the level of global inventories;
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prevailing prices on local price indices in the areas in which we operate;
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the proximity, capacity, cost and availability of gathering and transportation facilities;
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localized and global supply and demand fundamentals and transportation availability;
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members of the Organization of Petroleum Exporting Countries and other oil exporting nations to agree to and maintain oil price and production controls;
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weather conditions;
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technological advances affecting energy consumption;
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the effect of worldwide energy conservation and environmental protection efforts;
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the price and availability of alternative fuels;
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domestic, local and foreign governmental regulation and taxes; and
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shareholder activism and activities by non-governmental organizations to restrict the exploration, development and production of oil and natural gas.
Since November 2014, prices for U.S. oil have weakened in response to continued high levels of production, a buildup in inventories and lower global demand. Prices for oil have showed some recovery beginning in late 2016 and continuing into 2018, but remain significantly below 2014 levels.
Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGL that we can produce
economically and may impact our ability to satisfy our obligations under firm-commitment transportation agreements. We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited, and we are not under an obligation to hedge a specific portion of our oil or natural gas production.
Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential liabilities, including environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development and acquisition of oil and natural gas reserves. We expect to fund our 2019 capital expenditures with borrowings under our revolving credit facility and possibly through asset sales or additional capital markets transactions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.”
Substantially all of our producing properties are located in the DJ Basin of Colorado, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the DJ Basin is an area of high industry activity, we may be unable to hire, train or retain qualified personnel needed to manage and operate our assets.
Substantially all of our producing properties are geographically concentrated in the DJ Basin of Colorado, an area in which industry activity has increased rapidly. At December 31, 2018, substantially all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors or other regional events, delays or interruptions of production from wells in this area caused by governmental regulation, including at the state and local level, processing or transportation capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGL. For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition, or results of operations.
Specifically, demand for qualified personnel in this area, and the cost to attract and retain such personnel, has increased over the past few years and may increase substantially in the future. Moreover, our competitors, including those operating in multiple basins, may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could have a negative effect on production volumes or significantly increase costs, which could have a material adverse effect on our results of operations, liquidity and financial condition.
Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes specific to the DJ Basin of Colorado, could have a material adverse effect on our business
Our business is subject to various forms of government regulation. Some local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and natural gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. Since that time, local district courts have struck down the ordinances for certain of those Colorado cities, and such decisions were upheld by the Colorado Supreme Court in May 2016. Nevertheless, there is a continued risk that cities will adopt local ordinances that seek to regulate the time, place, and manner of hydraulic fracturing activities and oil and natural gas operations within their respective jurisdictions.
In addition, in 2014, 2016 and 2018, opponents of hydraulic fracturing sought statewide ballot initiatives that would have restricted oil and gas development in Colorado. The 2014 initiatives were withdrawn in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and natural gas facilities, and none of the 2016 initiatives were successful. However, in 2018, the Colorado Secretary of State approved a citizen-initiated ballot measure, referred to as Prop. 112, for inclusion on the statewide voter ballot in November 2018. Prop. 112 sought to amend the Colorado Revised Statutes to increase setback distances by requiring that all new oil and gas development on non-federal lands (i.e. state and private lands) be located at least 2,500 feet away from certain occupied structures, including homes, schools and hospitals, as well as certain defined "vulnerable areas," including playgrounds, permanent sports fields, public parks and open spaces, public drinking water sources, reservoirs, lakes, rivers, perennial and intermittent streams, and creeks. In contrast, rules adopted and enforced by the COGCC currently require that wells and production facilities be located at least 500 feet away from homes and 1,000 feet away from certain defined high occupancy building units, including schools, subject to certain exceptions. The term "oil and gas development" was broadly defined under Prop. 112 to include oil and gas exploration, drilling, hydraulic fracturing, flowlines, production and processing activities, including the development and production activities central to our operations. Under Prop. 112, state and local governments would have been allowed to designate vulnerable areas beyond those that are defined in the measure, but the proposal provided no additional guidance on procedures or any limitations with respect to such designations. Prop. 112 further provided that the state or a local government may increase the setback to a distance larger than 2,500 feet, again without any defined procedure, limitations, or governing standards. The COGCC conducted a study in 2018 and determined that, if Prop. 112 had been approved by state voters, an estimated 54% of Colorado's total land surface would be unavailable for new oil and gas development, or 85% of all non-
federal lands. Focusing on Weld County, located in the DJ Basin, the 2018 COGCC study determined that approval and adoption of Prop. 112 would have precluded new oil and gas development on approximately 78% of the total land surface and 85% of the non-federal land surface in the county. If Prop. 112 were to have passed and become law in the State of Colorado, we would have likely encountered updates to our long-term forecast which could have negatively impacted future operating cash flows, credit facility re-determinations, minimum volume commitments and lead to potential non-cash impairments.
Although Prop. 112 was ultimately unsuccessful, similar efforts are likely to continue in the future, which, if successful, could result in dramatically reducing the area available for future oil and gas development in Colorado or outright banning oil and gas development in Colorado. We cannot predict the nature or outcome of future ballot initiatives or other similar efforts. If we are required to cease operating in any of the areas in which we now operate as the result of bans or moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results of operations.
Additionally, we are subject to laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells we drill, among other matters. In particular, our business utilizes a methodology available in Colorado known as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling spacing unit to apply to the Colorado Oil & Gas Conservation Commission ("COGCC") for an order forcing all other holders of oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. This methodology is especially important for our operations in the Greeley area, where there are many interest holders. Changes in the legal and regulatory environment governing our industry, particularly any changes to Colorado forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business, financial condition and results of operations.
Our cash flow from operations and access to capital are subject to a number of variables, including:
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our proved reserves;
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the level of hydrocarbons we are able to produce from existing wells;
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the prices at which our production is sold;
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the availability of takeaway capacity;
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our ability to acquire, locate and produce new reserves; and
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our ability to borrow under our revolving credit facility.
If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition and results of operations.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploitation, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production.
Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “-Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
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delays imposed by or resulting from compliance with environmental and other regulatory requirements including limitations on or resulting from wastewater discharge and disposal, subsurface injections, GHG emissions and hydraulic fracturing;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
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lack of available capacity on interconnecting transmission pipelines;
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equipment failures or accidents, such as fires or blowouts;
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lack of available gathering facilities or delays in construction of gathering facilities;
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adverse weather conditions, such as blizzards, tornados and ice storms;
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issues related to compliance with environmental and other governmental regulations;
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environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
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declines in oil, natural gas and NGL prices;
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limited availability of financing at acceptable terms;
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title problems or legal disputes regarding leasehold rights; and
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limitations in the market for oil, natural gas and NGL.
Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained or if existing producing wells that are holding leases with other potential locations cease to continue to produce in commercial quantities, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.
A substantial portion of our reserves are located in urban areas, which could increase our costs of development and delay production.
A substantial portion of our reserves are located in urban portions of the DJ Basin, which could disproportionately expose us to operational and regulatory risk in that area. Much of our operations are within the city limits of various municipalities in northeastern Colorado. In such urban and other populated areas, we may incur additional expenses, including expenses relating to mitigation of noise, odor and light that may be emitted in our operations, expenses related to the appearance of our facilities and limitations regarding when and how we can operate. The process of obtaining permits for drilling or for gathering lines to move our production to market in such areas may be more time consuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.
Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.
The marketing of oil and natural gas production depends in large part on the capacity and availability of trucks, pipelines and storage facilities, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If there is insufficient capacity available on these systems, or if these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise, especially in areas of planned expansion where such facilities do not currently exist. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, recent increases in activity in the DJ Basin have contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Additionally, we continued to experience constraints on the capacity available in certain pipelines that we use to transport natural gas and have been forced to shut in some production from time to time. Capacity constraints typically reduce the productivity of some of our older vertical wells and may on occasion limit incremental production from some of our newer horizontal wells. This constrains our production and reduces our revenue from the affected wells. Capacity constraints affecting natural gas production also impact the associated NGL. We are also dependent on the availability and capacity of oil purchasers for our production. Increases in the amount of oil that we transport out of the DJ Basin for sale would result in an increase in our transportation costs and would reduce the price we receive for the affected production.
Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the DJ Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.
While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these initiatives may be delayed or unsuccessful. As a result, our business, financial condition and results of operations could be adversely affected.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our debt arrangements contain a number of significant covenants, including restrictive covenants that may limit our ability to, among other things:
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incur additional indebtedness;
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sell assets;
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make loans to others;
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make certain acquisitions and investments;
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enter into mergers, consolidations or other transactions resulting in the transfer of all or substantially all of our assets;
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make certain payments, including paying dividends or distributions in respect of our equity;
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hedge future production or interest rates;
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redeem and prepay other debt;
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incur liens; and
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engage in certain other transactions without the prior consent of the lenders.
In addition, our debt arrangements require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our debt arrangements will impose on us.
Our revolving credit facility limits the amount we can borrow up to the lower of our aggregate lender commitments and a borrowing base amount, which the lenders, in their sole discretion, will determine on a semi-annual basis based upon projected revenues from the oil and natural gas properties securing our loan. The lenders will be able to unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders does not agree to a proposed borrowing base, then the borrowing base will be the highest borrowing base acceptable to such lenders. We will be required to repay outstanding borrowings in excess of the borrowing base. Our borrowing base is $1.2 billion, subject to the current maximum lending commitments of $650.0 million.
A breach of any covenant in our revolving credit facility will result in a default under the revolving credit facility after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the facility and a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. In addition, our obligations under our revolving credit facility are secured by perfected first priority liens and security interests on substantially all of our assets, including mortgage liens on oil and natural gas properties having at least 90% of the reserve value as determined by reserve reports, and if we are unable to repay our indebtedness under the revolving credit facility, the lenders could seek to foreclose on our assets.
We may be subject to risks in connection with divestitures
In 2018, we completed divestitures of several of our non-strategic assets and we have additional divestitures pending, as discussed in Item. "Business-Recent Developments." In addition, in 2019 we announced our ongoing initiative to divest of non-strategic assets in order to increase capital resources available for other core assets, create organizational and operational efficiencies or for other purposes. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchases willing to acquire the assets with terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific action.
Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving credit facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If oil and natural gas prices remain at their current level for an extended period of time or decline, we may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or
operations to meet debt service and other obligations. Our revolving credit facility and the indentures governing our 2024 Notes and 2026 Notes currently restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas and NGL, we enter into commodity derivative contracts for a significant portion of our production, primarily consisting of swaps, put options and call options. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Overview-Sources of Our Revenues.” Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
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the counterparty to the derivative instrument defaults on its contractual obligations;
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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
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there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas and NGL, which could also have an adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. While we utilize multiple counterparties, if the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of December 31, 2018 were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $65.56/Bbl for oil and $3.10/MMBtu for natural gas, which for certain periods of 2018 were substantially above the available spot oil and natural gas prices. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.
There is a limited amount of production data from horizontal wells completed in the DJ Basin. As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.
Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontal drilling in the DJ Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in this area for over 50 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small compared to that of production data from vertical wells. Until a greater number of horizontal wells have been completed in the DJ Basin, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories. We cannot assure you that any such variance would not be material and any such variance could have a material and adverse impact on our cash flows and results of operations. If our horizontal wells do not allow for the extraction of oil and natural gas in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects.
Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. During the year ended December 31, 2018, we have drilled 286 gross one-mile equivalent horizontal wells and have completed 268 gross one-mile equivalent horizontal wells, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. In addition, our horizontal drilling activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
Approximately 56% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
As of December 31, 2018, approximately 56% of our net leasehold acreage was undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.
We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of actual volume throughput.
We may enter into firm transportation, gas processing, gathering and compression service, water handling and treatment, or other agreements that require minimum volume delivery commitments. Our oil marketer is subject to a firm transportation agreement that commenced in November 2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, we amended this agreement with our oil marketer that requires us to sell all of our crude oil from an area of mutual interest in exchange for a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. In December 2017, we extended the term of this agreement through October 31, 2019 and posted a letter of credit in the amount of $35.0 million. We are currently in the process of amending and extending this agreement. We evaluate our contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. We also have two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which we have a minority ownership interest. The first agreement commenced in November 2016 and has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The second agreement will commence in or around July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The remaining aggregate amount of estimated payments under these agreements is approximately $875.8 million. If we have insufficient production to meet the minimum volumes under this agreement or any other firm commitment agreement we may enter into, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results or operations.
The prices we receive for our production may be affected by local and regional factors.
The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process, and transport, our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.
Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.
Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as winter storms, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.
SEC rules could limit our ability to book additional PUDs in the future.
SEC rules require that, subject to limited exceptions, PUDs may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
At December 31, 2018, approximately 60% of our total estimated proved reserves were classified as proved undeveloped. The development of our estimated proved undeveloped reserves of 208,395 MBoe will require an estimated $1.9 billion of development capital over the next five years.
Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The future development of our proved undeveloped reserves is dependent on future commodity prices, costs and economic assumptions that align with our internal forecast, as well as access to liquidity sources, such as the capital markets, our revolving credit facility and derivative contracts. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.
We own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.
We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.
We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.
As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors such as lease expirations, changes in drilling plans and adverse drilling results, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. If market or other economic conditions deteriorate or if oil, natural gas and NGL prices continue to decline, we may incur impairment charges in 2019 or later periods, which may have a material adverse effect on our results of operations.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or
acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
Conservation measures and technological advances could reduce demand for oil, natural gas and NGL.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGL, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGL. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGL we produce.
The availability of a ready market for any oil, natural gas and NGL we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. See “Business-Operations-Marketing and Customers.” We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.
The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.
We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. Two, three and four purchasers accounted for more than 10% of our revenues in the years ended December 31, 2018, 2017 and 2016, respectively. This concentration of purchasers may impact our overall credit risk in that these entities may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.
Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, natural gas leaks, pipeline and tank ruptures or unauthorized discharges of toxic gases or other pollutants.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and other environmental risks generally are not fully insurable. The occurrence of an event that is not covered or fully covered by insurance and any delay in the payment of
insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.
Properties that we decide to drill may not yield oil, natural gas or NGL in commercially viable quantities.
Properties that we decide to drill that do not yield oil, natural gas or NGL in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failure or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or contractual requirements; and
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increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of oil and gas properties or businesses that complement or expand our current business. The successful acquisition of oil and gas properties requires an assessment of several factors, including:
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recoverable reserves;
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future oil, natural gas and NGL prices and their applicable differentials;
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operating costs; and
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potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our debt arrangements will impose certain limitations on our ability to enter into mergers or combination transactions. Our debt arrangements will also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
We are subject to stringent environmental and health and safety laws and regulations that could expose us to significant costs and liabilities.
Our oil and natural gas exploration, development and production operations are subject to numerous stringent and complex federal, state and local laws and regulations governing safety and health aspects of our operations, the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting drilling and other regulated activities; the restriction of types, quantities and concentration of materials that may be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring costly actions. For example, on May 2, 2017, following an incident in Firestone, Colorado, the COGCC issued a Notice to Operators (the “Notice”) that, among other things, required operators of oil and natural gas wells in Colorado: (i) by May 30, 2017, to re-inspect all existing flowlines and pipelines located within 1,000 feet of a defined “building unit,” which term includes residences and certain commercial facilities, to identify the well API number and tank battery location ID number associated with each line; (ii) by May 30, 2017, to inspect all existing flowlines and pipelines, regardless of distance to a “building unit,” to verify that any existing flowline or pipeline not in use, regardless of when it was installed or taken out of service, is abandoned in conformity with applicable rules; (iii) by June 30, 2017, to ensure and document that all flowlines within 1,000 feet of a “building unit” have integrity; and (iv) by June 30, 2017, to complete abandonment of any flowline or pipeline not actively operated, regardless of distance to a “building unit,” and regardless of when it was installed or taken out of service, in conformity with the applicable rules and the Notice. In August 2017, the Governor of Colorado announced several policy initiatives designed to enhance public safety that are to be implemented through rulemaking or legislation. On February 13, 2018, the COGCC approved new oil and natural gas flowline requirements, which include: (i) requirements for more-detailed tracking, location data, and record-keeping for flowlines that carry fluids away from a specific oil and gas location; (ii) requirements that any flowlines not in use, but not yet abandoned, are locked and marked and must continue to undergo integrity testing under the same standards as active lines until abandonment, and any risers associated with abandoned flowlines must be cut below grade; (iii) more-detailed requirements for operators to demonstrate flowline integrity, including updated standards for integrity-testing lines, more testing options that align with newer technology, and the elimination of pressure-testing exemptions for low-pressure lines; and (iv) requirements for full operator participation in the Utility Notification Center of Colorado’s “one-call” program to ensure a centralized home for all data on flowline locations and access to that information through the established 811 “call-before-you-dig” system. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory, remedial or corrective obligations, the occurrence of delays in permitting or development of projects and the issuance of orders limiting or prohibiting some or all of our operations in a particular area or forcing future compliance with environmental requirements.
The performance of our operations may result in significant environmental costs and liabilities due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances could expose us to material losses, expenditures and liabilities under environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. We may not be able to recover some or any of our costs with respect to such developments from
insurance. See “Business-Regulation of Environmental and Safety and Health Matters” for a further description of environmental and safety and health laws and regulations that affect us.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, natural gas and NGL prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EPAct 2005, FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1.0 million per day for each violation. FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the FTC has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1.0 million per day, and the CFTC prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business-Regulation of the Oil and Gas Industry.”
We may be involved in legal proceedings that could result in substantial liabilities.
Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Additionally, citizen groups have brought and, in certain instances, may continue to bring legal proceedings against us to challenge our ability to receive environmental permits that we need to operate. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, loss of necessary environmental permits, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.
Climate change legislation or regulations restricting emissions of GHG could result in increased operating costs and reduced demand for the oil, natural gas and NGL that we produce.
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes and 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 adopted rules under authority of the CAA that, among other things, establish PSD construction and Title V permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards for those emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among other things, onshore producing facilities, which include certain of our operations. Federal agencies also have begun directly regulating emissions of methane from oil and natural gas operations,
with the EPA publishing NSPS Subpart OOOOa standards in June 2016 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 and the BLM publishing requirements in November 2016 to reduce methane emissions from venting, flaring, and leaking on public lands. In September 2018, both of the EPA and BLM took steps to relax or rescind certain requirements under their respective methane rules. EPA proposed amendments that would relax requirements of the NSPS OOOOa standards and BLM issued a rule that relaxes or rescinds requirements of its November 2016 regulations. California and New Mexico have challenged BLM's September 2018 rule in ongoing litigation. 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 preparing 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. In follow-up to an earlier announcement by President Trump, in August 2017, the U.S. Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHG or otherwise limit emissions of GHG from, our equipment and operations could result in increased costs to reduce emissions of GHG associated with our operations as well as delays or restrictions in our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil, natural gas and NGL we produce and lower the value of our reserves, which devaluation could be significant. One or more of these developments could have a materially adverse effect on our business, financial condition and results of operations. Finally, notwithstanding potential risks related to climate change, the International Energy Agency, an autonomous intergovernmental organization involved in international energy policy, estimates that global energy demand will continue to rise and will not peak until after 2040 and oil and gas will continue to represent a substantial percentage of global energy use over that time. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector. Please read “Business-Regulation of Environmental and Safety and Health Matters-Regulation of Greenhouse Gas (“GHG”) Emissions” for a further description of the laws and regulations relating to climate change that affect us.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions or similar state agencies but several federal agencies have asserted regulatory authority over certain aspects of the process. In addition, 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. Also, from time to time, the U.S. Congress has considered, but not adopted, legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. At the state level, Colorado, where we conduct operations, is among the states that has adopted, and other states are considering adopting, regulations that impose new or more stringent permitting, disclosure or well-construction requirements on hydraulic fracturing operations. States may elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York. In addition to state laws, local land use restrictions may restrict drilling or the hydraulic fracturing and cities may adopt local ordinances allowing hydraulic fracturing activities within their jurisdictions but regulating the time, place and manner of those activities. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, including, for example, on federal and American Indian lands, we could incur potentially significant added cost to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Moreover, because most of our operations are conducted in a particular area, the DJ Basin in Colorado, legal restrictions imposed in that area will have a significantly greater adverse effect than if we had our operations spread out amongst several diverse geographic areas. Consequently, in the event that local or state restrictions or prohibitions are adopted
in the DJ Basin in Colorado that impose more stringent limitations on the production and development of oil and natural gas, we may incur significant costs to comply with such requirements or may experience delays or curtailment in the pursuit of exploration, development, or production activities, and possibly be limited or precluded in the drilling of wells or in the amounts that we are ultimately able to produce from our reserves. Any such increased costs, delays, cessations, restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
Please read “Business-Regulation of Environmental and Safety and Health Matters-Hydraulic Fracturing Activities” for a further description of the laws and regulations relating to hydraulic fracturing that affect us.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows.
Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.
We have grown rapidly since we began operations in late 2012. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
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increased responsibilities for our executive level personnel;
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increased administrative burden;
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increased capital requirements; and
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increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.
Adverse weather conditions may negatively affect our operating results and our ability to conduct drilling activities.
Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of our oil, natural gas and NGL. Any decreases in production due to poor weather conditions will have an adverse effect on our revenues, which will in turn negatively affect our cash flow from operations.
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 deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. Drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources, we may be unable to produce oil, natural gas and NGL economically, which could have an adverse effect on our financial condition, results of operations and cash flows.
Restrictions on drilling activities intended to protect certain species of wildlife and natural resources may adversely affect our ability to conduct drilling activities areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife and natural resources. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered 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 a material adverse impact on our ability to develop and produce our reserves.
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.
The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In its rulemaking under the Dodd-Frank Act, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, the CFTC and certain banking regulators have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and CFTC rules, 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 Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGL. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.
Recent changes in United States federal income tax law may have an adverse effect on our cash flows, results of operations or financial condition overall.
The final version of the tax reform bill commonly known as the Tax Cuts and Jobs Act (the "TCJA") signed into law on December 22, 2017 may affect our cash flows, results of operations and financial condition. Among other items, the TCJA repealed the deduction for certain U.S. Production activities and provided for a new limitation on the deduction for interest expense. Given the scope of this law and the potential interdependency of its changes, it is difficult at this time to assess whether the overall effect of the TCJA will be cumulatively positive or negative for our earnings and cash flow, but such changes may adversely impact our financial results.
Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Although none of these changes were included in the TCJA, future adverse changes could include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.
We may not be able to keep pace with technological developments in our industry.
The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at
substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Our business could be negatively affected by security threats, including cybersecurity threats, destructive forms of protest and opposition by activists and other disruptions.
As an oil and natural gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information, to misappropriate financial assets or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of financial assets, sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability. In addition, destructive forms of protest and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and gas production and activities could potentially result in damage or injury to people, property or the environment or lead to extended interruptions of our operations, adversely affecting our financial condition and results of operations.
Loss of our information and computer systems could adversely affect our business.
We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Risks Related to our Common Stock
The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
We completed our IPO in October 2016. As a public company, we must comply with various laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NASDAQ, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We are now required to:
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institute a more comprehensive compliance function;
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comply with rules promulgated by the NASDAQ;
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continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
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establish new internal policies, such as those relating to insider trading; and
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involve and retain to a greater degree outside counsel and accountants in the above activities.
Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations.
Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if in the future we or our independent registered public accounting firm identifies deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses, the market price of our stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities, which would require additional financial and management resources.
In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. If one or more material weaknesses emerge related to financial reporting, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock.
Yorktown’s funds collectively hold a substantial portion of the voting power of our common stock.
Yorktown’s funds currently collectively hold approximately 28% of our common stock. See “Security Ownership of Certain Beneficial Owners and Management” for more information regarding ownership of our common stock by the Yorktown funds. The existence of affiliated stockholders with significant aggregate holdings that may act as a group may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, this concentration of stock ownership may adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with affiliated stockholders with significant aggregate holdings that may act as a group.
Conflicts of interest could arise in the future between us, on the one hand, and Yorktown and its affiliates, including its funds and their respective portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities.
Yorktown’s funds are in the business of making investments in entities in the U.S. energy industry. As a result, Yorktown’s funds may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. Yorktown’s funds and their respective portfolio companies may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, Yorktown’s funds and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock in addition to the Series A Preferred Stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
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limitations on the removal of directors;
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limitations on the ability of our stockholders to call special meetings;
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establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and
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providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws.
We do not intend to pay dividends on our common stock, and our debt arrangements and the Series A Preferred Stock place certain restrictions on our ability to do so. Consequently, it is possible that the only opportunity to achieve a return on an investment in our common stock will be if the price of our common stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our debt arrangements and the Series A Preferred Stock restrict our ability to pay cash dividends. Consequently, it is possible that the only opportunity to achieve a return on an investment in our common stock will be if shareholders sell their common stock at a price greater than they paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that such investors paid for our common stock.
Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute the ownership in us by current shareholders.
We may sell additional shares of common stock in public or private offerings. We may also issue additional shares of common stock or convertible securities. Excluding any shares of common stock issued upon the conversion of our Series A Preferred Stock including any shares of Series A Preferred Stock that may be issued pursuant to our option to pay dividends on the Series A Preferred Stock in kind pursuant to the terms of the Certificate of Designations setting forth the terms of the Series A Preferred Stock, we have 171,666,485 outstanding shares of common stock as of December 31, 2018. In connection with the IPO, we filed a registration statement with the SEC on Form S-8 providing for the registration of 23,000,000 shares of our common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction. Additionally, the Series A Preferred Stock are convertible into shares of our common stock pursuant to their terms.
We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
We may issue additional preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock, including the Series A Preferred Stock, could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim for a breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments from the SEC staff regarding our periodic or current reports under the Exchange Act.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may be involved in litigation relating to claims arising out of our business and operations in the normal course of business. While the outcomes of these proceedings cannot be predicted with certainty, we do not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.
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
Market Information.
Our common stock is currently traded on the NASDAQ under the ticker symbol “XOG.”
Dividend Policy
We have not historically paid, and do not anticipate paying any cash dividends in the future, to common stockholders of our common stock. In addition, our revolving credit facility, our Senior Notes (collectively, our “debt arrangements”) and the Series A Preferred Stock place certain restrictions on our ability to pay cash dividends. Please see Note 5 - Long Term Debt included in the notes to the consolidated financial statements included elsewhere in this Annual Report for more information regarding the restrictions placed on our ability to pay cash dividends.
Comparison of Cumulative Return
The following graph compares the cumulative total shareholder return on a $100 investment in our common stock on October 12, 2016 through December 31, 2018, to that of the cumulative return on a $100 investment in the S&P 500 Composite for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. The indices are included for comparative purpose only. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.
Holders
Pursuant to the records of the transfer agent, as of February 19, 2019, the number of holders of record of our common stock was 60.
Sales of Unregistered Securities
We did not have any sales of unregistered securities during the fiscal year ended December 31, 2018.
Issuer Purchases of Equity Securities
The following table sets forth our share repurchase activity for each period presented:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data as of and for the five-years ended December 31, 2018. The data as of and for the fiscal years ended December 31 for each respective year was derived from our historical consolidated financial statements and the accompanying notes included elsewhere in this Annual Report.
The following selected consolidated financial information 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 and analysis should be read in conjunction with our consolidated financial statements and related notes appearing in “Item 8. Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
OVERVIEW
We are an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves, as well as the construction and support of midstream assets to gather and process crude oil and gas production in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. We have developed an oil, natural gas and NGL asset base of proved reserves, as well as a portfolio of development drilling opportunities on high resource-potential leasehold on contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin. We are focused on growing our proved reserves and production primarily through the development of our large inventory of identified liquids-rich horizontal drilling locations.
Our Properties
We have assembled, as of December 31, 2018, approximately 179,300 net acres of large, contiguous acreage blocks in some of the most productive areas of what we consider to be the core of the DJ Basin as indicated by the results of our horizontal drilling program and the results of offset operators. Additionally, we hold approximately 138,100 net acres outside of what we consider our Core DJ Basin, which we refer to as our “Other Rockies Area,” that we believe is prospective for many of the same formations as our properties in the Core DJ Basin. We operated 96% of our horizontal production for the year ended December 31, 2018, our total estimated proved reserves were approximately 347.9 MMBoe, of which approximately 40% were classified as proved developed reserves. For more information about our properties, please read “Business-Our Properties.” in Items 1. and 2. of this Annual Report.
Financial Overview
For the year ended December 31, 2018, we had net income of $121.9 million as compared to a net loss of $44.4 million for the year ended December 31, 2017. The change to net income was primarily driven by an increase in sales revenues of $456.4 million, partially offset by an increase in operating expenses of $119.1 million, which includes the gain on sale of property and equipment and assets of unconsolidated subsidiary of $136.8 million. Additionally, we had an increase in interest expense of $71.4 million, which includes a make-whole premium of $35.6 million and $9.4 million of accelerated amortization expense upon the redemption of our 2021 Senior Notes.
For the year ended December 31, 2018, crude oil, natural gas and NGL sales, coupled with the impact of settled derivatives, increased to $930.1 million as compared to $585.7 million in the same prior year period due to an increase in sales volumes of 8,853 MBoe and an increase of $2.52 in realized price per BOE, including settled derivatives.
Adjusted EBITDAX was $659.8 million for the year ended December 31, 2018, as compared to $380.5 million in the same period in 2017, reflecting a 73% increase. Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation to our most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Adjusted EBITDAX.”
Operational Overview
During the year ended December 31, 2018, we continued to focus on growing production while at the same time implementing operational efficiencies to reduce drilling and completion costs. We incurred approximately $776.1 million in drilling 161 gross (129.7 net) wells with an average lateral length of 1.8 miles and completing 161 gross (137.4 net) wells with an average lateral length of 1.7 miles, all of which were horizontal wells in the DJ Basin. In addition, we incurred approximately $116.4 million of leasehold and surface acreage additions, excluding acquisitions. These capital expenditures exclude the impact of the decrease in outstanding elections of $6.7 million. In addition, Elevation Midstream, LLC, our wholly owned midstream subsidiary, incurred $108.2 million of capital expenditures.
Income Taxes
On December 22, 2017, the TCJA was enacted making significant changes to the Internal Revenue Code. Many of the provisions in the TCJA have an effective date for years beginning after December 31, 2017, including the lowering of the U.S. corporate rate from 35% to 21%. As a result of the enactment date of December 22, 2017, we were required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. We provisionally recorded an income tax benefit in the amount of $23.4 million related to the remeasurement of the net deferred tax liability as of December 31, 2017. During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. There are no remaining provision amounts associated with the TCJA as of December 31, 2018.
In connection with the IPO in October 2016, our accounting predecessor, Extraction Oil & Gas Holdings, LLC ("Holdings") was merged into the Company. Prior to this corporate reorganization, we were not subject to federal or state income taxes. Accordingly, the financial data attributable to us prior to such corporate reorganization contain no provision for federal or state income taxes because the tax liability with respect to Holdings’ taxable income was passed through to our members. Beginning October 12, 2016, we began to be taxed as a C corporation under the Code, prior to the TCJA enactment, and subject to federal and state income taxes at a blended statutory rate of approximately 38% of pretax earnings.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and gas operations, including:
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Sources of revenue;
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Sales volumes;
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Realized prices on the sale of oil, natural gas and NGL, including the effect of our commodity derivative contracts;
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Lease operating expenses (“LOE”);
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Capital expenditures; and
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Adjusted EBITDAX (a Non-GAAP measure).
Sources of Our Revenues
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives. For the year ended December 31, 2018, our revenues were derived 79% from oil sales, 10% from natural gas sales and 11% from NGL sales. For the year ended December 31, 2017, our revenues were derived 70% from oil sales, 15% from natural gas sales and 15% from NGL sales. For the year ended December 31, 2016, our revenues were derived 70% from oil sales, 17% from natural gas sales and 13% from NGL sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
Sales Volumes
The following table presents historical sales volumes for our properties for the periods indicated:
As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add or develop proved reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through organic growth as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including takeaway capacity in our areas of operation and our ability to raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. We estimate that midstream constraints negatively impacted our production by approximately 18.5 MBOE/d, or 24%, during the year ended December 31, 2018. We are currently working with various midstream providers to address processing constraints in the DJ Basin. Please read “Risks Related to the Oil, Natural Gas and NGL Industry and Our Business” in Item 1A. of this Annual Report for a further description of the risks that affect us.
Realized Prices on the Sale of Oil, Natural Gas and NGL
Our results of operations depend upon many factors, particularly the price of oil, natural gas and NGL and our ability to market our production effectively. Oil, natural gas and NGL prices are among the most volatile of all commodity prices. For example, during the period from January 1, 2014 to December 31, 2018, average daily prices for NYMEX West Texas Intermediate oil prices ranged from a high of $107.26 per Bbl to a low of $26.21 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $6.15 per MMBtu to a low of $1.64 per MMBtu during the same period. Declines in, and continued depression of, the price of oil and natural gas occurring during 2015 and also during 2018 are due to a combination of factors including increased U.S. supply, global economic concerns and geopolitical risks. These price variations can have a material impact on our financial results and capital expenditures.
Oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. The NYMEX WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. In the DJ Basin, oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials.
Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. For example, wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGL. Location differentials to NYMEX Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant, generally in the form of percentage of proceeds. The price we receive for our natural gas produced in the DJ Basin is based on CIG prices, adjusted for certain deductions.
Our price for NGL produced in the DJ Basin is based on a combination of prices from the Conway hub in Kansas and Mont Belvieu in Texas where this production is marketed.
The following table provides the high and low prices for NYMEX WTI and NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated. The differential varies, but our oil, natural gas and NGL normally sells at a discount to the NYMEX WTI and NYMEX Henry Hub price, as applicable.
(1)
Based on the difference between our average realized price and the NYMEX Henry Hub Average as converted into Mcf using a conversion factor of 1.1 to 1.
(2)
As a result of the adoption of ASC 606 - Revenue from Contracts with Customers ("ASC 606") on January 1, 2018, certain costs previously classified as transportation and gathering expenses are presented on a net basis for proceeds expected to be received. See "-Historical Results of Operations and Operating Expense" for more information.
Derivative Arrangements
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our oil and natural gas production. By removing a significant portion of price volatility associated with our oil production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil prices on our cash flow from operations for those periods. However, in a portion of our current positions, our hedging activity may also reduce our ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will realize gains to the extent our derivatives contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our derivative portfolio, we may choose to restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. See “-Quantitative and Qualitative Disclosure About Market Risk-Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and our commodity derivative contracts.
We will continue to use commodity derivative instruments to hedge our price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. As a result of recent volatility in the price of oil and natural gas, we have relied on a variety of hedging strategies and instruments to hedge our future price risk. We have utilized swaps, put options, and call options, which in some
instances require the payment of a premium, to reduce the effect of price changes on a portion of our future oil and natural gas production. We expect to continue to use a variety of hedging strategies and instruments for the foreseeable future.
A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of our purchased put options have deferred premiums. For the deferred premium puts, we agreed to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
We combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging strategies. Some examples of our hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options, and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap. We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices.
We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements at favorable prices may be limited, and we are not obligated to hedge a specific portion of our oil or natural gas production. The following summarizes our derivative positions related to crude oil and natural gas sales in effect as of December 31, 2018:
The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated.
Lease Operating Expenses
All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, superintendence, supplies, repairs, maintenance, water injection and disposal costs, allocated overhead charges, workover, insurance and other expenses incidental to production, but exclude lease acquisition or drilling or completion expenses.
Capital Expenditures
For the year ended December 31, 2018, we incurred approximately $776.1 million in capital expenditures, excluding outstanding elections, in drilling 161 gross (129.7 net) wells with an average lateral length of 1.8 miles and completing 161 gross (137.4 net) wells with an average lateral length of 1.7 miles. In addition, we incurred approximately $116.4 million of leasehold and surface acreage additions, excluding acquisitions. These capital expenditures exclude the impact of the decrease in outstanding elections of $6.7 million. In addition, Elevation, our wholly owned midstream subsidiary, incurred $108.2
million of capital expenditures for the year ended December 31, 2018. Our 2018 revised capital budget allocated approximately $770 million to $840 million to the drilling of 168 to 173 gross operated wells, completion of between 170 to 175 gross operated wells and turned to sales between 163 to 168 gross operated wells. Approximately $120 million to $150 million was allocated to acreage leasing, midstream and other capital expenditures, excluding amounts that were paid for acquisitions.
Our 2019 capital budget for the drilling and completion of operated and non-operated wells is approximately $585.0 million to $675.0 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 125 gross operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. Our capital budget anticipates a one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party and any amounts that may be paid for potential acquisitions.
The amount and timing of these capital expenditures is within our control and subject to our management’s discretion. We retain the flexibility to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil, natural gas and NGL, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. Any postponement or elimination of our development drilling program could result in a reduction of proved reserve volumes and related standardized measure. These risks could materially affect our business, financial condition and results of operations.
Adjusted EBITDAX
Adjusted EBITDAX is not a measure of net income (loss) as determined by United States generally accepted accounting principles ("GAAP"). Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) adjusted for certain cash and non-cash items, including depletion, depreciation, amortization and accretion ("DD&A"), impairment of long lived assets and goodwill, exploration expenses, rig termination fees, write off of deposit on acquisition, (gain) loss on sale of property and equipment, gain on sale of assets of unconsolidated subsidiaries, acquisition transaction expenses, (gain) loss on commodity derivatives, settlements on commodity derivative instruments, premiums paid for derivatives that settled during the period, unit and stock-based compensation expense, amortization of debt discount and debt issuance costs, make-whole premiums, interest expense, income tax expense (benefit) and non-recurring charges. Adjusted EBITDAX is also used to evaluate the performance of reportable segments. See Note 15 - Segment Information in Item 8 in this Annual Report for more information regarding the EBITDAX of reportable segments.
Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital, hedging strategy and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measure of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance. Additionally, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
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is widely used by investors in the oil and natural gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, among other factors;
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helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure from our operating structure; and
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is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation.
The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated (in thousands).
Items Affecting the Comparability of Our Financial Results
Our historical results of operations for the periods presented may not be comparable, either to each other or to our future results of operations, for the reasons described below:
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For the year ended December 31, 2018, we recognized $136.8 million gain on sale of property and equipment and assets of unconsolidated subsidiary related to our April 2018 Divestitures, August 2018 Divestiture and December 2018 Divestitures. We also recognized $54.2 million in impairment of goodwill resulting from the conclusion that the fair value of the reporting unit was not greater than its carrying amount and $16.2 million related to impairment of the proved oil and gas properties in our northern field.
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On December 22, 2017, the TCJA was enacted making significant changes to the Internal Revenue Code. Many of the provisions in the TCJA have an effective date for years beginning after December 31, 2017, including the lowering of the U.S. corporate rate from 35% to 21%. As a result of the enactment date of December 22, 2017, we were required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. We provisionally recorded an income tax benefit in the amount of $23.4 million related to the remeasurement of the net deferred tax liability as of December 31, 2017. During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. There are no remaining provision amounts associated with the TCJA as of December 31, 2018.
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In connection with the consummation of the IPO, we issued 185,280 shares of our Series A Preferred Stock to the holders of Holdings’ Series B Preferred Units in conversion of such units. The Series A Preferred Stock are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are paid in cash).
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We incur additional general and administrative expenses related to being a public company, including Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with listing on the NASDAQ Global Select Market; incremental independent auditor fees; incremental legal fees; investor relations expenses; registrar and transfer agent fees; incremental director and officer liability insurance costs; and directors compensation.
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Prior to our initial public offering, we were not subject to federal or state income taxes. Accordingly, the financial data attributable to us prior to such corporate reorganization contain no provision for federal or state income taxes because the tax liability with respect to Holdings’ taxable income was passed through to its members. Beginning October 12, 2016, we began to be taxed as a C corporation under the Code and subject to federal and state income taxes at a blended statutory rate of approximately 38% of pretax earnings. As a result of the TCJA, we were subject to federal and state income taxes at a blended statutory rate of approximately 24.7% of pretax earnings for the years ended December 31, 2018 and 2017.
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In October 2016, our board of directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan ("LTIP") and subsequently granted awards to certain directors, officers and employees, including stock options, restricted stock units and performance stock awards. We recognized $48.7 million, $48.3 million and $8.5 million of stock-based compensation expense for years ended December 31, 2018, 2017 and 2016, respectively, related to these awards.
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On October 3, 2016, we acquired additional oil and gas properties primarily located in the Wattenberg Field located primarily around our existing Greeley and Windsor areas. The October 2016 Acquisition consisted of working interest in approximately 6,400 net acres and 31 gross (19 net) drilled but uncompleted wells, as of the date of acquisition. The October 2016 Acquisition provided net daily production of approximately 6,900 BOE/d during the fourth quarter of 2016.
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In 2015, we granted certain members of management incentive units pursuant to Holdings’ 2014 Membership Unit Incentive Plan and its limited liability company agreement. These equity-based awards were subject to time-based vesting requirements, as well as accelerated vesting upon the occurrence of a change of control. In connection with the IPO, the Board of Managers of Holdings accelerated the vesting of the Holdings’ Incentive Units. Our IPO and change of control triggered the conversion of these units into approximately 9.1 million of our common shares based on the 10-day volume weighted average price of our common stock following its IPO as set forth in the 2014 Plan and the Holdings LLC Agreement. For the year ended December 31, 2016, we recognized approximately $172.1 million in non-cash, unit-based compensation expense in connection with the conversion of the Holdings’ Incentive Units into our common stock.
Historical Results of Operations and Operating Expenses
Oil, Natural Gas and NGL Sales Revenues, Operating Expenses and Other Income (Expense).
The following table provides the components of our revenues, operating expenses, other income (expense) and net income (loss) for the periods indicated (in thousands):
The following table provides a summary of our sales volumes, average prices and operating expenses on a per BOE basis for the periods indicated:
(1)
One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
(2)
Average prices shown in the table reflect prices both before and after the effects of our settlements of our commodity derivative contracts. Our calculation of such effects includes both gains and losses on cash settlements for commodity derivatives and premiums paid or received on options that settled during the period.
(3)
As a result of the adoption of ASC 606 on January 1, 2018, certain costs previously classified as transportation and gathering expenses are presented on a net basis for proceeds expected to be received. See below for further information.
(4)
Excludes (gain) loss on sale of property and equipment, gain on sale of assets of unconsolidated subsidiary, other operating expenses and acquisition transaction expenses.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Oil sales revenues. Crude oil sales revenues increased by $420.8 million to $840.7 million for the year ended December 31, 2018 as compared to crude oil sales of $419.9 million for the year ended December 31, 2017. An increase in sales volumes between these periods contributed to a $222.6 million positive impact, while an increase in crude oil prices contributed a $198.2 million positive impact.
For the year ended December 31, 2018, our crude oil sales averaged 40.2 MBbl/d. Our crude oil sales volumes increased 53% to 14,679 MBbl for the year ended December 31, 2018 compared to 9,594 MBbl for the year ended December 31, 2017. The volume increase was primarily due to an increase in production from the completion of 161 wells for the year ended December 31, 2018. The increased production from these new wells was partially offset by the natural decline of our existing producing properties.
The average price we realized on the sale of crude oil was $57.27 per Bbl for the year ended December 31, 2018 compared to $43.77 per Bbl for the year ended December 31, 2017.
Natural gas sales revenues. Natural gas sales revenues increased by $13.3 million to $105.6 million for the year ended December 31, 2018 as compared to natural gas sales revenues of $92.3 million for the year ended December 31, 2017. An increase in sales volumes between these periods contributed a $41.2 million positive impact, while a decrease in natural gas prices contributed a $27.9 million negative impact. The decrease in pricing is partially attributable to our adoption of ASC 606. Adoption of this new standard was applied to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. Amounts previously recognized as transportation and gathering ("T&G") under ASC 605 of $15.6 million are currently recognized within natural gas sales revenues.
For the year ended December 31, 2018, our natural gas sales averaged 128.3 MMcf/d. Natural gas sales volumes increased by 45% to 46,847 MMcf for the year ended December 31, 2018 as compared to 32,395 MMcf for the year ended December 31, 2017. The volume increase was primarily due to the completion of 161 gross wells for the year ended December 31, 2018, partially offset by the natural decline on existing producing properties.
The average price we realized on the sale of our natural gas was $2.25 per Mcf for the year ended December 31, 2018 compared to $2.85 per Mcf for the year ended December 31, 2017.
NGL sales revenues. NGL sales revenues increased by $22.3 million to $114.4 million for the year ended December 31, 2018 as compared to NGL sales revenues of $92.1 million for the year ended December 31, 2017. An increase in sales volumes between these periods contributed a $32.0 million positive impact, while a decrease in price contributed a $9.7 million negative impact. The decrease in pricing is partially attributable to our adoption of ASC 606. Adoption of this new standard was applied to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. Amounts previously recognized as T&G under ASC 605 of $20.1 million are currently recognized within NGL sales revenues.
For the year ended December 31, 2018, our NGL sales averaged 14.4 MBbl/d. NGL sales volumes increased by 36% to 5,260 MBbl for the year ended December 31, 2018 as compared to 3,901 MBbl for the year ended December 31, 2017. The volume increase is primarily due to the completion of 161 gross wells for the year ended December 31, 2018, partially offset by the natural decline on existing producing properties. Our NGL sales are directly associated with our natural gas sales because our natural gas volumes are processed by third parties for both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $21.75 per Bbl for the year ended December 31, 2018 compared to $23.60 per Bbl for the year ended December 31, 2017.
Lease operating expenses ("LOE"). Our LOE, increased by $19.0 million to $79.4 million for the year ended December 31, 2018, from $60.4 million for the year ended December 31, 2017. The increase in LOE was primarily the result of an increase in producing wells and an increase in equipment rental and other service rates, partially offset by optimization of our field cost structure for the year ended December 31, 2018.
On a per unit basis, LOE decreased to $2.86 per BOE sold for the year ended December 31, 2018 from $3.19 per BOE sold for the year ended December 31, 2017. The decrease in LOE per BOE is primarily a result of flush production on several new pads turned-in-line for the year ended December 31, 2018.
Transportation and gathering. Our T&G expense decreased by $11.5 million to $39.4 million for the year ended December 31, 2018, from $50.9 million for the year ended December 31, 2017. The decrease in T&G is primarily attributable to adoption of ASC 606. Adoption of this new standard was applied to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue as not been recognized under legacy revenue guidance. Amounts previously recognized as T&G under ASC 605 of $35.7 million are currently recognized within natural gas and NGL sales revenues. This decrease was offset by an increase in producing wells and in both residue natural gas and NGL sales volumes, resulting in $24.2 million of collectively higher T&G.
On a per unit basis, T&G decreased to $1.42 per BOE sold for the year ended December 31, 2018 from $2.70 per BOE sold for the year ended December 31, 2017. The decrease in T&G per BOE is primarily the result of the adoption of ASC 606.
Production taxes. Our production taxes increased by $38.9 million to $90.3 million for the year ended December 31, 2018 as compared to $51.4 million for the year ended December 31, 2017. The increase was attributable to increased revenue as production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 8.5% for the year ended December 31, 2018 as compared to 8.5% for the year ended December 31, 2017. Production taxes were consistent for the years ended December 31, 2018 and 2017.
Exploration expenses. Our exploration expenses were $31.6 million and $36.3 million for the years ended December 31, 2018 and 2017, respectively. We recognized $4.6 million in expense attributable to the extension of certain leases and $25.7 million in expense attributable to the abandonment and impairment of unproved properties for the year ended December 31, 2018. We recognized $18.7 million in expense attributable to the extension of certain leases and $15.8 million in expense attributable to the abandonment and impairment of unproved properties for the year ended December 31, 2017.
Depletion, depreciation, amortization and accretion expense. Our DD&A expense increased $120.8 million to $435.8 million for the year ended December 31, 2018 as compared to $315.0 million for the year ended December 31, 2017. This increase was due to increased volumes sold for the year ended December 31, 2018 as sales increased by approximately 8,853 MBoe. On a per unit basis, DD&A expense decreased from $16.67 per BOE for the year ended December 31, 2017 to $15.71 per BOE for the year ended December 31, 2018. The decrease in DD&A per BOE is due to an increase in reserves related to an increase in prices and extensions, slightly offset by increased production for the year ended December 31, 2018.
Impairment of long lived assets and goodwill. For the year ended December 31, 2018, our impairment expense was $70.9 million. We recognized $16.2 million related to impairment of the proved oil and gas properties in our northern field. The fair value did not exceed the Company's carrying amount associated with its proved oil and gas properties in its northern field. Impairment on goodwill of $54.2 million was recognized upon completion of a quantitative assessment noting the fair value of the reporting unit was not greater than its carrying amount. For the year ended December 31, 2017, we recognized $1.6 million associated with impairment on other property and equipment and certain well equipment inventory evaluated to have a net realizable value less than the carrying value, as the equipment was determined to no longer be useful in our current drilling operations.
(Gain) loss on sale of property and equipment and assets of unconsolidated subsidiary. Our gain on sale of property and equipment and assets of unconsolidated subsidiary was $136.8 million for the year ended December 31, 2018, which was related to our April 2018 Divestitures, August 2018 Divestiture and December 2018 Divestitures, as compared to $0.5 million loss on the sale of property and equipment for the year ended December 31, 2017.
General and administrative expenses (“G&A”). General and administrative expenses increased by $24.4 million to $134.6 million for the year ended December 31, 2018 as compared to $110.2 million for the year ended December 31, 2017. This increase was primarily due to an increase in our employee head count for the year ended December 31, 2018 compared to the year ended December 31, 2017. On a per unit basis, G&A expenses decreased by $0.98 per BOE from $5.83 per BOE sold for the year ended December 31, 2017 to $4.85 per BOE sold for the year ended December 31, 2018.
Our G&A expenses includes the non-cash expense for stock-based compensation for equity awards granted to our employees and directors. For the year ended December 31, 2018, stock-based compensation expense was $68.3 million as compared to stock-based compensation expense of $65.6 million for the year ended December 31, 2017. On a per unit basis, stock-based compensation decreased $1.01 per BOE from $3.47 per BOE sold for the year ended December 31, 2017 to $2.46 per BOE sold for the year ended December 31, 2018.
Our other G&A expenses increased by $21.7 million during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to the growth of the Company, including an increase in employed workforce of 23%, or 52 additional employees. On a per BOE basis, other G&A expenses per BOE sold increased $0.03 per BOE sold from $2.36 per BOE sold for the year ended December 31, 2017 to $2.39 per BOE sold for the year ended December 31, 2018. The increase in other G&A expenses on a per BOE basis is partially offset by increased sales volumes for the year ended December 31, 2018.
Commodity derivative loss. Primarily due to the change in fair value from the execution of new positions during the year ended December 31, 2018, partially offset by a decrease in NYMEX crude oil futures prices at December 31, 2018 as compared to December 31, 2017, we incurred a net loss on our commodity derivatives of $8.6 million and $36.3 million for the years ended December 31, 2018 and 2017, respectively. These losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled and we will likely add to our hedging program in the future. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. For the year ended December 31, 2018 and 2017, we paid cash settlements of commodity derivatives totaling $123.5 million and $18.0 million, respectively.
Interest expense. Interest expense consists of interest expense on our long-term debt and debt issuance costs, net of capitalized interest. For the year ended December 31, 2018, we recognized interest expense of approximately $123.3 million as compared to $51.9 million for the year ended December 31, 2017, as a result of borrowings under our revolving credit facility, our 2021 Senior Notes and the associated make-whole premium and accelerated amortization of debt issuance costs upon redemption, our 2024 Senior Notes, our 2026 Senior Notes, and the amortization of other debt issuance costs.
We incurred interest expense for the year ended December 31, 2018 of approximately $82.7 million related to our 2021 Senior Notes, 2024 Senior Notes, 2026 Senior Notes and credit facility, as well as a make-whole premium of $35.6 million related to our repayment of our 2021 Senior Notes in January and February 2018. We incurred interest expense for the year ended December 31, 2017 of approximately $58.7 million related to our credit facility, 2021 Senior Notes and 2024 Senior Notes. Also included in interest expense for the years ended December 31, 2018 and 2017 was the amortization of debt issuance costs of $13.2 million and $4.3 million, respectively. Amortization expense for the year ended December 31, 2018 includes $9.4 million of acceleration of amortization expense upon the repayment of our 2021 Senior Notes. For the years ended December 31, 2018 and 2017, we capitalized interest expense of $8.2 million and $11.1 million, respectively.
Income tax (expense) benefit. We recorded income tax expense of approximately $66.9 million and income tax benefit of $63.7 million resulting in an effective tax rate of approximately 35.4% and 58.9% for the years ended December 31, 2018 and 2017, respectively. Our effective tax rate for 2018 differs from the U.S. statutory income tax rate of 24.7% primarily due to the effects of state income taxes, estimated permanent taxable differences, including the book impairment of goodwill and partnership income allocated to a noncontrolling interest owner.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016
Oil sales revenues. Crude oil sales revenues increased by $225.8 million to $419.9 million for the year ended December 31, 2017 as compared to crude oil sales of $194.1 million for the year ended December 31, 2016. An increase in sales volumes between these periods contributed to a $158.0 million positive impact, while an increase in crude oil prices contributed a $67.8 million positive impact.
For the year ended December 31, 2017, our crude oil sales averaged 26.3 MBbl/d. Our crude oil sales volumes increased 81% to 9,594 MBbl in the year ended December 31, 2017 compared to 5,287 MBbl for the year ended December 31, 2016. The volume increase was primarily due to the development of our properties. For the year ended December 31, 2017, we completed 198 gross wells. The increased production from these new wells was offset by the normal decline on the existing producing properties.
The average price we realized on the sale of crude oil was $43.77 per Bbl for the year ended December 31, 2017 compared to $36.70 per Bbl for the year ended December 31, 2016.
Natural gas sales revenues. Natural gas sales revenues increased by $43.6 million to $92.3 million for the year ended December 31, 2017 as compared to natural gas sales revenues of $48.7 million for the year ended December 31, 2016. An increase in sales volumes between these periods contributed a $29.3 million positive impact, while an increase in natural gas prices contributed a $14.3 million positive impact.
For the year ended December 31, 2017, our natural gas sales averaged 88.8 MMcf/d. Natural gas sales volumes increased by 60% to 32,395 MMcf for the year ended December 31, 2017 as compared to 20,212 MMcf for the year ended December 31, 2016. The volume increase was primarily due to the development of our properties. For the year ended December 31, 2017, we completed 198 gross wells. The increased production from these new wells was offset by the normal decline on the existing producing properties.
The average price we realized on the sale of our natural gas was $2.85 per Mcf for the year ended December 31, 2017 compared to $2.41 per Mcf for the year ended December 31, 2016.
NGL sales revenues. NGL revenues increased by $56.7 million to $92.1 million for the year ended December 31, 2017 as compared to NGL revenues of $35.4 million for the year ended December 31, 2016. An increase in sales volumes between these periods contributed a $25.0 million positive impact, while an increase in price contributed a $31.7 million positive impact.
For the year ended December 31, 2017, our NGL sales averaged 10.7 MBbl/d. NGL sales volumes increased by 70% to 3,901 MBbl for the year ended December 31, 2017 as compared to 2,284 MBbl for the year ended December 31, 2016. The volume increase was due to the development of our properties. Our NGL sales are directly associated with our natural gas sales since the majority of our natural gas volumes are processed by third parties which return a percentage of the proceeds from both residue natural gas sales and NGL sales.
The average price we realized on the sale of our NGL was $23.60 per Bbl for the year ended December 31, 2017 compared to $15.49 per Bbl for the year ended December 31, 2016.
Lease operating expenses. Our LOE, increased by $23.7 million to $60.4 million for the year ended December 31, 2017, from $36.7 million for the year ended December 31, 2016. The increase in LOE was due to the development of our properties. For the year ended December 31, 2017, we completed 198 gross wells. On a per BOE basis there was a decrease in operating expenses of $0.17 per BOE from $3.36 per BOE for the year ended December 31, 2016 to $3.19 per BOE for the year ended December 31, 2017. The decrease in LOE per BOE was primarily a result of flush production on several new pads turn-in-line during the year ended December 31, 2017.
Transportation and gathering. Our T&G expense increased by $25.6 million to $50.9 million for the year ended December 31, 2017, from $25.3 million for the year ended December 31, 2016. On a per unit basis, there was an increase in T&G expense of $0.39 per BOE from $2.31 per BOE for the year ended December 31, 2016 to $2.70 per BOE for the year ended December 31, 2017. These increases were due to the increase in producing wells and in both residue natural gas and NGL sales volumes and realized prices.
Production taxes. Our production taxes increased by $30.7 million to $51.4 million for the year ended December 31, 2017 as compared to $20.7 million for the year ended December 31, 2016. The increase was attributable to increased revenue as State of Colorado production taxes are calculated as a percentage of sales revenue. Production taxes as a percentage of sales revenue was 8.5% for the year ended December 31, 2017 as compared to 7.5% for the year ended December 31, 2016. The increase in production taxes as a percentage of sales revenue relates to an increase in the estimated ad valorem and severance tax rates for the year ended December 31, 2017.
Exploration expenses. Our exploration expenses were $36.3 million and $36.4 million for the years ended December 31, 2017 and 2016, respectively. We recognized $18.7 million in expense attributable to the extension of leases, $15.8 million in expense attributable to the abandonment and impairment of unproved properties and $1.4 million of costs associated with exploratory geological and geophysical costs for the year ended December 31, 2017. We recognized $14.1 million in expense attributable to the extension of leases and $22.3 million in expense attributable to the abandonment and impairment of unproved properties for the year ended December 31, 2016.
Depletion, depreciation, amortization and accretion expense. Our DD&A expense increased $109.7 million to $315.0 million for the year ended December 31, 2017 as compared to $205.3 million for the year ended December 31, 2016. This increase was due to higher volumes sold for the year ended December 31, 2017 as sales increased by approximately 7,954 MBoe. On a per unit basis, DD&A expense decreased from $18.77 per BOE for the year ended December 31, 2016 to $16.67 per BOE for the year ended December 31, 2017. The decrease in DD&A per BOE is due to an increase in reserves related to an increase in prices and extensions, slightly offset by increased production for the year ended December 31, 2017.
Impairment of long lived assets. For the year ended December 31, 2017, our impairment expense was $1.6 million, associated with impairment on other property and equipment and certain well equipment inventory evaluated to have a net
realizable value less than the carrying value, as the equipment was determined to no longer be useful in our current drilling operations. For the year ended December 31, 2016, we recognized $22.5 million in impairment expense on proved oil and gas properties in our northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in our northern field and it was determined that the proved oil and gas properties had no remaining fair value. Therefore, the full net book value of these proved oil and gas properties were impaired at June 30, 2016. Additionally, for the year ended December 31, 2016 we recognized $0.9 million of impairment on other property and equipment.
Loss on sale of property and equipment. Loss on sale of property and equipment for the for the year ended December 31, 2017 is comprised of a $0.5 million loss on the sale of property and equipment. There were no such losses on the sale of property and equipment for the year ended December 31, 2016.
Other operating expenses. Other operating expenses for the year ended December 31, 2016 includes $10.0 million on the write off of a non-refundable payment related to an option to acquire additional acreage. In March 2017, we entered into an amendment to this agreement with seller to terminate both our and the seller’s options for no further consideration. Also included in other operating expenses for the year ended December 31, 2016 is a $0.9 million rig termination fee related to the early termination of a rig in February 2016. There were no such expenses for the year ended December 31, 2017.
Acquisition transaction expenses. There were no significant acquisition transaction expenses for the year ended December 31, 2017. As part of the acquisition of properties in August 2016 and October 2016, we incurred $2.7 million of transaction costs associated with a finder’s fee, legal expenses and due diligence for the year ended December 31, 2016.
General and administrative expenses. General and administrative expenses decreased by $122.2 million to $110.2 million for the year ended December 31, 2017 as compared to $232.4 million for the year ended December 31, 2016. This decrease was comprised of a decrease in unit and stock-based compensation of $134.7 million, offset by an increase in other general and administrative expenses of $12.5 million. On a per unit basis, G&A expenses decreased from $21.24 per BOE sold for the year ended December 31, 2016 to $5.83 per BOE sold for the year ended December 31, 2017.
Our G&A expenses includes the non-cash expense for unit and stock-based compensation for equity awards granted to our employees, directors, officers and non-employee consultants. For the year ended December 31, 2017, stock-based compensation expense was $65.6 million as compared to unit and stock-based compensation expense of $200.3 million for the year ended December 31, 2016. On a per unit basis, unit and stock-based compensation decreased $14.84 per BOE from $18.31 per BOE sold for the year ended December 31, 2016 to $3.47 per BOE sold for the year ended December 31, 2017. The decrease in unit and stock-based compensation expense was due to accelerated vesting of outstanding Holdings RUAs in connection with our Corporate Reorganization and IPO in 2016. Additionally, as a result of the IPO in 2016, Holdings incentive units were converted to common stock resulting in the recognition of $172.1 million of stock-based compensation expense. Also in 2016, we created a Long Term Incentive Plan, which resulted in the granting of RSUs, stock options and performance stock awards to certain board members, officers, and employees.
Our other G&A expenses increased by $12.5 million during the year ended December 31, 2017 compared to the year ended December 31, 2016, primarily due to the growth of the Company, including an increase in employed workforce of 41.0%, or 66 additional employees. However, on a per BOE basis, other G&A expenses per BOE sold decreased $0.57 per BOE sold from $2.93 per BOE sold for the year ended December 31, 2016 to $2.36 per BOE sold for the year ended December 31, 2017. The decrease in other G&A expenses on a per BOE basis is due to higher production volumes for the year ended December 31, 2017.
Commodity derivative gain (loss). Primarily due to the increase in NYMEX crude oil futures prices at December 31, 2017 as compared to December 31, 2016 and change in fair value from the execution of new positions during each period, we incurred a net loss on our commodity derivatives of $36.3 million and $100.9 million for the years ended December 31, 2017 and 2016, respectively. These losses are a result of our hedging program, which is used to mitigate our exposure to commodity price fluctuations. The fair value of the open commodity derivative instruments will continue to change in value until the transactions are settled. Therefore, we expect our net income (loss) to reflect the volatility of commodity price forward markets. Our cash flow will only be affected upon settlement of the transactions at the current market prices at that time. For the year ended December 31, 2017, we paid cash settlements of commodity derivatives totaling $18.0 million. For the year ended December 31, 2016, we received cash settlements of commodity derivatives totaling $34.2 million.
Interest expense. Interest expense consists of interest paid and accrued on our long term debt, amortization of debt discount and debt issuance costs, net of capitalized interest. For the year ended December 31, 2017, we recognized interest expense of approximately $51.9 million as compared to $68.8 million for the year ended December 31, 2016, as a result of
borrowings under our revolving credit facility, our Second Lien Notes in 2016, our 2021 Senior Notes, our 2024 Senior Notes in 2017 and the amortization of debt issuance costs and debt discount.
We incurred interest expense for the year ended December 31, 2017 of approximately $58.7 million related to our 2024 Senior Notes, 2021 Senior Notes and credit facility. We incurred interest expense for the year ended December 31, 2016 of approximately $50.4 million related to our Second Lien Notes, our 2021 Senior Notes and credit facility. Also included in interest expense for the years ended December 31, 2017 and 2016 was the amortization of debt issuance costs and debt discount of $4.3 million and $4.2 million, respectively. For the years ended December 31, 2017 and 2016, we capitalized interest expense of $11.1 million and $5.2 million, respectively. Also included in interest expense for the year ended December 31, 2016 is a prepayment penalty of $4.3 million and the accelerated amortization of our remaining unamortized debt discount and debt issuance costs of $15.1 million related to our repayment of the Second Lien Notes in July 2016.
Income tax benefit. We recorded an income tax benefit of approximately $63.7 million and $29.3 million resulting in an effective tax rate of approximately 58.9% and 6.0% for the years ended December 31, 2017 and 2016, respectively. Our effective tax rate for 2017 differs from the U.S. statutory income tax rate of 38.0% primarily due to the effects of state income taxes, estimated permanent taxable differences and a one-time remeasurement of net deferred tax liabilities from 38.0% to 24.7% due to the Tax Cuts and Jobs Act. During the year ended December 31, 2017, our income tax benefit increased $34.4 million compared to the same period in 2016, which was primarily due to the one-time remeasurement of net deferred tax liabilities in 2017 and our corporate reorganization to a C-Corp in 2016. Excluding the impact of the one-time remeasurement of net deferred tax liabilities required in 2017, our overall effective tax rate was 37.3% for the year ended December 31, 2017.
Liquidity and Capital Resources
Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. Depending upon market conditions and other factors, we may also issue equity and debt securities, if needed.
Historically, our primary sources of liquidity have been borrowings under our revolving credit facility, proceeds from notes offerings, equity provided by investors, including our management team, cash from the IPO and Private Placement, cash from the issuance of preferred units, cash flows from operations and divestitures. To date, our primary use of capital has been for the acquisition of oil and gas properties to increase our acreage position, as well as development and exploration of oil and gas properties. Our borrowings, net of unamortized debt issuance costs, were approximately $1,417.7 million and $1,023.4 million at December 31, 2018, and 2017, respectively. We also have other contractual commitments, which are described in Note 13 - Commitments and Contingencies in Item 8 of this Annual Report.
We plan to continue our practice of entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we intend to enter into commodity derivative contracts at times and on terms desired to maintain a portfolio of commodity derivative contracts covering approximately 50% to 70% of our projected oil and natural gas production over a one to two year period at a given point in time, although we may from time to time hedge more or less than this approximate range.
Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and available borrowings under our revolving credit facility to execute our current capital program, excluding any acquisitions we may consummate, make our interest payments on the 2024 Senior Notes, 2026 Senior Notes and credit facility and pay dividends on our Series A Preferred Stock and the Elevation Preferred Units.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.
Our 2019 capital budget for the drilling and completion of operated and non-operated wells is approximately $585.0 million to $675.0 million, substantially all of which we intend to allocate to the Core DJ Basin. We expect to drill 125 gross operated wells, complete 122 gross operated wells and turn-in-line 111 gross operated wells. Our capital budget anticipates a one to two operated rig drilling program and excludes up to $250.0 million for Elevation, which is fully funded by a third party and any amounts that may be paid for potential acquisitions.
We currently have both a Stock Repurchase Program and a Senior Notes Repurchase Program in place. Spending under these programs in 2018 was $26.2 million and we expect continued spending under these programs through the first quarter of 2019.
Cash Flows
The following table summarizes our cash flows for the periods indicated (in thousands):
Year Ended December 31, 2018 Compared to the Year Ended December 31, 2017
Net cash provided by operating activities For the year ended December 31, 2018 as compared to the year ended December 31, 2017, our net cash provided by operating activities increased by $368.0 million, primarily driven by an increase in sales volume of 8,853 MBoe and increase in realized price of $6.25 per BOE resulting in an increase in net income of $166.3 million. An increase in changes in current assets and liabilities of $134.4 million also contributed to the increase in cash provided by operating activities.
Net cash used in investing activities. For the year ended December 31, 2018 as compared to the year ended December 31, 2017, our net cash used in investing activities decreased by $507.2 million primarily due to a decrease of $354.4 million used in oil and gas property additions, gathering systems and facilities additions, and other property and equipment additions. An increase of cash provided by the sale of assets of an unconsolidated subsidiary of $83.6 million and the sale of property and equipment of $75.7 million also contributed to the decrease in cash used in investing activities.
Net cash provided by financing activities. For the year ended December 31, 2018 as compared to the year ended December 31, 2017, our net cash provided by financing activities decreased by $22.8 million, primarily as a result of cash used in the redemption of the 2021 Senior Notes for $585.6 million, including a make-whole premium of $35.6 million and $28.6 million associated with repurchase of common shares. This decrease was offset by an increase of cash provided by the issuance of the Senior Notes of $345.7 million, an increase of cash provided by the net borrowings under the credit facility of $105.0 million, and an increase of cash provided by the issuance of Elevation Preferred Units of $141.6 million.
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Net cash provided by operating activities For the year ended December 31, 2017 as compared to the year ended December 31, 2016, our net cash provided by operating activities increased by $196.3 million, primarily driven by an increase in sales volume of 7,954 MBoe and increase in realized price of $6.56 per BOE resulting in a reduction in net loss of $411.6 million. An increase in deferred income tax benefit of $34.4 million and increase in changes in current assets and liabilities of $14.7 million also contributed to this increase. This increase was offset by a decrease of stock-based compensation of $134.7 million and settlements on commodity derivatives of $54.8 million.
Net cash used in investing activities. For the year ended December 31, 2017 as compared to the year ended December 31, 2016, our net cash used in investing activities increased by $530.9 million primarily due to an increase of $935.7 million in cash expended for drilling and completion activities and other property and equipment. This increase was offset by a decrease in acquired oil and gas properties of $401.8 million.
Net cash provided by financing activities. For the year ended December 31, 2017 as compared to the year ended December 31, 2016, our net cash provided by financing activities decreased by $823.4 million, primarily as a result of a decrease of $1,243.1 million in proceeds from the issuance of common stock and members units, net of issuance costs, and a decrease of $171.6 million in proceeds from the issuance of preferred units and stock in the year ended December 31, 2016. This decrease was offset by an increase of $315.0 million in borrowings under the credit facility and an increase of $278.3 million in net proceeds and repayments of 2021 Senior Notes, 2024 Senior Notes and Second Lien Notes.
Working Capital
Our working capital surplus (deficit) was $62.2 million and $(236.7) million at December 31, 2018 and 2017, respectively. Our cash balances totaled $235.0 million and $6.8 million at December 31, 2018 and 2017, respectively.
Due to the amounts that we incur related to our drilling and completion program and the timing of such expenditures, we may incur working capital deficits in the future. We expect that our cash flows from operating activities and availability under our revolving credit facility will be sufficient to fund our working capital needs. We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil, natural gas and NGL production will be the largest variables affecting our working capital.
Debt Arrangements
Our revolving credit facility has a maximum credit amount of $1.5 billion and a current borrowing base of $1.2 billion, subject to the current maximum lending commitments of $650.0 million. All of our current and future restricted subsidiaries will be guarantors under such facility, with the exception of Elevation. Amounts repaid under our revolving credit facility may be re-borrowed from time to time, subject to the terms of the facility. For more information on the revolving credit facility, please see Note 5 - Long-Term Debt in Item 8. Financial Statements and Supplementary Data of this Annual Report. The revolving credit facility is secured by liens on substantially all of our properties.
In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bore interest at an annual rate of 7.875%. Interest on our 2021 Senior Notes was payable on January 15 and July 15 of each year, and the first interest payment was made on January 15, 2017. Our 2021 Senior Notes would have matured on July 15, 2021. Our 2021 Senior Notes were guaranteed by all of our current and future restricted subsidiaries (other than Extraction Finance Corp., the co-issuer of our 2021 Senior Notes). In the first quarter of 2018, we closed a tender offer for the 2021 Senior Notes and subsequently redeemed all remaining outstanding 2021 Senior Notes. No 2021 Senior Notes remain outstanding.
In August 2017, we closed a private offering of our unsecured 7.375% Senior Notes due 2024 that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024. Our 2024 Senior Notes are guaranteed by certain of our current and future restricted subsidiaries.
In January 2018, we closed a private offering of our unsecured 5.625% Senior Notes due 2026 that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on our 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026. Our 2026 Senior Notes are guaranteed by certain of our current and future restricted subsidiaries.
Revolving Credit Facility
The amount available to be borrowed under our revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under our revolving credit facility. As of December 31, 2018, the borrowing base was $1.2 billion, subject to current elected commitments of $650.0 million, and we had $285.0 million of borrowings outstanding under our revolving credit facility. In December 2018, we completed the November 1, 2018 borrowing base redetermination.
Principal amounts borrowed will be payable on the maturity date, and interest will be payable quarterly for alternate base rate loans and at the end of the applicable interest period for Eurodollar loans. We have a choice of borrowing in Eurodollars or at the alternate base rate. Eurodollar loans bear interest at a rate per annum equal to an adjusted LIBOR rate (equal to the product of: (a) the LIBOR rate, multiplied by (b) a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the reserve percentages (expressed as a decimal) on such date at which the administrative agent under our revolving credit facility is required to maintain reserves on ‘Eurocurrency Liabilities’ as defined in and pursuant to Regulation D of the Board of Governors of the Federal Reserve System) plus an applicable margin ranging from 200 to 300 basis points, depending on the percentage of our borrowing base utilized. Alternate base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds
effective rate plus 50 basis points and (iii) the adjusted one-month LIBOR rate (as calculated above) plus 100 basis points, plus an applicable margin ranging from 100 to 200 basis points, depending on the percentage of our borrowing base utilized. As of December 31, 2018, we had $285.0 million of outstanding borrowings under our revolving credit facility. We may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs.
The revolving credit facility is secured by liens on substantially all of our properties and guarantees from us and our current and future subsidiaries, with the exception of Elevation. The revolving credit facility contains restrictive covenants that may limit our ability to, among other things:
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incur additional indebtedness;
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sell assets;
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make loans to others;
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make investments;
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make certain changes to our capital structure;
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make or declare dividends;
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hedge future production or interest rates;
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enter into transactions with our affiliates;
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incur liens; and
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engage in certain other transactions without the prior consent of the lenders.
The revolving credit facility requires us to maintain the following financial ratios:
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a current ratio, which is the ratio of our and our restricted subsidiaries' consolidated current assets (includes unused commitments under our revolving credit facility and excludes derivative assets) to our restricted subsidiaries' consolidated current liabilities (excludes obligations under our revolving credit facility, the senior notes and certain derivative liabilities), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; and
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a net leverage ratio, which is the ratio of our and our restricted subsidiaries' (i) consolidated debt less cash balances to (ii) consolidated EBITDAX for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter.
2021 Senior Notes
In July 2016, we closed a private offering of our 2021 Senior Notes that resulted in net proceeds of approximately $537.2 million. Our 2021 Senior Notes bore interest at an annual rate of 7.875% and matured on July 15, 2021.
Concurrent with the 2026 Notes Offering, we commenced a cash tender offer to purchase any and all of our 2021 Senior Notes. On January 24, 2018 we received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 we made a cash payment of approximately $534.2 million, which included principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, we redeemed the approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, we closed a private offering of our 2024 Senior Notes that resulted in net proceeds of approximately $392.6 million. Our 2024 Senior Notes bear interest at an annual rate of 7.375%. Interest on our 2024 Senior Notes is payable on May 15 and November 15 of each year, and the first interest payment was paid on November 15, 2017. Our 2024 Senior Notes will mature on May 15, 2024.
We may, at our option, redeem all or a portion of our 2024 Senior Notes at any time on or after May 15, 2020 at the redemption prices set forth in the indenture governing the 2024 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2024 Senior Notes before May 15, 2020, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 107.375% of the principal amount of our 2024 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to May 15, 2020, we may redeem some or all of our 2024 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2024 Senior Notes may have the right to require us to repurchase their 2024 Senior Notes at 101% of the principal amount of the 2024 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2024 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that guarantees our indebtedness under a credit facility. The 2024 Senior Notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2024 Senior Notes.
2026 Senior Notes
On January 25, 2018, we closed a private offering of our 2026 Senior Notes that resulted in net proceeds of approximately $737.9 million. Our 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on the 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. Our 2026 Senior Notes will mature on February 1, 2026. As of the date of this filing, we have repurchased 2026 Senior Notes with a nominal value of $13.1 million for $10.5 million in connection with the Senior Notes Repurchase Program.
We may, at our option, redeem all or a portion of our 2026 Senior Notes at any time on or after February 1, 2021 at the redemption prices set forth in the indenture governing the 2026 Senior Notes. We are also entitled to redeem up to 35% of the aggregate principal amount of our 2026 Senior Notes before February 1, 2021, with an amount of cash not greater than the net proceeds that we raise in certain equity offerings at a redemption price equal to 105.625% of the principal amount of our 2026 Senior Notes being redeemed plus accrued and unpaid interest, if any, to the redemption date. In addition, prior to February 1, 2021, we may redeem some or all of our 2026 Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium. If we experience certain kinds of changes of control, holders of our 2026 Senior Notes may have the right to require us to repurchase their 2026 Senior Notes at 101% of the principal amount of the 2026 Senior Notes, plus accrued and unpaid interest, if any, to the date of purchase.
Our 2026 Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our other senior indebtedness and senior to any of our subordinated indebtedness. Our 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our current subsidiaries and by certain future restricted subsidiaries that guarantee our indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of our secured indebtedness (including all borrowings and other obligations under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of our future subsidiaries that do not guarantee the 2026 Senior Notes.
Convertible Preferred Securities and Series A Preferred Stock
We previously issued investment funds managed by Apollo Global Management ("Apollo") $75.0 million in Series A Preferred Units to fund a portion of the purchase price for the October 2016 Acquisition. The Series A Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. In 2016, we used $90.0 million of the net proceeds from the IPO to redeem the Series A Preferred Units in full, which included a premium of $15.0 million.
In addition, we issued to, among others, investment funds managed by OZ Management LP and Yorktown $185.3 million in Series B Preferred Units to fund a portion of the purchase price for the October 2016 Acquisition. The Series B Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and we had the ability to pay up to 50% of the quarterly dividend in kind. The Series B Preferred Units were converted in connection with the closing of the IPO into shares of our Series A Preferred Stock that are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and we have the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are partially paid in cash). The Series A Preferred Stock is convertible into shares of our common stock at the election of the Series A Preferred Holders at a conversion ratio per share of
Series A Preferred Stock of 61.9195. Until the three-year anniversary of the closing of the IPO, we may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of our common stock trades at or above a certain premium to our initial offering price, such premium to decrease with time. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference. See Note 9 - Equity- Series A Preferred Stock and Series B Preferred Units” in Item 8. Financial Statements and Supplementary Data of this Annual Report.
Elevation Preferred Units
On July 3, 2018, Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and subsidiary of the Company, entered into the Securities Purchase Agreement with the Purchaser, pursuant to which Elevation agreed to sell 150,000 Elevation Preferred Units at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million, in a transaction exempt from the registration requirements under the Securities Act. The Private Placement closed on July 3, 2018 and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement to Extraction for previously incurred midstream capital expenditures and general and administrative expenses. These Elevation Preferred Units are non-recourse to Extraction, minimizing risk to our common shareholders, and represent the noncontrolling interest presented on the consolidated balance sheets, consolidated statements of operations and consolidated statements of changes in members' and stockholders' equity and noncontrolling interest. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of December 31, 2018, $136.9 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas.
During the Preferred Unit Commitment Period, subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at least $25.0 million, up to an aggregate amount of $350.0 million. During the Preferred Unit Commitment Period, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $350.0 million commitment.
The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In respect of quarters ending prior to and including June 30, 2020, such dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, such dividend is payable solely in cash.
Commitments, Contingencies and Contractual Obligations
A summary of our commitments, contingencies and contractual obligations as of December 31, 2018 is provided in the following table (in thousands).
(1)
We lease two office spaces in Denver, Colorado, two office spaces in Greeley, Colorado and one office space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2028. The Greeley, Colorado and Houston, Texas leases expire on October 31, 2019, June 30, 2019 and January 31, 2022,
respectively. Total rental commitments under non-cancelable leases for office space were $32.8 million at December 31, 2018.
(2)
As of December 31, 2018, we were subject to commitments on three drilling rigs. The three drilling rigs are under contract and are set to expire on February 19, 2019, May 26, 2019 and November 23, 2019.
(3)
As of December 31, 2018, our oil marketer is subject to a firm transportation agreement that commenced in November 2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, we amended our agreement with our oil marketer that requires us to sell all of our crude oil from an area of mutual interest in exchange for a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. In December 2017, we extended the term of this agreement through October 31, 2019 and posted a letter of credit in the amount of $35.0 million. We are currently in the process of amending and extending this agreement. We evaluate our contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. We also have two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which we have a minority ownership interest. The first agreement commenced in November 2016 and has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The second agreement will commence in or around July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The remaining aggregate amount of estimated payments under these agreements is approximately $875.8 million.
(4)
In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, we agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August 2018 and the second plant is expected to be completed by mid-2019, although the exact start-up date is undetermined at this time. Our share of these commitments will require 51.5 MMcf and 20.6 MMcf per day, respectively, to be delivered after the plants' in-service dates for a period of seven years thereafter. We may be required to pay a shortfall fee for any volumes under these commitments. These contractual obligations can be reduced by our proportionate share of the collective volumes delivered to the plants by other third party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. We are also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. Under our current drilling plans, we expect to meet these volume commitments and they have therefore not been reflected in the table above.
(5)
Calculated based on balance of $285.0 million outstanding borrowings under our revolving credit facility as of December 31, 2018 and assumes no borrowings until the maturity date of the facility. Interest on our revolving credit facility is payable at one of the following two variable rates as selected by us: a base rate based on the Prime Rate or the Eurodollar rate based in LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the Pricing Grid. Additionally, our revolving credit facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage.
(6)
Calculated based on the December 31, 2018 outstanding aggregate principal amount on our 2024 Senior Notes of $400.0 million outstanding, at a fixed rate of 7.375%, and outstanding principal amount on our 2026 Senior Notes of $750.0 million outstanding, at a fixed rate of 5.625%. Interest is payable on our 2024 Senior Notes and 2026 Senior Notes on a semi-annual basis through the maturity dates of May 15, 2024 and February 1, 2026, respectively.
The above contractual obligations schedule does not include the Series A Preferred Stock, future anticipated settlement of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties, as we cannot determine with accuracy the timing of such payments. Additionally, the above contractual obligations schedule does not include lease operating expenses or budgeted capital expenditures. For further discussion regarding our Series A Preferred Stock, derivative contracts and estimated future costs associated with the abandonment of our oil and gas properties, please refer to Note 9 - Equity, Note 6 - Commodity Derivative Instruments and Note 7 - Asset Retirement Obligations to our historical audited financial statements for the years ended December 31, 2018 and 2017. Additionally, for further information regarding our contractual obligations, lease operating expenses and budgeted capital expenditures as of December 31, 2018, please refer to Note 13 - Commitments and Contingencies to our historical unaudited financial statements, "Historical Results of Operations and Operating Expenses" for the year ended December 31, 2018 and 2017 and "Capital Expenditures" in Item 7 of this Annual Report.
As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells. If we do not meet such commitments, the acreage positions or wells may be lost or we may be required to pay damages if certain performance conditions are not met.
Off-Balance Sheet Arrangements
As of December 31, 2018, we do not have material off-balance sheet arrangements, except for our agreement with our oil marketer. Our oil marketer is subject to a firm transportation agreement with a make-whole provision that allows us to satisfy any minimum volume commitment deficiencies incurred by our oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2019. We are currently in the process of amending and extending this agreement. Please see Note 13 - Commitments and Contingencies in Part II, Item 8 of this Annual Report.
Impact of Inflation/Deflation and Pricing
All of our transactions are denominated in U.S. dollars. Typically, as prices for oil and natural gas increase, associated costs rise. Conversely, as prices for oil and natural gas decrease, costs decline. Cost declines tend to lag and may not adjust downward in proportion to decline commodity prices. Historically, field-level prices received for our oil and natural gas production have been volatile. During the year ended December 31, 2018, commodity prices increased during the first, second and third quarter, and subsequently decreased in the fourth quarter, while during the years ended December 31, 2017 and 2016, commodity prices generally increased. Changes in commodity prices impact our revenues, estimates of reserves, assessments of any impairment of oil and natural gas properties, as well as values of properties being acquired or sold. Price changes have the potential to affect our ability to raise capital, borrow money, and retain personnel.
Critical Accounting Policies and Estimates
Use of Estimates in the Preparation of Financial Statements
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, 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 period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion, amortization and accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of unit and stock-based payments, and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe our estimates are reasonable.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.
We capitalize interest, if debt is outstanding, during drilling operations in our exploration and development activities.
Oil and Gas Reserves
Our estimates of proved reserves are based on the quantities of oil, natural gas and NGL, 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 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. Our independent petroleum engineers, Ryder Scott, prepare a reserve and economic evaluation of all of our properties on a well-by-well basis. The accuracy of reserve estimates is a function of the:
•
quality and quantity of available data;
•
interpretation of that data;
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accuracy of various mandated economic assumptions; and
•
judgment of the independent reserve engineer.
One of the most significant estimates we make is the estimate of oil, natural gas and NGL reserves. Oil, natural gas and NGL reserve estimates require significant judgments in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history, projected future production, economic assumptions relating to commodity prices, operating expenses, severance and other taxes, capital expenditures and remediation costs and these estimates are inherently uncertain. For example, if estimates of proved reserves decline, our DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of oil and gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. We cannot predict what reserve revisions may be required in future periods.
Ryder Scott estimated all of our proved reserve quantities as of December 31, 2018, 2017 and 2016. In connection with Ryder Scott performing their independent reserve estimations, we furnish them with the following information that they review: (1) technical support data, (2) technical analysis of geologic and engineering support information, (3) economic and production data and (4) our well ownership interests.
The following table presents information about proved reserve changes from period to period due to items we do not control, such as price, and from changes due to production history and well performance. These changes do not require a capital expenditure on our part, but may have resulted from capital expenditures we incurred to develop other estimated proved reserves.
The recent significant decline in oil, natural gas and NGL prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market. A prolonged period of depressed commodity prices may have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other changes to our development plans or costs.
Depreciation, Depletion, Amortization and Accretion.
Our DD&A rate is dependent upon our estimates of total proved and proved developed reserves, which incorporate various assumptions and future projections. If our estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, which in turn reduces our net income. Such a decline in reserves may result from lower commodity prices or other changes to reserve estimates, as discussed above, and we are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploration and development program, as well as future economic conditions.
Impairment of Proved Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. We estimate the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization.
For the years ended December 31, 2018 and 2016, we recognized $16.2 million and $22.5 million, respectively, in impairment expense on proved oil and gas properties in our northern field. As of September 30, 2018, the future undiscounted cash flows did not exceed the carrying amount associated with our proved oil and gas properties in the northern field. As of June 30, 2016, it was determined that the proved oil and gas properties had no remaining fair value, therefore, the full net book value of these proved oil and gas properties were impaired. For the year ended December 31, 2017, we recognized no impairment expense on proved oil and gas properties.
Our impairment analyses requires us to apply judgment in identifying impairment indicators and estimating future cash flows of our oil and gas properties. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to an impairment charge.
Forward commodity prices and estimates of future production also play a significant role in determining impairment of proved oil and gas properties. As a result of lower commodity prices and their impact on our estimated future cash flows, we have continued to review our proved oil and gas properties for impairment. At December 31, 2018, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $0.8 billion, or 30%. At December 31, 2017, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $1.6 billion, or 68%. At December 31, 2016, our expected undiscounted future cash flows exceeded the carrying value of our proved oil and gas properties by approximately $1.7 billion, or 108%. The key assumptions used to determine the undiscounted future cash flows include estimates of future production, future commodity pricing, differentials, net estimated operating costs, anticipated capital expenditures and new wells on production. Future commodity pricing for oil and NGL is based on five-year West Texas Intermediate strip prices, which decreased 8% from an average of $54.66/Bbl at December 31, 2017 to an average of $50.04/Bbl at December 31, 2018, and on five-year Henry Hub strip prices, which decreased 14% from an average of $3.14/MMBtu at December 31, 2017 to an average of $2.70/MMBtu at December 31, 2018.
Impairment of Unproved Oil and Gas Properties
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. We evaluate significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, we recognized $25.7 million, $15.8 million and $22.3 million in impairment expense for the years ended December 31, 2018, 2017 and 2016, respectively.
Goodwill and Other Intangible Assets
We apply the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. We test goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents our oil and gas operations in the core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of our common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. We performed a quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its carrying amount. We identified triggering events as of December 31, 2018,
due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to September 30, 2018. As such, we performed a quantitative assessment as of December 31, 2018, utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit was not greater than its carrying amount. As a result, we recorded goodwill impairment of $54.2 million, the entirety of the balance, for the year ended December 31, 2018. We performed a quantitative assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount. We performed a qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-likely-than-not greater than its carrying amount.
Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the estimated useful life of the license.
Commodity Derivative Instruments
We have entered into commodity derivative instruments, as described below. We have utilized swaps, put options, and call options to reduce the effect of price changes on a portion of our future oil and natural gas production. A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of our purchased put options have deferred premiums. For the deferred premium puts, we agree to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
We combine swaps, purchased put options, sold put options, and sold call options in order to achieve various hedging strategies. Some examples of our hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options, and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap.
The objective of our use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit our ability to benefit from favorable price movements. We may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. We do not enter into derivative contracts for speculative purposes.
The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets. We have not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, we do not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the statements of operations. Our cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in our statements of cash flows.
Our valuation estimate takes into consideration the counterparties’ credit worthiness, our credit worthiness, and the time value of money. The consideration of the factors result in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please see “-How We Evaluate Our Operations-Derivative Arrangements.”
Accounting for Business Combinations
We account for all of our business combinations using the purchase method, which is the only method permitted under FASB ASC 805, Business Combinations, and involves the use of significant judgment. In connection with a business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Any excess or shortage of amounts assigned to assets and liabilities over or under the purchase price is recorded as a gain on bargain purchase or goodwill. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and gas properties. If sufficient market data is not available regarding the fair values of proved and unproved properties, we must prepare estimates. To estimate the fair values of these properties, we prepare estimates of gas, oil and NGL reserves. We estimate future prices to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, when a discounted cash flow model is used, the discounted future net cash flows of probable and possible reserves are reduced by additional risk factors. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage.
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.
Asset Retirement Obligations
Our asset retirement obligations (“ARO”) consist of estimated future costs associated with the plugging and abandonment of oil, natural gas and NGL wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws, and applicable lease terms. The fair value of an ARO liability is required to be recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous assumptions regarding such factors as the estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free discount rate to be used; and inflation rates. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.
Revenue Recognition
Revenues from the sale of oil, natural gas and NGL are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We recognize revenues from the sale of oil, natural gas and NGL using the sales method of accounting, whereby revenue is recorded based on our share of volume sold, regardless of whether we have taken our proportional share of volume produced. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. We receive payment one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers and the price we will receive. Variances between our estimates and the actual amounts received are recorded in the month payment is received. A 10% change in our revenue accrual would have impacted total operating revenues by approximately $9.1 million and $9.3 million for the years ended December 31, 2018 and 2017, respectively.
Unit and Stock-Based Payments
The Company and its predecessor, Holdings, has granted restricted unit awards (“RUAs”), restricted stock units (“RSUs”), stock option awards and performance stock awards ("PSAs) to certain employees of the Company, which therefore required the Company to recognize the expense in its financial statements.
All unit and stock-based payments to employees are measured at fair value on the grant date and expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All unit and stock-based payment expense is recognized using the straight-line method and is included within general and administrative expenses in the consolidated statements of operations and unit and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 11 - Unit and Stock-Based Compensation for additional discussion on unit and stock-based payments.
Income Taxes
We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by deferral and state taxing authorities.
We periodically assess whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, we consider all the available positive and negative evidence and makes certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. We believe it is more likely than not that certain net operating losses can be carried forward and utilized.
We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. We do not currently have uncertain tax positions.
On December 22, 2017, United States legislation referred to as the TCJA was signed into law. Many of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes changes to the Internal Revenue Code of 1986 (as amended, the "Code"). The most significant change included in the TCJA is a reduction in the corporate federal income tax rate from 35% to 21%. As a result of the enactment date of December 22, 2017, we were required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. This re-measurement of deferred tax assets and liabilities required us to analyze and record a one-time adjustment to reduce the overall deferred tax liability in the consolidated balance sheets and affect a corresponding income tax benefit in the consolidated statements of operations for the year ended December 31, 2017. We believe the accounting is complete regarding the revaluation of the deferred tax balances. This resulted in the recording of an income tax benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability as of December 31, 2017. During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. There are no remaining provision amounts associated with the TCJA as of December 31, 2018.
Extraction Oil & Gas Holdings, LLC, our accounting predecessor, was a limited liability company that was not subject to U.S. federal income tax.
Recent Accounting Pronouncements
Please refer to Recent Accounting Pronouncements in Note 2 - Basis of Presentation and Significant Accounting Policies in Part II, Item 8 of this Annual Report.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGL has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control, such as the strength of the global economy and global supply and demand for the commodities we produce.
To reduce the impact of fluctuations in oil prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil and natural gas production through various transactions that limit the downside of future prices received. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations.
The following tables present our derivative positions related to crude oil and natural gas sales in effect as of December 31, 2018:
As of December 31, 2018, the fair market value of our oil derivative contracts was a net asset of $59.4 million. Based on our open oil derivative positions at December 31, 2018, a 10% increase in the NYMEX WTI price would decrease our net oil derivative asset by approximately $43.4 million, while a 10% decrease in the NYMEX WTI price would increase our net oil derivative asset by approximately $43.9 million. As of December 31, 2018, the fair market value of our natural gas derivative contracts was a net liability of $2.3 million. Based upon our open commodity derivative positions at December 31, 2018, a 10% increase in the NYMEX Henry Hub price would increase our net natural gas derivative liability by approximately $7.2 million, while a 10% decrease in the NYMEX Henry Hub price would decrease our net natural gas derivative liability by approximately $7.3 million. Please see “-Derivative Arrangements.”
Counterparty and Customer Credit Risk
Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.
We sell oil, natural gas and NGL to various types of customers, including marketers. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside of our control, none of which can be predicted with certainty. For the year ended December 31, 2018, we had certain major customers that exceeded 10% of total oil, natural gas and NGL revenues. We do not believe the loss of any single purchaser would materially impact its operating results because oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers.
At December 31, 2018, we had commodity derivative contracts with eleven counterparties, all of whom are lenders under our credit agreement. We do not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, we use master netting agreements to minimize credit-risk exposure. The creditworthiness of our counterparties is subject to periodic review. For the years ended December 31, 2018, 2017 and 2016, we did not incur any losses with respect to counterparty contracts. None of our existing derivative instrument contracts contains credit-risk related contingent features.
Interest Rate Risk
At December 31, 2018, we had $285.0 million of variable-rate debt outstanding. The impact on interest expense of a 1% increase or decrease in the average interest rate would be approximately $2.9 million. We may begin entering into interest rate swap arrangements on a portion of our outstanding debt to mitigate the risk of fluctuations in LIBOR if we have variable-rate debt outstanding in the future. See “-Liquidity and Capital Resources-Debt Arrangements.”
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
EXTRACTION OIL & GAS, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Financial Statements:
Page
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Changes in Members' and Stockholders' Equity and Noncontrolling Interest
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Extraction Oil & Gas, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Extraction Oil & Gas, Inc. and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations, of changes in members’ and stockholders’ equity and noncontrolling interest and of cash flows for each of the three years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.
/s/ PricewaterhouseCoopers LLP
Denver, Colorado
February 21, 2019
We have served as the Company’s auditor since 2014.
EXTRACTION OIL & GAS, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART
OF THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ AND STOCKHOLDERS’ EQUITY AND NONCONTROLLING INTEREST
(In thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF
THESE CONSOLIDATED FINANCIAL STATEMENTS
EXTRACTION OIL & GAS, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1-Business and Organization
Extraction Oil & Gas, Inc. (the “Company” or “Extraction”) is an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, primarily in the Wattenberg Field of the Denver-Julesburg Basin (the “DJ Basin”) of Colorado. The Company and its subsidiaries are focused on the acquisition, development and production of oil, natural gas and NGL reserves in the Rocky Mountain region, as well as the construction and support of midstream assets to gather and process crude oil and gas production focused in the DJ Basin of Colorado. Extraction is a public company listed for trading on the NASDAQ Global Select Market under the symbol "XOG".
Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and an unrestricted subsidiary of the Company, focused on the construction of gathering systems and facilities operations to serve the development of acreage in the Company’s Hawkeye and Southwest Wattenberg areas. Midstream assets of Elevation are represented as the gathering systems and facilities line item within the consolidated balance sheet. As of December 31, 2018, these gathering systems and facilities operations are not in service, therefore, there are no such revenues for the year then ended.
The consolidated financial statements for the period January 1, 2016 through October 12, 2016 are based on the financial statements of the Company's accounting predecessor, Extraction Oil & Gas Holdings, LLC ("Holdings") prior to the corporate reorganization (the "Corporate Reorganization"), pursuant to which, in connection with the initial public offering of the Company (the "Offering" or "IPO"), (i) on October 11, 2016, a former subsidiary of Extraction Oil & Gas Holdings, LLC, Extraction Oil & Gas, LLC, converted into the Company, and (ii) on October 17, 2016, Holdings merged with and into the Company with Extraction as the surviving entity.
Note 2-Basis of Presentation and Significant Accounting Policies
Basis of Presentation
The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States (“GAAP”). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair statement of the consolidated financial information, have been included.
Use of Estimates in the Preparation of Financial Statements
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, 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 period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties and goodwill; (3) depreciation, depletion, amortization and accretion; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations, including the determination of any resulting goodwill; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of unit and stock-based payments, and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances.
Cash and Cash Equivalents
Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased.
Restricted Cash
Restricted cash represents cash that is unavailable for use in the Company's general operations. The Company had no restricted cash as of December 31, 2018 and 2017.
Cash Held in Escrow
Cash held in escrow includes deposits for the purchase of certain oil and gas properties as required under the related purchase and sale agreements. The Company had no cash held in escrow as of December 31, 2018 and 2017.
Accounts Receivable
The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. The Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. On an on-going basis, management reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables as of or for the years ended December 31, 2018 and 2017.
Credit Risk and Other Concentrations
The Company’s cash and cash equivalents are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.
The Company sells oil, natural gas and NGL to various types of customers, including oil marketers, pipelines and refineries. Credit is extended based on an evaluation of the customer’s financial conditions and historical payment record. The future availability of a ready market for oil, natural gas and NGL depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. For the three years ended December 31, 2018, the Company had the following customers that exceeded 10% of total oil, natural gas and NGL revenues. The Company does not believe the loss of any single purchaser would materially impact its operating results because crude oil, natural gas and NGL are fungible products with well-established markets and numerous purchasers.
At December 31, 2018, the Company had commodity derivative contracts with eleven counterparties, all of whom are lenders under our credit agreement. The Company does not require collateral or other security from counterparties to support derivative instruments; however, to minimize the credit risk in derivative instruments, it is the Company’s policy to enter into derivative contracts only with counterparties that are credit worthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The credit worthiness of the Company’s counterparties is subject to periodic review. For the years ended December 31, 2018, 2017 and 2016, the Company did not incur any losses with respect to counterparty contracts. None of the Company’s existing derivative instrument contracts contains credit-risk related contingent features.
Inventory and Prepaid Expenses
The Company records well equipment inventory at the lower of cost or net realizable value. Prepaid expenses are recorded at cost. Inventory and prepaid expenses are comprised of the following (in thousands):
Additionally, the Company recognized approximately $0.1 million, $0.7 million and $0.4 million of impairment expense on well equipment inventory for the years ended December 31, 2018, 2017 and 2016, respectively.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a units-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. For the years ended December 31, 2018, 2017 and 2016, the Company excluded $144.3 million, $127.4 million and $98.7 million of capitalized costs from depletion related to wells in progress, respectively. For the years ended December 31, 2018, 2017 and 2016, the Company recorded depletion expense on capitalized oil and gas properties of $426.8 million, $306.7 million and $197.4 million, respectively.
The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed at each period end. Due to the capital-intensive nature and the geological characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. As of December 31, 2018, the Company had approximately $6.1 million of suspended well costs, all capitalized less than one year and included in wells in progress at December 31, 2018. These exploratory well costs are pending further engineering evaluation and analysis to determine if economic quantities of oil and gas reserves have been discovered. The Company expects its analysis to be complete in the second half of 2019. As of December 31, 2017, $15.7 million of suspended well costs, all capitalized less than one year and included in wells in progress as of December 31, 2017. At September 30, 2018, the Company completed its evaluation and moved $17.9 million of these suspended well costs to proved oil and gas properties based on the determination of proved reserves. As of December 31, 2016, the Company had no suspended well costs recorded.
Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. The Company expensed $0.4 million and $1.4 million of costs associated with exploratory geological and geophysical costs for the years ended December 31, 2018 and 2017, respectively. There were no exploratory geological and geophysical costs incurred for the year ended December 31, 2016.
The Company capitalizes interest, if debt is outstanding, during drilling operations in its exploration and development activities. For the years ended December 31, 2018, 2017 and 2016, the Company capitalized interest of approximately $8.2 million, $11.1 million and $5.2 million, respectively.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so
significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized to earnings.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Impairment of Oil and Gas Properties
Proved oil and gas properties are reviewed for impairment annually or when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. For all of its fields, the Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital expenditures, estimated future operating costs, and discount rates commensurate with the risk associated with realizing the projected cash flows. Impairment expense for proved oil and gas properties is reported in impairment of long lived assets and goodwill in the consolidated statements of operations, which increases accumulated depletion, depreciation and amortization. For the years ended December 31, 2018 and 2016, the Company recognized $16.2 million and $22.5 million, respectively, in impairment expense on proved oil and gas properties in the Company's northern field. As of September 30, 2018, the future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in its northern field. As of June 30, 2016, it was determined that the proved oil and gas properties had no remaining fair value, therefore, the full net book value of these proved oil and gas properties were impaired. For the year ended December 31, 2017, the Company recognized no impairment expense on proved oil and gas properties.
Unproved oil and gas properties consist of costs to acquire unevaluated leases as well as costs to acquire unproved reserves. The Company evaluates significant unproved oil and gas properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. When successful wells are drilled on undeveloped leaseholds, unproved property costs are reclassified to proved properties and depleted on a unit-of-production basis. Impairment expense and lease extension payments for unproved properties is reported in exploration expenses in the consolidated statements of operations. As a result of the abandonment and impairment of unproved properties, the Company recognized $25.7 million, $15.8 million and $22.3 million in impairment expense for the years ended December 31, 2018, 2017 and 2016, respectively.
Other Property and Equipment
Other property and equipment consists of (i) other property and equipment including, office furniture and fixtures, leasehold improvements and computer hardware and software, (iii) compressors used in Extraction’s oil and gas operations, (iii) land, compressor stations, central tank batteries, and disposal well facilities and (iv) rights of ways, pipeline, and engineering costs. Impairment expense for other property and equipment is reported in impairment of long lived assets and goodwill in the consolidated statements of operations. The Company recognized $0.4 million, $0.9 million and $0.5 million in impairment expense related to midstream facilities for the years ended December 31, 2018, 2017 and 2016, respectively, which increased accumulated depreciation recognized in other property and equipment, net of accumulated depreciation. The Company recognized the impairment expense for the year ended December 31, 2018 and 2017 primarily as the result of right-of-way options that were no longer in the Company's plans for developing midstream infrastructure. The Company recognized the impairment expense for the years ended December 31, 2016, as the result of contraction in the local oil and gas industry’s near term growth profile, therefore decreasing the need and support for a specifically proposed gas processing facility. Gain or loss on the sale of other property and equipment is reported in (gain) loss on sale of property and equipment in the consolidated statement of operations. The Company recognized $0.5 million of loss on the sale of other property and equipment related to the disposal of an oil pipeline that was not yet placed into service in the first quarter of 2017. Other property and equipment is recorded at cost and depreciated using the straight-line method.
The estimated useful lives of those assets depreciated under the straight-line basis are as follows:
Other property and equipment is comprised of the following (in thousands):
Gathering Systems and Facilities
Gathering systems and facilities consist of midstream assets such as land, rights of way, pipelines, equipment and construction and engineering costs associated with the construction of pipeline infrastructure to serve the development of the Company's acreage in its Hawkeye and Southwest Wattenberg areas. Approximately $112.3 million of gathering system and facilities assets have not been placed into service and therefore are not currently being depreciated. The Company will determine the estimated use lives of these assets when they are placed into service.
Gathering systems and facilities is comprised of the following (in thousands):
Equity Method Investments
Investments in entities for which the Company exercises significant influence, but not control, are accounted for under the equity method. The Company recorded $15.5 million and $8.3 million of such investments included in other non-current assets on the consolidated balance sheets as of December 31, 2018 and 2017, respectively. The Company recognized $2.9 million and $0.4 million of income from such investments, including the accretion of any basis difference between the carrying amount of the investment and the amount of underlying equity in net assets, included in other income on the consolidated statements of operations and equity in earnings of unconsolidated subsidiary, in which we have a minority ownership interest on the consolidated statements of cash flows for the year ended December 31, 2018 and 2017, respectively. The Company held no such investments during the years ended December 31, 2016.
On August 3, 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for year ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.
Deferred Lease Incentives
All incentives received from landlords for office leasehold improvements are recorded as deferred lease incentives and amortized over the term of the respective lease on a straight-line basis as a reduction of rental expense. Please refer to Recent Accounting Pronouncements for discussion related to Accounting Standard Update No. 2016-02, which updates the GAAP related to deferred lease incentives and will be effective as of January 1, 2019.
Debt Discount Costs
The $430.0 million in Second Lien Notes issued in May of 2014 were issued at a 1.5% original issue discount (“OID”) and the debt discount of $6.5 million was recorded as a reduction of the Second Lien Notes. The debt discount costs related to Second Lien Notes were amortized to interest expense using the effective interest method over the term of the debt.
Debt Issuance Costs
Debt issuance costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company’s credit facility, 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes"). Debt issuance costs related to the credit facility are included in other non-current assets on the consolidated balance sheets and amortized to interest expense on the consolidated statement of operations on a straight-line basis over the respective borrowing term. Debt issuance costs related to the Senior Notes are amortized to interest expense using the effective interest method over the term of the debt.
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production. The commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and commodity derivative liabilities. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments. Net gains and losses on commodity derivative instruments are recorded in the commodity derivative gain (loss) line on the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.
Any premiums paid on derivative contracts are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid. Premium payments are reflected in cash flows from operating activities in the Company's consolidated statements of cash flows. Over time, as the derivative contracts settle, the differences between the cash received and the premiums paid or fair value of contracts acquired are recognized in net gains or losses on commodity or interest rate derivate contracts, and the cash received is reflected in cash flows from operating activities in the Company's consolidated statements of cash flows.
The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of these factors result in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. Please refer to Note 6 - Commodity Derivative Instruments for additional discussion on commodity derivative instruments.
Goodwill and Other Intangible Assets
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed a quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its
carrying amount. The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company performed a quantitative assessment as of December 31, 2018, utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit was not greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety of the balance, for the year ended December 31, 2018. The Company performed a quantitative assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company performed a qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-likely-than-not greater than its carrying amount.
Costs relating to the acquisition of internal-use software licenses are capitalized when incurred and amortized over the estimated useful life of the license, which is typically one to three years. The Company recorded $3.0 million, $2.3 million and $0.3 million of internal-use software for the years ended December 31, 2018, 2017 and 2016, respectively, on the consolidated balance sheets within the goodwill and other intangible assets line item. Accumulated amortization for the years ended December 31, 2018, and 2017 was $3.1 million and $1.1 million, respectively. The Company recognized $2.1 million, $1.0 million and $0.1 million amortization expense for the years ended December 31, 2018, 2017 and 2016, respectively.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The Company’s Senior Notes are recorded at cost and the fair value is disclosed in Note 8 - Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.
Asset Retirement Obligation
The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 7 - Asset Retirement Obligations.
Environmental Liabilities
The Company is subject to federal, state and local environmental laws and regulations. These laws regulate the release, disposal or discharge of materials into the environment or otherwise relating to environmental protection and may require the Company to remove or mitigate the environmental effects of the discharge, disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or determinable. Management has determined that no significant environmental liabilities existed as of December 31, 2018.
Revenue Recognition
Revenues from the sale of oil, natural gas and NGL are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. The Company recognizes revenues from the sale of oil, natural gas and NGL using the sales method of accounting, whereby revenue is recorded based on the Company’s share of volume sold, regardless of whether the Company has taken its proportional share of volume produced. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2018, the Company has an oil imbalance of 22 MBbl, which the Company intends to settle with the counterparty in crude oil barrels. There were no material imbalances at December 31, 2017 or 2016.
On January 1, 2018, the Company adopted ASC 606 - Revenue from Contracts with Customers ("ASC 606"). See Adoption of ASC 606 for more information regarding the adoption of this standard.
Unit and Stock-Based Payments
The Company and its predecessor, Holdings, has granted restricted unit awards ("RUAs"), restricted stock units ("RSUs"), stock option awards and performance stock awards ("PSAs") to certain directors, officers and employees of the Company, which therefore required the Company to recognize the expense in its financial statements.
All unit and stock-based payments to directors, officers and employees are measured at fair value on the grant date and expensed over the relevant service period. The fair value of stock option awards is determined by using the Black-Scholes option pricing model. The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. All unit and stock-based payment expense is recognized using the straight-line method and is included within general and administrative expenses in the consolidated statements of operations and unit and stock-based compensation in the consolidated statements of cash flows. Forfeitures are recorded as they occur. Please refer to Note 11 - Unit and Stock-Based Compensation for additional discussion on unit and stock-based payments.
Income Taxes
The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and operating loss and tax credit carry forwards. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date. The tax returns and the amount of taxable income or loss are subject to examination by deferral and state taxing authorities.
The Company periodically assesses whether it is more likely than not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating losses. In making this determination, the Company considers all the available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. The Company believes it is more likely than not that certain net operating losses can be carried forward and utilized.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company does not currently have uncertain tax positions.
On December 22, 2017, United States legislation referred to as the Tax Cuts and Jobs Act (the "TCJA") was signed into law. Many of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes changes to the Internal Revenue Code of 1986 (as amended, the "Code"). The most significant change included in the TCJA is a reduction in the corporate federal income tax rate from 35% to 21%. As a result of the enactment date of December 22, 2017, the Company was required to remeasure the deferred tax assets and liabilities at the rate in which they are expected to reverse. This re-measurement of deferred tax assets and liabilities required the Company to analyze and record a one-time adjustment to reduce the overall deferred tax liability in the consolidated balance sheets and affect a corresponding income tax benefit in the consolidated statements of operations for the year ended December 31, 2017. The Company believes the accounting is complete regarding the revaluation of the deferred tax balances. This resulted in the recording of an income tax benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability as of December 31, 2017. During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. There are no remaining provisional amounts associated with the TCJA as of December 31, 2018.
Extraction Oil & Gas Holdings, LLC, the Company’s accounting predecessor, was a limited liability company that was not subject to U.S. federal income tax.
Earnings Per Share
Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the “if-converted” method to determine the potential dilutive effects of its Series A Preferred Stock, and the treasury stock method to determine the potential dilutive effect of outstanding restricted stock units and stock option awards. The Company’s EPS calculation for the year ended December 31, 2016 includes only the net income (loss) for the period subsequent to IPO and Corporate Reorganization which occurred on October 12, 2016 and has omitted EPS prior to this date. In addition, the basic weighted average shares outstanding calculation for the year ended December 31, 2016 is based on the actual days in which the shares were outstanding for the period from October 12, 2016, to December 31, 2016.
Segment Reporting
Beginning in the fourth quarter of 2018, the Company had two operating segments, (i) the exploration, development and production of oil, natural gas and NGL (the "exploration and production segment") and (ii) the construction and support of midstream assets to gather and process crude oil and gas production (the "gathering and facilities segment"). Prior to the fourth quarter of 2018, the Company had a single operating segment. The gathering systems and facilities operating segment is currently under development. Capital expenditures associated with gathering systems and facilities are being incurred to develop midstream infrastructure to support the Company's development of its oil and gas leasehold along with third-party activity. The activity of the exploration and production segment and gathering systems and facilities operating segment are being monitored by our chief operating decision maker ("CODM"). The Company expects the first phase of the gathering systems and facilities to be operational during the second half of 2019. Revenues associated with the exploration and production segment are derived from the sale of our oil and natural gas production, as well as the sale of NGL that are extracted from our natural gas during processing. Revenues and operating expenses associated with the gathering systems and facilities operations will be primarily derived from intersegment transactions for services provided to the Company's exploration, development and production operations by Elevation Midstream, LLC., an unrestricted subsidiary to the Company. All intersegment transactions are and will be eliminated upon consolidation, including revenues and operating expenses during the construction of and from gathering services provided by Elevation Midstream to the Company. The CODM considers Adjusted EBITDAX as the measure of segment performance under ASC 280, Segment Reporting. Accounting policies for each segment are the same as the accounting policies as described herein. For more information about Segments, see Note 15 - Segment Information.
All of the Company’s operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
Recent Accounting Pronouncements
The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on its consolidated financial statements and related disclosures.
In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2018-15, which aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.
In August 2018, the FASB issued ASU No. 2018-13, which improves the disclosure requirements on fair value measurements. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019, including interim reporting periods within that reporting period. The Company is currently evaluating this new standard to determine the potential impact to its financial statements and related disclosures.
In May 2017, the FASB issued ASU No. 2017-09, which provides clarification and reduces both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 Compensation - Stock Compensation, to a change to the terms or conditions of a share-based payment award. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that reporting period. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures.
In February 2017, the FASB issued ASU No. 2017-05, which provided clarification regarding the guidance on accounting for the derecognition of nonfinancial assets. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, including interim reporting periods within that fiscal year. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-04, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount. For public entities, the new guidance is effective for fiscal years beginning after December 15, 2019. Early adoption is permitted for interim and annual goodwill impairment tests performed on testing dates after January 1, 2017. The Company is currently evaluating the impact of adopting this ASU, however it is not expected to have a significant effect on its consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-01, which clarifies the definition of a business when evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018 and the adoption of this ASU did not have a material impact on the consolidated financial statements and related disclosures; however, this standard may result in more transactions being accounted for as asset acquisitions rather than business combinations.
In November 2016, the FASB issued ASU No. 2016-18, which intends to clarify how entities should present restricted cash and restricted cash equivalents in the statement of cash flows. This amendment was effective retrospectively for reporting periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2018 and the retrospective adoption increased the Company's beginning cash balances within the statement of cash flows for the prior period presented in the table below. The adoption had no other material impact on the cash flow statement and had no impact on the Company's results of operations or financial position.
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets to the consolidated statement of cash flows:
In August 2016, the FASB issued ASU No. 2016-15, which addresses eight specific cash flow issues, including presentation of debt prepayments or debt extinguishment costs, with the objective of reducing the existing diversity in practice. For public entities, the new guidance was effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The Company adopted this ASU on January 1, 2018, which requires current period make-whole premiums to be presented in financing activities in the statement of cash flows and prior period debt prepayment costs to be reclassified from operating activities to financing activities in the statement of cash flows; however, there was no impact to the total change in cash and cash equivalents from period to period.
In February 2016, the FASB issued ASU No. 2016-02, which requires lessee recognition on the balance sheet of a right of use asset and a lease liability, initially measured at the present value of the lease payments. It further requires recognition in the income statement of a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis. Finally, it requires classification of all cash payments within operating activities in the statements of cash flows. It is effective for fiscal years commencing after December 15, 2018 and early adoption is permitted. The FASB subsequently issued ASU No. 2017-13, ASU No. 2018-01, ASU No. 2018-10 and ASU No. 2018-11, which provided additional implementation guidance. The Company is currently evaluating the impact this ASU will have on the consolidated financial statements and related disclosures and expects certain lease agreements with terms over one year to be classified as right-of-use assets and right-of-use liabilities, which will gross up the consolidated balance sheet as of January 1, 2019. The Company will adopt the accounting standard using a modified retrospective transition approach, which applies the provisions of the new guidance at the effective date without adjusting the comparative periods presented. The Company has elected the package of practical expedients permitted under the transition guidance with the new standard, which among other
things, requires no reassessment of whether existing contracts are or contain leases as well as no reassessment of lease classification for existing leases upon adoption. The Company has also elected the optional practical expedient permitted under the transition guidance within the new standard related to land easements that allows it to carry forward its current accounting treatment for land easements on existing agreements upon adoption. The Company made an accounting policy election to keep leases with an initial term of twelve months or less off of the consolidated balance sheet. The Company is finalizing its evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements and on our future consolidated balance sheet upon adoption. As a part of the implementation work, the Company is validating the inputs and outputs of the software tool used to calculate the initial and ongoing accounting balances for right-of-use assets and liabilities and finalizing the completeness of the lease population.
In May 2014, the FASB issued ASU No. 2014-09, which establishes a comprehensive new revenue recognition model, referred to as ASC 606 - Revenue from Contracts with Customers, designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The ASU allows for the use of either the full or modified retrospective transition method. In August 2015, the FASB issued ASU No. 2015-14, which deferred ASU No. 2014-09 for one year, and was effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. The FASB subsequently issued ASU No. 2016-08, ASU No. 2016-10, ASU No. 2016-11, ASU No. 2016-12, ASU No. 2016-20, ASU No. 2017-13, ASU No. 2017-14 and ASU No. 2019-20, which provided additional implementation guidance. Refer to -Adoption of ASC 606 for more information.
Adoption of ASC 606
On January 1, 2018, the Company adopted ASC 606. The Company adopted ASC 606 using the modified retrospective method to apply the new standard to all new contracts entered into on or after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.
The impact of adoption in the year ended December 31, 2018 results are as follows (in thousands):
Changes to sales of natural gas and NGL, and transportation and gathering expenses are due to the conclusion that certain midstream processing entities are the Company's customers in natural gas processing and marketing agreements in accordance with the five-step process in ASC 606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the Company determined it was the principal, the midstream processor was the agent and the third-party end user was its customer. As a result, the Company modified its presentation of revenues and operating expenses for these agreements. Revenues related to these agreements are now presented on a net basis for proceeds expected to be received from the midstream processing entity. Revenues from the sale of oil, natural gas and NGL, where the Company is a non-operating interest partner, are considered in the scope of ASC 808 - Collaborative Arrangements. Therefore, ASC 606 did not change the presentation of these revenues.
Transportation and gathering expense related to other agreements incurred prior to the transfer of control to the customer at the tailgate of the natural gas processing facilities will continue to be presented as transportation and gathering expense.
Revenues from Contracts with Customers
Sales of oil, natural gas and NGL are recognized at the point control of the commodity is transferred to the customer and collectability is reasonably assured. The majority of the Company's contracts' pricing provisions are tied to a commodity market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas and NGL fluctuates to remain competitive with the other available oil, natural gas and NGL supplies.
Oil Sales
Under the Company's crude purchase and marketing contracts, the Company generally sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead at the net price received.
The Company utilizes the sales method to account for producer imbalances, which continues to be applicable under ASC 606. As of December 31, 2018, the Company has an oil imbalance of 22 MBbl, which the Company intends to settle with the counterparty in crude oil barrels.
Natural Gas and NGL Sales
Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity's system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGL and residue gas. In these scenarios, we evaluate whether we are the principal or the agent in the transaction, and the point at which control of the hydrocarbons transfer to the customer. For those contracts where the Company has concluded the midstream processing entity is the Company's agent and the third-party end user is its customer (generally the Company's fixed-fee gathering and processing agreements), the Company recognizes revenue on a gross basis, with transportation and gathering expense presented as an operating expense in the consolidated statements of operations. Alternatively, for those contracts where the Company has concluded the midstream processing entity is its customer and controls the hydrocarbons (generally the Company's percentage of proceeds gathering and processing agreements), the Company recognizes natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing company.
In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGL in-kind at the tailgate of the midstream entity's processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when the control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering and processing expense attributable to the gas processing contracts, as well as any transportation expense incurred to deliver the product to the purchaser, are presented as transportation and gathering expense in the consolidated statements of operations.
Performance Obligations
A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price of a contract that has an original expected duration of one year or less.
For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a), which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The Company records revenue on its oil, natural gas and NGL sales at the time production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the customer and the net commodity price that will be received for the sale of these commodity products. The Company records the differences between the revenue estimated and the actual amounts received for product sales in the month that payment is received from the customer. The Company has internal controls over its revenue estimation process and related accruals, and
any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2018 to December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Contract Balances
Under the Company's various sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's product sales contracts do not give rise to contract assets or liabilities under ASC 606.
The following table presents the Company's revenues disaggregated by revenue source. Transportation and gathering costs in the following table are not all of the transportation and gathering expenses that the Company incurs, only the expenses that are netted against revenues pursuant to ASC 606. Prior period amounts have not been adjusted under the modified retrospective method.
There are no other accounting standards applicable to the Company that have been issued but not yet adopted by the Company as of December 31, 2018, and through the date of this filing that would have a material impact on the Company’s consolidated financial statements and related disclosures.
Note 3-Oil and Gas Properties
The Company’s oil and gas properties are entirely within the United States. The net capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):
(1)
Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined.
(2)
Costs from wells in progress are excluded from the amortization base until production commences.
(3)
Includes accumulated interest capitalized of $32.6 million, $24.5 million and $13.4 million as of December 31, 2018, 2017 and 2016, respectively.
The following table presents information regarding the Company’s net costs incurred in oil and gas property acquisition, exploration and development activities (in thousands):
(1)
Exploration costs do not include impairment and abandonment costs of unproved properties, which are included in the line item exploration expenses in the consolidated statements of operations.
Note 4-Acquisitions and Divestitures
Assets Held for Sale
In January 2019, the Company entered into a definitive agreement with an unaffiliated oil and gas company to sell approximately 5,000 net acres of leasehold and producing properties primarily in Weld County, Colorado (the "Proposed March 2019 Divestiture") from its exploration and production segment. Upon closing, the Company will receive total consideration of approximately $22.4 million in cash, subject to customary purchase price adjustments. The effective date for the Proposed March 2019 Divestiture is July 1, 2018 with purchase price adjustments calculated as of the closing date, which is scheduled for late March 2019. These assets are classified as held for sale on the consolidated balance sheets.
The following table presents the information related to the assets held for sale in the December 31, 2018 consolidated balance sheet (in thousands):
The assets held for sale as of December 31, 2018 do not qualify for discontinued operations as they do not represent a strategic shift that will have a major effect of the Company's operations or financial results.
December 2018 Divestitures
In December 2018, the Company completed various sales of its interests in approximately 31,200 net acres of leasehold and primarily non-producing properties, for aggregate sales proceeds of approximately $8.5 million, subject to customary purchase price adjustments, and recognized a loss of $6.1 million.
August 2018 Divestiture
On August 3, 2018, Elevation received proceeds of $83.6 million and recognized a gain of $83.6 million for the year ended December 31, 2018, upon the sale of assets of DJ Holdings, LLC, a subsidiary of Discovery Midstream Partners, LP, of which Elevation held a 10% membership interest. The Company acquired its interest in exchange for the contribution of an acreage dedication, which is considered a nonfinancial asset.
April 2018 Divestitures
In April 2018, the Company completed various sales of its interests in approximately 15,100 net acres of leasehold and primarily non-producing properties for aggregate sales proceeds of approximately $72.3 million and recognized a gain of $59.3 million for the year ended December 31, 2018.
April 2018 Acquisition
On April 19, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,000 net acres of non-producing leasehold primarily located in Arapahoe County, Colorado (the "April 2018 Acquisition"). Upon closing the seller received approximately $9.4 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
January 2018 Acquisition
On January 8, 2018, the Company acquired an unaffiliated oil and gas company's interest in approximately 1,200 net acres of non-producing leasehold located in Arapahoe County, Colorado, (the "January 2018 Acquisition"). Upon closing the seller received approximately $11.6 million in cash. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
November 2017 Acquisition
On November 15, 2017, the Company acquired an unaffiliated oil and gas company's interest in approximately 36,600 net acres of leasehold and primarily non-producing properties located in Arapahoe County, Colorado, (the "November 2017 Acquisition"). Upon closing the seller received $214.3 million in cash, subject to customary purchase price adjustments. The Company also recorded a liability of $12.2 million for the final settlement payment due in April 2018 in conjunction with November 2017 Acquisition, which was reflected in the December 31, 2017 consolidated balance sheets within the accounts payable and accrued liabilities line item. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
July 2017 Acquisition
On July 7, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 12,500 net acres of leasehold and primarily non-producing properties located primarily in Adams County, Colorado, (the "July 2017 Acquisition"). Upon closing the seller received total consideration of $84.0 million in cash. The effective date for the July 2017 Acquisition is July 1, 2017. This transaction has been accounted for as an asset acquisition. The acquisition provided new development opportunities in the Core DJ Basin.
June 2017 Acquisition
On June 8, 2017, the Company acquired an unaffiliated oil and gas company’s interests in approximately 160 net acres of leasehold and related producing properties located in Weld County, Colorado (the “June 2017 Acquisition”). The Company paid approximately $13.4 million in cash consideration in connection with the closing of the June 2017 Acquisition. The effective date for the acquisition was January 1, 2017, with purchase price adjustments calculated as of the closing date of June 8, 2017. The acquisition increased the Company's interest in existing operated wells. The acquired producing properties contributed $3.3 million of revenue and $2.5 million of earnings, respectively, for the year ended December 31, 2018. The acquired producing properties contributed $3.7 million of revenue and $3.0 million of earnings, respectively, for the year ended December 31, 2017. The acquired producing properties contributed no revenue and earnings for the years ended December 31, 2016. No significant transaction costs related to the acquisition were incurred for the years ended December 31, 2018, 2017 and 2016.
The June 2017 Acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which required the acquired assets and liabilities to be recorded at fair value as of the acquisition date of June 8, 2017. In August 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
November 2016 Acquisition
On November 22, 2016, the Company acquired an unaffiliated oil and gas company’s interest in approximately 9,200 net acres of leaseholds located in the Core DJ Basin for approximately $120.0 million, including customary closing adjustments. The Company also made a $41.1 million deposit in November 2016 in conjunction with the November 2016 Acquisition. The deposit was made for two additional closings of leaseholds located in the Core DJ Basin. The first closing occurred in January 2017 and added approximately 5,300 net acres for approximately $26.8 million. The second closing occurred in July 2017 and added approximately 640 net acres for approximately $10.9 million. This transaction has been accounted for as an asset acquisition.
October 2016 Acquisition
On October 3, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 6,400 net acres of leasehold, and related producing and non-producing properties located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way, gathering systems and other assets (the “October 2016 Acquisition”). The seller received aggregate consideration of approximately $405.3 million in cash. The effective date for the acquisition was July 1, 2016, with purchase price adjustments calculated as of the closing date on October 3, 2016. The acquisition provided new development opportunities in the DJ Basin as well as increases the Company’s existing working interest, as the majority of the locations are located on acreage in which the Company already owns a majority working interest and operates. The acquired producing properties contributed revenue of $17.2 million for the year ended December 31, 2016. The Company determined that it is not practical to calculate net income associated with October 2016 Acquisition. The Company incurred $2.6 million of transaction costs related to the acquisition for year ended December 31, 2016. These transaction costs are recorded in the consolidated statements of operations within the acquisition transaction expenses line item. No transaction costs related to the acquisition were incurred for the years ended December 31, 2018 and 2017.
The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair value as of the acquisition date of October 3, 2016. In February 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
(1)
Goodwill was primarily attributable to a decrease in commodity prices from the time the acquisition was negotiated and commodity prices on October 3, 2016 and the operational and financial synergies expected to be realized from the acquisition. Goodwill recognized as a result of the October 2016 Acquisition was not deductible for income tax purposes.
Option to Acquire Additional Assets from October 2016 Acquisition
Upon the closing of the October 2016 Acquisition, the Company made a $10.0 million non-refundable payment for an option to purchase additional assets from the seller of the October 2016 Acquisition (the “Additional Assets”) for an additional $190.0 million, for a total purchase price for the Additional Assets of $200.0 million. The option may have been exercised at any time until March 31, 2017. If the Company did not exercise the option to acquire the Additional Assets, the seller would have had the right until April 30, 2017 to elect to sell those assets to the Company for an additional $120.0 million, for a total purchase price for the Additional Assets of $130.0 million. In March 2017, the Company entered into an amendment to this agreement with the seller to terminate both the Company's and seller’s options for no further consideration. The $10.0 million was expensed in the fourth quarter of 2016 to other operating expenses within the consolidated statements of operations.
August 2016 Acquisition
On August 23, 2016, the Company acquired an unaffiliated oil and gas company’s interests in approximately 1,400 net acres of leasehold located primarily in Weld County, Colorado, along with various other related rights, permits, contracts, equipment, rights of way and other assets (the “August 2016 Acquisition”). The seller received aggregate consideration of approximately $17.5 million in cash. The effective date for the acquisition was August 31, 2016, with purchase price adjustments calculated as of the closing date of August 23, 2016. The acquisition provided new development opportunities in the DJ Basin as well as additions adjacent to the Company’s core project area. The Company incurred $0.1 million of transaction costs related to the acquisition. These transaction costs were recorded in the condensed consolidated statements of operations within the acquisition transaction expenses line item in the third quarter of 2016.
The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which required the acquired assets and liabilities to be recorded at fair value as of the acquisition date of August 23, 2016. In March 2017, the Company completed the transaction’s post-closing settlement. The following table summarizes the purchase price and the final allocation of the fair values of assets acquired and liabilities assumed (in thousands):
Pro Forma Financial Information (Unaudited)
For the years ended December 31, 2017 and 2016, the following pro forma financial information represents the combined results for the Company and the properties acquired in June 2017 and in October 2016 as if the acquisitions and related financing had occurred on January 1, 2016. For purposes of the pro forma financial information, it was assumed that the June 2017 Acquisition was funded through cash. For purposes of the pro forma financial information, it was assumed that the October 2016 Acquisition was funded through the issuance of $260.3 million in convertible preferred securities and borrowings under the revolving credit facility. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $1.6 million and $23.1 million for the years ended December 31, 2017 and 2016, respectively. No pro forma adjustments were made for non-recurring transaction costs for the year ended December 31, 2017. The pro forma information includes the effects of a decrease in non-recurring transaction costs that are included in general and administrative expenses and acquisition transaction expenses of $2.6 million for the year ended December 31, 2016. No pro forma adjustments were made for incremental interest expense on acquisition financing for the year ended December 31, 2017. The pro forma information includes the effects of adjustments for the incremental interest expense on acquisition financing of $4.0 million for the year ended December 31, 2016. The pro forma information includes the effects of adjustments for income taxes of $0.6 million for the year ended December 31, 2017. No pro forma adjustments were made for the effect of income taxes for the year ended December 31, 2016 as the acquisition occurred before the Corporate Reorganization. Additionally, the pro forma financial information excludes the effects the August 2016 Acquisition as these pro forma adjustments were de minimis.
The following pro forma results (in thousands, except per share data) do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Net income (loss) per share is not applicable for the period prior to the Corporate Reorganization.
Note 5-Long-Term Debt
As of the dates indicated the Company’s long-term debt consisted of the following (in thousands):
Credit Facility
On September 4, 2014, Holdings entered into a credit facility with a syndicate of banks, which is subject to a borrowing base. In connection with the IPO and the merger of Holdings into the Company, the Company assumed all of the obligations of Holdings under the credit facility and became the borrower thereunder.
In August 2017, the Company entered into an amendment and restatement of its existing credit facility (prior to amendment and restatement, the "Prior Credit Facility"), to provide aggregate commitments of $1.5 billion with a syndicate of banks, which is subject to a borrowing base. The credit facility matures on the earlier of (a) August 16, 2022, (b) January 15, 2021 if (and only if) the Company's 2021 Senior Notes (as defined below) have not been refinanced or repaid in full on or prior to January 15, 2021, (c) April 15, 2021, if (and only if) (i) the Series A Preferred Stock of the Company (the "Series A Preferred Stock") have not been converted into common equity or redeemed prior to April 15, 2021, and (ii) prior to April 15, 2021, the maturity date of the Series A Preferred Stock has not been extended to a date that is no earlier than six months after August 16, 2022 or (d) the earlier termination in whole of the commitments. No principal payments are generally required until the credit agreement matures or in the event that the borrowing base falls below the outstanding balance.
In January 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $525.0 million to $750.0 million, subject to the current elected commitments of $650.0 million, (ii) increase the maximum amount for the letter of credit issued in favor of a purchaser of its crude oil from $25.0 million to $35.0 million, and (iii) amend certain provisions of the credit agreement, including the commitments and allocations of each lender. In connection with the 2026 Senior Notes Offering (as defined below), the borrowing base was automatically reduced to $700.0 million; however, the current elected commitments remained at $650.0 million.
In February 2018, the Company entered into a consent agreement and amended its revolving credit facility to (i) provide for consent by the lenders to (a) the designation of Elevation as an unrestricted subsidiary and (b) the transfer of certain
assets by the Company and one of the guarantors to such unrestricted subsidiary; and (ii) amend certain provisions of the credit agreement, including the incurrence of indebtedness covenant to permit certain indebtedness in connection with certain transportation service agreements with such unrestricted subsidiary.
In May 2018, the Company amended its revolving credit facility to (i) increase the borrowing base from $700.0 million to $800.0 million, subject to current elected commitments of $650.0 million and (ii) reduce each of the applicable interest rate margins for borrowings by 0.50%.
In October 2018, the Company amended its revolving credit facility to (i) postpone the November 1, 2018 scheduled borrowing base redetermination until December 15, 2018 and (ii) permit the Company to make payments with respect to its own equity, subject to certain terms, conditions and financial thresholds.
In December 2018, the Company amended its revolving credit facility to increase the borrowing base from $800.0 million to $1.2 billion, associated with the postponed November 1, 2018 scheduled borrowing base determination. The current elected commitments remained at $650.0 million.
In January 2019, the Company amended its revolving credit facility to permit prepayments and redemptions of the Company’s unsecured bonds, subject to certain terms, conditions and financial thresholds.
As of December 31, 2018, the credit facility was subject to a borrowing base of $1.2 billion, subject to current elected commitments of $650.0 million. As of December 31, 2018, the Company had $285.0 million of borrowings outstanding. As of December 31, 2017, the Company had $90.0 million outstanding borrowings. As of December 31, 2018 and 2017, the Company had standby letters of credit of $35.7 million and $25.7 million, respectively, which reduce the availability of the undrawn borrowing base. At December 31, 2018, the undrawn balance under the credit facility was $365.0 million. As of the date of this filing, the Company had $285.0 million borrowings outstanding under the credit facility.
The amount available to be borrowed under the Company's revolving credit facility is subject to a borrowing base that is redetermined semiannually on each May 1 and November 1, and will depend on the volumes of the Company's proved oil and gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Company's revolving credit facility.
Interest on the credit facility is payable at one of the following two variable rates as selected by the Company: a base rate based on the Prime Rate or the Eurodollar rate, based on LIBOR. Either rate is adjusted upward by an applicable margin, based on the utilization percentage of the facility as outlined in the Pricing Grid. Additionally, the credit facility provides for a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. The grid below shows the Base Rate Margin and Eurodollar Margin depending on the applicable Borrowing Base Utilization Percentage (as defined in the credit facility) as of the date of this filing:
Borrowing Base Utilization Grid
The credit facility contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on dividends, distributions, redemptions and restricted payments covenants; (iii) limitations on investments, loans and advances covenants; and (iv) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. Additionally, the credit facility limits the Company from hedging in excess of 85% of its anticipated production volumes.
The credit facility also contains financial covenants requiring the Company and its restricted subsidiaries to comply with a current ratio of its consolidated current assets (includes availability under the revolving credit facility and excludes
derivative assets) to its consolidated current liabilities (excludes the current portion of long-term debt and derivative liabilities), of not less than 1.0 to 1.0 and to maintain, on the last day of each quarter, a ratio of consolidated debt less cash balances to its consolidated EBITDAX (EBITDAX is defined as net income adjusted for certain cash and non-cash items including DD&A, exploration expense, gains/losses on derivative instruments, amortization of certain debt issuance costs, non-cash compensation expense, interest expense and prepayment premiums on extinguishment of debt) for the four fiscal quarter period most recently ended, not to exceed 4.0 to 1.0 as of the last day of such fiscal quarter. The Company was in compliance with all financial covenants under the credit facility as of December 31, 2018.
Any borrowings under the credit facility are collateralized by substantially all of the assets of the Company and its subsidiaries, including oil and gas properties, personal property and the equity interests of the subsidiaries of the Company. The Company has entered into oil and natural gas hedging transactions with several counterparties that are also lenders under the credit facility. The Company’s obligations under these hedging contracts are secured by the collateral securing the credit facility.
Second Lien Notes
On May 29, 2014, Holdings entered into a five year, $430.0 million term loan facility with a syndicate of lenders (the “Second Lien Notes”). The Second Lien Notes would have matured on May 29, 2019. Holdings had drawn the full $430.0 million under the Second Lien Notes that bore an average interest rate of approximately 10.7%. The interest rates were fixed and interest was payable semi-annually.
In July 2016, the Second Lien Notes were repaid and terminated in conjunction with the 2021 Senior Notes Offering. The Company used the proceeds from the 2021 Senior Notes (as discussed below) to repay the outstanding $430.0 million of principal and a $4.3 million prepayment penalty. The prepayment penalty was expensed during the year ended December 31, 2016 in the consolidated statements of operations within the interest expense line item. Additionally, during the year ended December 31, 2016, the Company wrote off approximately $15.1 million of unamortized debt discount and debt issuance costs that were related to the Second Lien Notes. The write off of the unamortized debt discount and debt issuance costs were recorded in the consolidated statements of operations within the interest expense line item.
2021 Senior Notes
In July 2016, the Company issued at par $550.0 million principal amount of 7.875% Senior Notes due July 15, 2021 (the “2021 Senior Notes” and the offering, the "2021 Senior Notes Offering"). The 2021 Senior Notes bore an annual interest rate of 7.875%. The interest on the 2021 Senior Notes was payable on January 15 and July 15 of each year commencing on January 15, 2017. The Company received net proceeds of approximately $537.2 million after deducting discounts and fees.
Concurrent with the 2026 Notes Offering, the Company commenced a cash tender offer to purchase any and all of its 2021 Senior Notes. On January 24, 2018, the Company received approximately $500.6 million aggregate principal amount of the 2021 Senior Notes which were validly tendered (and not validly withdrawn). As a result, on January 25, 2018 the Company made a cash payment of approximately $534.2 million, which included principal of approximately $500.6 million, a make-whole premium of approximately $32.6 million and accrued and unpaid interest of approximately $1.0 million.
On February 17, 2018, the Company redeemed approximately $49.4 million aggregate principal amount of the 2021 Senior Notes that remained outstanding after the Tender Offer and made a cash payment of approximately $52.7 million to the remaining holders of the 2021 Senior Notes, which includes a make-whole premium of $3.0 million and accrued and unpaid interest of approximately $0.3 million.
2024 Senior Notes
In August 2017, the Company issued at par $400.0 million principal amount of 7.375% Senior Notes due May 15, 2024 (the “2024 Senior Notes” and the offering, the “2024 Senior Notes Offering”). The 2024 Senior Notes bear an annual interest rate of 7.375%. The interest on the 2024 Senior Notes is payable on May 15 and November 15 of each year commencing on November 15, 2017. The Company received net proceeds of approximately $392.6 million after deducting discounts and fees.
The Company's 2024 Senior Notes are its senior unsecured obligations and rank equally in right of payment with all of its other senior indebtedness and senior to any of its subordinated indebtedness. The Company's 2024 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of its current subsidiaries and by certain future restricted
subsidiaries that guarantees its indebtedness under a credit facility (the “2024 Senior Note Guarantors”). The 2024 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under its revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of its future subsidiaries that do not guarantee the 2024 Senior Notes.
The 2024 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company's and the Guarantors' ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company's affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2024 Senior Notes (the “2024 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2024 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2024 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2024 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2024 Senior Notes Indenture as of December 31, 2018.
2026 Senior Notes
In January 2018, the Company closed a private offering of its 2026 Senior Notes (the “2026 Senior Notes” and the offering, the "2026 Senior Notes Offering") that resulted in net proceeds of approximately $737.9 million after deducting discounts and fees. The Company used $534.2 million of the net proceeds from the 2026 Senior Notes Offering to tender for its 2021 Senior Notes, $52.7 million to redeem any 2021 Senior Notes not tendered and the remainder for general corporate purposes. The Company's 2026 Senior Notes bear interest at an annual rate of 5.625%. Interest on the Company's 2026 Senior Notes is payable on February 1 and August 1 of each year, and the first interest payment was made on August 1, 2018. The Company's 2026 Senior Notes will mature on February 1, 2026.
The Company's 2026 Senior Notes are the Company's senior unsecured obligations and rank equally in right of payment with all of the Company's other senior indebtedness and senior to any of the Company's subordinated indebtedness. The Company's 2026 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of the Company's current subsidiaries and by certain future restricted subsidiaries that guarantee the Company's indebtedness under a credit facility. The 2026 Senior Notes are effectively subordinated to all of the Company's secured indebtedness (including all borrowings and other obligations under the Company's revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated in right of payment to all existing and future indebtedness and other liabilities (including trade payables) of any of the Company's future subsidiaries that do not guarantee the 2026 Senior Notes.
The 2026 Senior Notes also contain affirmative and negative covenants that, among other things, limit the Company’s and the Guarantors’ ability to make investments; declare or pay any dividend or make any other payment to holders of the Company’s or any of its Guarantors’ equity interests; repurchase or redeem any equity interests of the Company; repurchase or redeem subordinated indebtedness; incur additional indebtedness or issue preferred stock; create liens; sell assets; enter into agreements that restrict dividends or other payments by restricted subsidiaries; consolidate, merge or transfer all or substantially all of the assets of the Company; engage in transactions with the Company’s affiliates; engage in any business other than the oil and gas business; and create unrestricted subsidiaries. The indenture governing the 2026 Senior Notes (the “2026 Senior Notes Indenture”) also contains customary events of default. Upon the occurrence of events of default arising from certain events of bankruptcy or insolvency, the 2026 Senior Notes shall become due and payable immediately without any declaration or other act of the trustee or the holders of the 2026 Senior Notes. Upon the occurrence of certain other events of default, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 2024 Senior Notes may declare all outstanding 2026 Senior Notes to be due and payable immediately. The Company was in compliance with all financial covenants under the 2026 Senior Notes Indenture as of December 31, 2018.
Debt Discount Costs on Second Lien Notes
The Company’s Second Lien Notes were issued with an original issue discount (OID) of $6.5 million. In July 2016, the Company repaid the Second Lien Notes in full and accelerated the remaining unamortized balance of $4.3 million. This expense was recorded in the consolidated statements of operations within the interest expense line item. As of December 31, 2017, there was no remaining balance on the OID.
Debt Issuance Costs
As of December 31, 2018 and 2017, the Company had debt issuance costs net of accumulated amortization of $3.3 million and $3.8 million, respectively, related to its credit facility which has been reflected on the Company’s consolidated balance sheet within the line item other non-current assets. As of December 31, 2018, the Company had debt issuance costs net of accumulated amortization of $17.3 million related to its 2024 and 2026 Senior Notes (collectively, the "Senior Notes"), and as of December 31, 2017, the Company had debt issuance costs net of accumulated amortization of $16.6 million related to its 2021 and 2024 Senior Notes, which has been reflected on the Company's consolidated balance sheet within the line item Senior Notes, net of unamortized debt issuance costs. Upon the repayment of the Company’s Second Lien Notes in July 2016, the Company accelerated the amortization of the remaining $10.8 million of unamortized debt issuance costs. As of December 31, 2018 and 2017, there was no remaining balance on debt issuance costs associated with the Second Lien Notes. Upon the redemption of the Company's 2021 Senior Notes in January and February 2018, the Company accelerated the amortization of the remaining $9.4 million of unamortized debt issuance costs. These expenses were recorded in the consolidated statements of operations within the interest expense line item. Debt issuance costs include origination, legal, engineering, and other fees incurred in connection with the Company’s credit facility and Senior Notes. For the years ended December 31, 2018, 2017, and 2016, the Company recorded amortization expense related to the debt issuance costs of $13.2 million, $4.3 million and $14.4 million, respectively.
Interest Incurred on Long-Term Debt
For the years ended December 31, 2018, 2017 and 2016, the Company incurred interest expense on long-term debt of $82.7 million, $58.7 million and $50.5 million, respectively, and capitalized interest of $8.2 million, $11.1 million and $5.2 million, respectively, for the years ended December 31, 2018, 2017 and 2016. Included in interest expense for the year ended December 31, 2018 is a make-whole premium of $35.6 million related to the Company's redemption of its 2021 Senior Notes in January and February 2018. Also included in interest expense for the year ended December 31, 2017 is a prepayment penalty of $4.3 million related to the Company’s repayment of its Second Lien Notes in July 2016.
Senior Note Repurchase Program
On January 4, 2019, the Board of Directors authorized a program, subject to the amendment to the Company's revolving credit facility, to repurchase up to $100.0 million of the Company’s Senior Notes. The Company’s Senior Notes Repurchase Program does not obligate it to acquire any specific nominal amount of Senior Notes. As of the date of this filing, the Company has repurchased 2026 Senior Notes with a nominal value of $13.1 million for $10.5 million in connection with the Senior Notes Repurchase Program.
Note 6-Commodity Derivative Instruments
The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, put options and call options to reduce the effect of price changes on a portion of the Company’s future oil and natural gas production.
A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless. Some of the Company’s purchased put options have deferred premiums. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement.
A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.
The Company combines swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging strategies. Some examples of the Company’s hedging strategies are collars which include purchased put options and sold call options, three-way collars which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap.
The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with eleven counterparties, all of whom are lenders under our credit agreement. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparties in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. There are no credit-risk-related contingent features or circumstances in which the features could be triggered in derivative instruments that are in a net liability position at the end of the reporting period.
The Company’s commodity derivative contracts as of December 31, 2018 are summarized below:
The following tables detail the fair value of the Company’s derivative instruments, including the gross amounts and adjustments made to net the derivative instruments for the presentation in the balance sheets (in thousands):
(1)
Agreements are in place with all of the Company’s financial trading counterparties that allow for the financial right of offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements.
(2)
Netting for balance sheet presentation is performed by current and non-current classification. This adjustment represents amounts subject to an enforceable master netting arrangement, which are not netted on the balance sheet. There are no amounts of related financial collateral received or pledged.
(3)
Net amounts are not split by current and non-current. All counterparties in a net asset position are shown in the current asset line item and all counterparties in a net liability position are shown in the current liability line item.
(4)
Gross current liabilities include a deferred premium liability of $7.7 million related to the Company's deferred put premiums. Gross current assets include a deferred premium asset of $0.8 million related to the Company's deferred put premiums.
The table below sets forth the commodity derivatives loss for the years ended December 31, 2018, 2017 and 2016 (in thousands). Commodity derivatives loss are included under other income (expense).
Note 7-Asset Retirement Obligations
The Company follows accounting for asset retirement obligations in accordance with ASC 410, Asset Retirement and Environmental Obligations, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut-in wells at the end of their productive lives in accordance with applicable local, state and federal laws, and applicable lease terms. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement costs are depleted with proved oil and gas properties using the unit of production method.
The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated (in thousands):
Note 8-Fair Value Measurements
ASC 820, Fair Value Measurement and Disclosure, establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability developed based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:
•
Level 1: Quoted prices are available in active markets for identical assets or liabilities;
•
Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability;
•
Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash flow models or valuations.
The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between levels during any periods presented below.
The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2018 and December 31, 2017 by level within the fair value hierarchy (in thousands):
The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above:
Commodity Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market based approach that takes into account several factors, including quoted market prices in active markets, implied market volatility factors, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. Derivative instruments utilized by the Company consist of swaps, put options, and call options. The oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
Fair Value of Financial Instruments
The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. The fair value of the 2021 Senior Notes, 2024 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes") was derived from available market data. As such, the Company has classified the Senior Notes as Level 2. Please refer to Note 5 - Long-Term Debt for further information. The Company’s policy is to recognize transfers between levels at the end of the period. This disclosure (in thousands) does not impact the Company’s financial position, results of operations or cash flows.
(1)
The carrying amount of the 2021 Senior Notes includes unamortized debt issuance costs of $9.6 million as of December 31, 2017. There were no unamortized debt issuance costs as of December 31, 2018.
(2)
The carrying amount of the 2024 Senior Notes includes unamortized debt issuance costs of $6.1 million and $7.0 million as of December 31, 2018 and 2017, respectively.
(3)
The carrying amount of the 2026 Senior Notes includes unamortized debt issuance costs of $11.2 million as of December 31, 2018. There were no unamortized debt issuance costs as of December 31, 2017.
Non-Recurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including proved property and goodwill. These assets and liabilities are not measured at fair
value on a recurring basis, but are subject to fair value adjustments when facts are circumstances arise that indicate a need for measurement.
The Company utilizes fair value on a non-recurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. The Company uses an income approach analysis based on the net discounted future cash-flows of producing property. The future cash-flows are based on Management’s estimates for the future. Unobservable inputs included future estimates of oil and gas production, as the case may be, from the Company’s reserve reports, commodity prices based on the sales contract terms or forward price curves, operating and development costs, and a discount rate based on a market-based weighted average cost of capital (all of which are Level 3 inputs within the fair value hierarchy). For the years ended December 31, 2018 and 2016, the Company recognized $16.2 million and $22.5 million in impairment expense on proved oil and gas properties, respectively. The impairment expense for the years ended December 31, 2018 and 2016 is related to impairment of the assets in the Company’s northern field. The future undiscounted cash flows did not exceed its carrying amount associated with its proved oil and gas properties in the Company’s northern field. A portion of the net book value of these proved oil and gas properties were impaired at September 30, 2018 and the proved oil and gas properties in the northern field were written down to their fair value. The full net book value of these proved oil and gas properties were impaired at June 30, 2016 as it was determined that the proved oil and gas properties had no remaining fair value. No impairment expense was recognized for the year ended December 31, 2017 on proved oil and gas properties.
The Company applies the provisions of ASC 350, Intangibles-Goodwill and Other. Goodwill represents the excess of the purchase price over the estimated value of the net assets acquired in business combinations. The Company tests goodwill for impairment annually on September 30, or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. The goodwill test is performed at the reporting unit level, which represents the Company’s oil and gas operations in its core DJ Basin field. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. Any sharp prolonged decreases in the prices of oil and natural gas as well as continued declines in the quoted market price of the Company’s common shares could change the estimates of the fair value of the reporting unit and could result in an impairment charge. The Company performed a quantitative assessment as of September 30, 2018, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company identified triggering events as of December 31, 2018, due to the decrease in commodity pricing and the quoted market price of the Company's common shares compared to September 30, 2018. As such, the Company performed a quantitative assessment as of December 31, 2018, utilizing an income approach based on estimates of the expected discounted future cash flows of the reporting unit's oil and gas properties, which concluded the fair value of the reporting unit was not greater than its carrying amount. As a result, the Company recorded goodwill impairment of $54.2 million, the entirety of the balance, for the year ended December 31, 2018. The Company performed a quantitative assessment as of September 30, 2017, which concluded the fair value of the reporting unit was greater than its carrying amount. The Company performed a qualitative assessment as of December 31, 2017 and 2016, which concluded the fair value of the reporting unit was more-likely-than-not greater than its carrying amount.
The Company’s other non-recurring fair value measurements include the purchase price allocations for the fair value of assets and liabilities acquired through business combinations, please refer to Note 4 - Acquisitions and Divestitures. The fair value of assets and liabilities acquired through business combinations is calculated using a discounted-cash flow approach using level 3 inputs. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including risk-adjusted oil and gas reserves, commodity prices, development costs, and operating costs, based on market participant assumptions. The fair value of assets or liabilities associated with purchase price allocations is measured on a non-recurring basis and is not measured in periods after initial recognition.
Note 9-Equity
Stock Repurchase Program
On November 19, 2018, the Company announced the Board of Directors had authorized a program to repurchase up to $100.0 million of the Company's common stock ("Stock Repurchase Program"). During the year ended December 31, 2018, the Company repurchased 4.1 million shares of its common stock for $26.2 million, at a weighted average per share price of $6.47 per share, in connection with the Stock Repurchase Program. The Company's Stock Repurchase Program does not obligate it to acquire any specific number of shares and will expire on March 31, 2019. The Company intends to conduct any open market stock repurchase activities in compliance with the safe harbor provisions of Rule 10b-18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act").
Preferred Units
On July 3, 2018, Elevation Midstream, LLC (“Elevation”), a Delaware limited liability company and subsidiary of the Company, entered into a securities purchase agreement (the “Securities Purchase Agreement”) with a third party (the "Purchaser"), pursuant to which Elevation agreed to sell 150,000 Preferred Units (the “Elevation Preferred Units”) of Elevation at a price of $990 per Elevation Preferred Unit with an aggregate liquidation preference of $150.0 million (the “Private Placement”), in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The Private Placement closed on July 3, 2018 (the “Preferred Unit Closing Date”), funded on July 19, 2018 and resulted in net proceeds of approximately $141.9 million, $25.4 million of which was a reimbursement for previously incurred midstream capital expenditures and general and administrative expenses. These Preferred Units are non-recourse to Extraction and represent the noncontrolling interest presented on the consolidated balance sheets, consolidated statement of operations and consolidated statement of changes in members' and stockholders' equity and noncontrolling interest. Elevation is a separate entity and the assets and credit of Elevation are not available to satisfy the debts and other obligations of the Company or its other subsidiaries. As of December 31, 2018, $136.9 million of cash was held by Elevation and is earmarked for construction of pipeline infrastructure to serve the development of acreage in its Hawkeye and Southwest Wattenberg areas. As of December 31, 2018 and 2017, Elevation capital expenditures represented all of the gathering systems and facilities line item in the consolidated balance sheet and the gathering systems and facilities additions in the consolidated statement of cash flows.
During the twenty-eight months following the Preferred Unit Closing Date (the “Preferred Unit Commitment Period”), subject to the satisfaction of certain financial and operational metrics and certain other customary closing conditions, Elevation has the right to require the Purchaser to purchase additional Elevation Preferred Units on the terms set forth in the Securities Purchase Agreement. Elevation may require the Purchaser to purchase additional Elevation Preferred Units, in increments of at least $25.0 million, up to an aggregate amount of $350.0 million. During the Preferred Unit Commitment Period, Elevation is required to pay the Purchaser a quarterly commitment fee payable in cash or in kind of 1.0% per annum on any undrawn amounts of such additional $350.0 million commitment. Elevation recognized $1.8 million of commitment fees paid-in-kind for the year ended December 31, 2018, included under the Preferred Unit commitment fees and dividends paid-in-kind line item in the consolidated statement of changes in members' and stockholders' equity and noncontrolling interest. No such fees were recognized for the year ended December 31, 2017 or 2016.
The Elevation Preferred Units will entitle the Purchaser to receive quarterly dividends at a rate of 8.0% per annum. In respect of quarters ending prior to and including June 30, 2020, such dividend is payable in cash or in kind at the election of Elevation. After June 30, 2020, such dividend is payable solely in cash. Elevation recognized $5.5 million of dividends paid-in-kind for the year ended December 31, 2018, included under the Preferred Unit commitment fees and dividends paid-in-kind line item in the consolidated statement of changes in members' and stockholders' equity and noncontrolling interest. No such fees were recognized for the years ended December 31, 2017 or 2016.
Private Placement of Common Stock
On December 15, 2016, the Company completed the issuance of 25.0 million shares of common stock, at a price of $18.25 per share, in connection with the Private Placement (the “Private Placement”). The Private Placement resulted in approximately $457.0 million of gross proceeds and approximately $441.9 million of net proceeds, after deducting placement agent commissions and offering expenses. Proceeds from the Private Placement were to be used for general corporate purposes, including to fund the Company’s 2017 capital expenditures.
Initial Public Offering
On October 17, 2016, the Company completed its initial public offering, issuing 38.3 million shares of common stock, par value $0.01 per share (“common stock”), which included the full exercise of the underwriters’ over-allotment option of 5.0 million shares at a price of $19.00 per share. The net proceeds of the offering were $681.0 million, after deducting underwriting discounts and commissions and offering expenses, of approximately $47.3 million. The proceeds from the Offering were used to (i) redeem in full the Series A Preferred Units for $90.0 million and (ii) to repay borrowings under the Company’s revolving credit facility for $291.6 million. The remaining net proceeds were to be used for general corporate purposes, including to fund 2017 capital expenditures. The material terms of the Offering are described in the Company’s final prospectus, dated October 11, 2016 and filed with the SEC pursuant to Rule 424(b)(4) of the Securities Act of 1933, as amended, on October 13, 2016.
Series A Preferred Units
On October 3, 2016, the Company issued $75.0 million in Series A Preferred Units (the “Series A Preferred Units”) to fund a portion of the purchase price for the October 2016 Acquisition. The Series A Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears. All holders of Series A Preferred Units were also members of Holdings. The Company used $90.0 million of the net proceeds from its IPO to redeem the Series A Preferred Units in full on October 17, 2016, including a premium of $15.0 million which is recorded within additional paid in capital in the consolidated statement of changes in members' and stockholders' equity and noncontrolling interest. For further discussion on the October 2016 Acquisition, please refer to Note 4 - Acquisitions and Divestitures.
Series A Preferred Stock and Series B Preferred Units
On October 3, 2016, the Company issued $185.3 million in convertible preferred securities ("Series B Preferred Units") to fund a portion of the purchase price for the October 2016 Acquisition. The Series B Preferred Units were entitled to receive a cash dividend of 10% per year, payable quarterly in arrears, and the Company had the ability to pay up to 50% of the quarterly dividend in kind. For the year ended December 31, 2016, the Company paid $0.7 million of dividends associated with the Series B Preferred Units. The Company did not make any payments in kind on the Series B Preferred Units from the date of issuance of the Series B Preferred Units through the Offering. The Series B Preferred Units converted in connection with the closing of the IPO into 185,280 shares of Series A Convertible Preferred Stock (the "Series A Preferred Stock") that are entitled to receive a cash dividend of 5.875% per year, payable quarterly in arrears, and the Company has the ability to pay such quarterly dividends in kind at a dividend rate of 10% per year (decreased proportionately to the extent such quarterly dividends are paid in cash). For the year ended December 31, 2018, the Company accrued $2.7 million of dividends associated with the Series A Preferred Stock, or $14.69 per share, which were paid in January 2019. The Company did not make any payments in kind on the Series A Preferred Stock from the date of the Offering through December 31, 2017. Beginning on or after the later of (a) 90 days after the closing of the Offering and (b) the earlier of 120 days after the closing of the Offering and the expiration of the lock-up period contained in the underwriting agreement entered into in connection with the Offering ("Lock-Up Period End Date"), the Series A Preferred Stock will be convertible into shares of the Company's common stock at the election of the holders of the Series A Preferred Stock ("Series A Preferred Holders") at a conversion ratio per share of Series A Preferred Stock of 61.9195. Beginning on or after the Lock-Up Period End Date until the three year anniversary of the closing of the Offering, the Company may elect to convert the Series A Preferred Stock at a conversion ratio per share of Series A Preferred Stock of 61.9195, but only if the closing price of the Company’s common stock trades at or above a certain premium to the Company’s initial offering price, such premium to decrease with time. In accordance with ASC Topic 470, Debt ("ASC 470"), the Company determined that the conversion feature of the Series A Preferred Stock represented a beneficial conversion feature. The fair value of the Company's common stock on the closing of the IPO was greater than the Series A Preferred Stock conversion price by approximately $32.7 million in aggregate. Under ASC 470, $32.7 million (the fair value of the beneficial conversion feature) of the proceeds received from the issuance of the Series B Preferred Units, subsequently converted to the Series A Preferred Stock, was allocated to additional paid-in capital. The beneficial conversion feature is required to be accreted on a non-cash basis over the approximate 60 month period between the issuance date and the required redemption date of October 15, 2021, or fully accreted upon an accelerated date of redemption or conversion, resulting in an increase of the Series A Convertible Preferred Stock presented on the Consolidated Balance Sheets. The accretion of the beneficial conversion feature of Series A Preferred Stock is presented as a decrease to additional paid-in capital on the changes in members' and stockholders' equity and noncontrolling interest. As a result, approximately $6.0 million and $5.4 million was accreted during the years ended December 31, 2018 and 2017. In certain situations, including a change of control, the Series A Preferred Stock may be redeemed for cash in an amount equal to the greater of (i) 135% of the liquidation preference of the Series A Preferred Stock and (ii) a 17.5% annualized internal rate of return on the liquidation preference of the Series A Preferred Stock. The Series A Preferred Stock mature on October 15, 2021, at which time they are mandatorily redeemable for cash at the liquidation preference.
Note 10-Income Taxes
On December 22, 2017, the Tax Cuts and Jobs Act (the “TCJA”) was enacted making significant changes to the Internal Revenue Code. Many of the provisions in the TCJA have an effective date for years beginning after December 31, 2017, including the lowering of the U.S. corporate rate from 35 percent to 21 percent. As a result, the Company was required to remeasure the deferred tax assets and liabilities as of December 31, 2017 at the rate in which they are expected to reverse. This re-measurement of deferred tax assets and liabilities required the Company to analyze and record a one-time adjustment to reduce the overall deferred tax liability in the consolidated balance sheets and reflect a corresponding income tax benefit in the consolidated statements of operations for the year ended December 31, 2017. This resulted in the recording of an income tax benefit of $23.4 million, as well as a corresponding reduction in the deferred tax liability as of December 31, 2017.
During the third quarter of 2018, we completed the accounting for the income tax effect of the TCJA's limit on compensation under Internal Revenue Code Sec. 162(m) and stock-based compensation for covered employees. This resulted in a $0.4 million reduction in deferred tax assets that had been recorded as a provisional amount as of December 31, 2017. The Company believes the accounting is complete regarding the revaluation of the deferred tax balances and there are no remaining provisional amounts associated with the TCJA as of December 31, 2018. The Company is aware that the Internal Revenue Service has issued proposed regulations regarding the TCJA and has incorporated this guidance into its current tax policy. The Company will continue to monitor and analyze the impact of future guidance and any final regulations as they become available.
The components of the income tax expense (benefit) were as follows (in thousands):
The following table reconciles the income tax expense (benefit) with income tax expense at the federal statutory rate (in thousands):
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities were as follows (in thousands):
Management considers whether some portion or all of the deferred tax assets will be realized based on a more likely than not standard of judgment. 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. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. The Company has net operating loss carryforwards (NOLs) for U.S. income tax purposes that have been generated from the Company's operations in 2017 of approximately $605.9 million, which expire in 2037 and are not subject to the 80 percent limitation of taxable income. As of December 31, 2018, the Company also had $517.5 million of indirect drilling costs that were capitalized under Code Section 59(e). As of December 31, 2017, the Company had no indirect drilling costs that were capitalized under Code Section 59(e).
The utilization of such NOL carryforwards may be limited upon the occurrence of certain ownership changes as stipulated in Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"). As of December 31, 2018, the Company determined that the statutory provision of Section 382 will not limit the Company’s ability to realize future tax benefits. As of December 31, 2018, the Company believes it will be able to generate sufficient future taxable income and accordingly, believes that it is more likely than not that its deferred income tax assets will be fully realized. The Company files income tax returns in the U.S. federal jurisdiction and in Colorado. The statute of limitations related to the 2016 and 2017 tax returns are open through 2020 and 2021 respectively, however, the ability for the tax authority to adjust the NOL will continue until three years after the NOL is utilized.
As of December 31, 2018, the Company believes that it has no liability for uncertain tax positions. If the Company were to determine there were any uncertain tax positions, the Company would recognize the liability and related interest and penalties within income tax expense. As of December 31, 2018, the Company had no provision for interest or penalties related to uncertain tax positions.
Note 11-Unit and Stock-Based Compensation
Extraction Long Term Incentive Plan
In October 2016, the Board of Directors adopted the Extraction Oil & Gas, Inc. 2016 Long Term Incentive Plan (the “2016 Plan” or “LTIP”), pursuant to which employees, consultants, and directors of the Company and its affiliates performing services for the Company are eligible to receive awards. The 2016 Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, other stock-based awards, substitute awards, annual incentive awards, and performance awards intended to align the interests of participants with those of stockholders. In accordance with the terms of the LTIP, 20.2 million shares of common stock have been reserved for issuance pursuant to awards under the LTIP. Extraction has granted awards under the LTIP to certain directors, officers and employees, including stock options, restricted stock units and performance stock awards.
Restricted Stock Units (“RSUs”)
Restricted stock units granted under the LTIP (“RSUs”) vest over either (i) a one-year service period, with 100% of the units vesting at the end of the service period, or (ii) a three-year service period with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09.
The Company recorded $27.9 million, $31.8 million and $5.5 million of stock-based compensation costs related to RSUs for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, there was $32.2 million of total unrecognized compensation cost related to the unvested RSUs granted to certain employees that is expected to be recognized over a weighted average period of 1.4 years.
The following table summarizes the RSU activity from January 1, 2016 through December 31, 2018 and provides information for RSUs outstanding at the dates indicated.
Stock Options
Expense on the stock options are recognized on a straight-line basis over the service period of the award less awards forfeited. The fair value of the stock options was measured at the grant date using the Black Scholes valuation model. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. Expected volatility is based on the volatility of the historical stock prices of the Company’s peer group. The risk-free rates are based on the yields of U.S. Treasury instruments with comparable terms. A dividend yield and forfeiture rate of zero were assumed. Stock options granted under the LTIP vest ratably over three years and are exercisable immediately upon vesting through the tenth anniversary of the grant date. To fulfill options exercised, the Company issues new shares.
The Company recorded $15.1 million, $15.7 million and $2.9 million of stock-based compensation costs related to the stock options for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, there was $12.1 million of unrecognized compensation cost related to the stock options that is expected to be recognized over a weighted-average period of 0.8 years.
The following table summarizes the assumptions used for the Black-Scholes valuation model to calculate the stock-based compensation expense for the years ended December 31, 2017 and 2016. No stock options were granted for the year ended December 31, 2018.
The following table summarizes the stock option activity from January 1, 2016 through December 31, 2018 and provides information for stock options outstanding at the dates indicated.
The following table summarizes information about outstanding and exercisable stock options as of December 31, 2018.
Performance Stock Awards
The Company granted performance stock awards ("PSAs") to certain executives under the LTIP in October 2017 and March 2018. The number of shares of the Company's common stock that may be issued to settle PSAs ranges from zero to one times the number of PSAs awarded. Generally, the shares issued for PSAs are determined based on the satisfaction of a time-based vesting schedule and a weighting of one or more of the following: i) absolute total stockholder return ("ATSR"), ii) relative total stockholder return ("RTSR"), as compared to the Company's peer group and iii) cash return on capital invested ("CROCI") measured over a three-year period and vest in their entirety at the end of the three-year measurement period. Any PSAs that have not vested at the end of the applicable measurement period are forfeited. The vesting criterion that is associated with the RTSR is based on a comparison of the Company's total shareholder return for the measurement period compared to that of a group of peer companies for the same measurement period. As the ATSR and RTSR vesting criteria are linked to the Company's share price, they each are considered a market condition for purposes of calculating the grant-date fair value of the awards. The vesting criterion that is associated with the CROCI is considered a performance condition for purposes of calculating the grant-date fair value of the awards.
The fair value of the PSAs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. Those outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be obtained for those iterations. In the case of the Company's PSAs, the Company cannot predict with certainty the path its stock price or the stock prices of its peer will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the PSAs. Significant assumptions used in this simulation include the Company's expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period as well as the volatilities for each of the Company's peers.
The assumptions used in valuing the PSAs granted were as follows:
The Company recorded $5.7 million and $0.8 million of stock-based compensation costs related to PSAs for the years ended December 31, 2018 and 2017, respectively. The Company did not record any stock-based compensation expense related to PSAs for the year ended December 31, 2016. As of December 31, 2018, there was $9.1 million of unrecognized compensation cost related to the PSAs that is expected to be recognized over a weighted-average period of 1.7 year.
The following table summarizes the PSA activity from January 1, 2017 through December 31, 2018 and provides information for PSAs outstanding at the dates indicated.
(1)
The number of awards assumes that the associated maximum vesting condition is met at the target amount. The final number of shares of the Company's common stock issued may vary depending on the performance multiplier, which ranges from zero to one, depending on the level of satisfaction of the vesting condition.
Incentive Restricted Stock Units (“Incentive RSUs”)
Officers of the Company contributed 2.7 million shares of common stock to Extraction Employee Incentive, LLC (“Employee Incentive”), which is owned solely by certain officers of the Company. Employee Incentive issued restricted stock units (“Incentive RSUs”) to certain employees. Incentive RSUs vest over a three-year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. On July 10, 2017, the partners of Employee Incentive amended the vesting schedule in which 25% vested on July 17, 2017 and the remaining Incentive RSUs will vest 25%, 25% and 25% each six months thereafter, over the remaining 18 months service period. Grant date fair value was determined based on the value of Extraction’s common stock on the date of issuance. The Company assumed a forfeiture rate of zero as part of the grant date estimate of compensation cost. As of January 1, 2017, the Company elected to account for stock-based compensation forfeitures as they occur, as a result of the adoption of ASU No. 2016-09. As the vesting of any Incentive RSUs will be satisfied with shares of common stock that are already issued and outstanding, the Incentive RSUs do not have any impact on the Company’s diluted earnings per share calculation.
The Company recorded $19.6 million, $17.3 million and $2.4 million of stock-based compensation costs related to Incentive RSUs for the years ended December 31, 2018, 2017 and 2016, respectively. These costs were included in the consolidated statements of operations within the general and administrative expenses line item. As of December 31, 2018, there was $0.9 million of total unrecognized compensation cost related to the unvested Incentive RSUs granted to certain employees that is expected to be recognized over a weighted average period of 0.1 years.
The following table summarizes the Incentive RSU activity from January 1, 2016 through December 31, 2018 and provides information for Incentive RSUs outstanding at the dates indicated.
Holdings’ Membership Unit Incentive Plan
On May 29, 2014, Holdings adopted the 2014 Membership Unit Incentive Plan (“2014 Plan”). The 2014 Plan provided for the compensation of employees, non-employee managers and consultants of the Company and its affiliates through grants of restricted unit awards (“Holdings’ RUAs”) and incentive units (“Holdings’ Incentive Units”). The 2014 Plan was terminated as a result of the Corporate Reorganization in October 2016.
Holdings’ RUAs
Holdings’ RUAs vested over a three-year service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. The Company estimated fair value of the RUAs on their grant date based upon estimated volatility, market comparable risk free rate, estimated forfeiture rate and a discount for lack of marketability. Grant date fair value was determined based on the value of Holdings’ Equity Units on the date of the grant. Due to a lack of historical data, the Company used the experience of other entities in the same industry to estimate a forfeiture rate. Expected forfeitures are then included as part of the grant date estimate of compensation cost.
No unit-based compensation costs related to Holdings' RUA grants were recorded for December 31, 2018 and 2017. The Company recorded $16.8 million of unit-based compensation costs related to Holdings’ RUA grants for the year ended December 31, 2016. These costs are included in the consolidated statements of operations within the general and administrative expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit Incentive Plan ("2014 Plan") was terminated. As of December 31, 2018, there is no unrecognized compensation cost related to unvested RUAs granted to employees.
The following table summarizes the Holdings’ RUA activity from January 1, 2016 through December 31, 2016 and provides information for Holdings’ RUAs outstanding at the dates indicated.
PRL RUAs
PRL granted RUAs to certain employees, including Extraction employees (“PRL RUAs”). PRL RUAs vested over a three years service period, with 25%, 25% and 50% of the units vesting in year one, two and three, respectively. Grant date fair value was determined based on the value of PRL’s Equity Units on the date of the grant. PRL uses its past experience to estimate a forfeiture rate and expected forfeitures are included as part of the grant date estimate of compensation cost.
No unit-based compensation costs related to PRL RUA grants were recorded for the year ended December 31, 2018 and 2017. The Company recorded $0.5 million of unit-based compensation costs related to PRL RUA grants for the year ended December 31, 2016. These costs are included in the consolidated statements of operations within the general and administrative expenses line item. In connection with the Corporate Reorganization in 2016, the Holdings Membership Unit Incentive Plan ("2014 Plan") was terminated. As of December 31, 2018, there was no unrecognized compensation cost related to the PRL RUAs as all awards were fully vested.
Holdings’ Incentive Units
In accordance with the 2014 Plan and the Holdings LLC Agreement, Holdings issued 3.0 million Holdings’ incentive units to certain members of management in the fourth quarter of 2015. All of Holdings’ Incentive Units were non-voting and subject to certain vesting and performance conditions. The Holdings’ Incentive Units vested over a three year service period, with 25%, 25% and 50% of the units vesting in year 1, year 2 and year 3, respectively (with vesting between the first and third anniversaries occurring pro-rata based on the number of full months elapsed since the last vesting date), and in full upon a change of control, as defined in the Holdings LLC Agreement. The Holdings’ Incentive Units were accounted for as liability awards under ASC 718, Compensation-Stock Compensation, with compensation expense based on period-end fair value.
In connection with the IPO, the Board of Managers of Holdings accelerated the vesting of the Holdings’ Incentive Units. The Company’s IPO and change of control triggered the conversion of these units into approximately 9.1 million common shares of the Company based on the 10-day volume weighted average price of the Company’s common stock following its IPO as set forth in the Holdings Third Amended and Restated LLC Agreement. For the year ended December 31, 2016, the Company recognized approximately $172.1 million in non-cash, stock-based compensation expense in connection with the conversion of the Holdings’ Incentive Units into the Company’s common stock. As of December 31, 2018 and 2017, there was no unrecognized compensation cost related to the Holdings' Incentive Units.
Note 12-Earnings (Loss) Per Share
Basic earnings per share (“EPS”) includes no dilution and is computed by dividing net income (loss) available to common shareholders by the weighted-average number of shares outstanding during the period. Diluted EPS reflects the potential dilution of securities that could share in the earnings available to common shareholders of the Company. The Company uses the “if-converted” method to determine potential dilutive effects of Series A Preferred Stock and the treasury method to determine the potential dilutive effects of outstanding restricted stock awards and stock options.
EPS for the year ended December 31, 2016 is calculated for the period from October 12, 2016, the effective date of the Corporate Reorganization, to December 31, 2016. EPS information is not applicable for reporting periods prior to the Corporate Reorganization. The basic weighted average shares outstanding calculation is based on the actual days in which the shares were
outstanding for the period from October 12, 2016 to December 31, 2016. Please refer to Note 1 - Business and Organization and Note 9 - Equity for additional discussion regarding the Corporate Reorganization.
The components of basic and diluted EPS were as follows:
(1)
For the year ended December 31, 2018, 3,102,335 potentially dilutive shares associated with restricted stock awards outstanding were not included in the calculation above, as they had an anti-dilutive effect on EPS. Additionally, 5,244,428 common shares for stock options were excluded as they were out-of-the-money and 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded, as they would have had an anti-dilutive effect on EPS.
(2)
For the year ended December 31, 2017, 8,566,983 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards, stock options outstanding and performance stock awards contingently issuable, if December 31, 2017 was the end of the measurement period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
(3)
For the period of October 12 through December 31, 2016, 7,737,500 potentially dilutive shares were not included in the calculation above, as they had an anti-dilutive effect on EPS, including restricted stock awards and stock options outstanding for the period. Additionally, the 11,472,445 common shares associated with the assumed conversion of Series A Preferred Stock were also excluded.
Note 13-Commitments and Contingencies
Leases
The Company leases two office spaces in Denver, Colorado, two office spaces in Greeley, Colorado and one office space in Houston, Texas under separate operating lease agreements. The Denver, Colorado leases expire on February 29, 2020 and May 31, 2028, respectively. The Greeley and Houston leases expire on October 31, 2019, June 30, 2019 and January 31, 2022, respectively. Total rental commitments under non-cancelable leases for office space were $32.8 million at December 31, 2018. The future minimum lease payments under these non-cancelable leases are as follows: $3.5 million in 2019, $3.4 million in 2020, $3.4 million in 2021, $3.4 million in 2022, $3.4 million in 2023 and $15.7 million thereafter. Rent expense was $3.4 million, $2.3 million, and $1.9 million for the years ended December 31, 2018, 2017, and 2016, respectively.
On June 4, 2015, the Company subleased the remaining term of one of its Denver office leases that expires February 29, 2020. The sublease will decrease the Company’s future lease payments by $0.3 million.
Drilling Rigs
As of December 31, 2018, the Company was subject to commitments on three drilling rigs. In the event of early termination of these contracts, the Company would be obligated to pay an aggregate amount of approximately $9.2 million as of December 31, 2018, as required under the terms of the contracts. In February 2016, the Company provided notice to terminate one of its drilling rigs that was subject to commitment at December 31, 2015. As part of this termination, the Company was obligated to pay $1.0 million in the second quarter of 2016, which was recorded in the consolidated statements of operations within the other operating expenses line item. In January 2017, the Company provided notice for termination on one drilling rig and paid no termination fees.
Delivery Commitments
As of December 31, 2018, the Company’s oil marketer is subject to a firm transportation agreement that commenced in November 2016 and has a ten-year term with a monthly minimum delivery commitment of 45,000 Bbl/d in year one, 55,800 Bbl/d in year two, 61,800 Bbl/d in years three through seven and 58,000 Bbl/d in years eight through ten. In May 2017, the Company amended its agreement with its oil marketer that requires it to sell all of its crude oil from an area of mutual interest in exchange for a make-whole provision that allows the Company to satisfy any minimum volume commitment deficiencies incurred by its oil marketer with future barrels of crude oil in excess of their minimum volume commitment through October 31, 2018. In December 2017, the Company extended the term of this agreement through October 31, 2019 and has posted a letter of credit in the amount of $35.0 million. The Company is currently in the process of amending and extending this agreement. The Company evaluates its contracts for loss contingencies and accrues for such losses, if the loss can be reasonably estimated and deemed probable. The Company also has two long-term crude oil gathering commitments with an unconsolidated subsidiary, in which the Company has a minority ownership interest. The first agreement commenced in November 2016 and has a term of ten years with a minimum volume commitment of an average 9,167 Bbl/d in year one, 17,967 Bbl/d in year two, 18,800 Bbl/d for years three through five and 10,000 Bbl/d for years six through ten. The second agreement will commence in or around July 2019 and has a term of ten years for an average of 3,200 Bbl/d in year one, 8,000 Bbl/d in year two, 14,000 Bbl/d in year three, 16,000 Bbl/d in years four through eight, 12,000 Bbl/d in year nine and 10,000 Bbl/d in year ten. The remaining aggregate amount of estimated payments under these agreements is approximately $875.8 million.
In collaboration with several other producers and a midstream provider, on December 15, 2016 and August 7, 2017, the Company agreed to participate in expansions of natural gas gathering and processing capacity in the DJ Basin. The plan includes two new processing plants as well as the expansion of related gathering systems. The first plant commenced operations in August 2018 and the second plant is expected to be completed by mid-2019, although the exact start-up date is undetermined at this time. The Company’s share of these commitments will require 51.5 MMcf and 20.6 MMcf per day, respectively, to be delivered after the plants' in-service dates for a period of seven years thereafter. The Company may be required to pay a shortfall fee for any volumes under these commitments. These contractual obligations can be reduced by the Company’s proportionate share of the collective volumes delivered to the plants by other third party incremental volumes available to the midstream provider at the new facilities that are in excess of the total commitments. The Company is also required for the first three years of each contract to guarantee a certain target profit margin on these volumes sold. Under its current drilling plans, the Company expects to meet these volume commitments.
In February 2019, the Company entered into two long-term gas gathering agreements with third-party midstream providers. The first agreement will commence in or around November 2019 and has a term of twenty years with a minimum volume commitment of 251 Bcf to be delivered within the first seven years. The annual commitments over seven years are to be delivered on an average 48,000 Mcf/d in year one, 96,000 Mcf/d in year two, 132,000 Mcf/d in year three, 120,000 Mcf/d in year four, 108,000 Mcf/d in year five, 104,000 Mcf/d in year six and 80,000 Mcf/d in year seven. The aggregate amount of estimated payments under this agreement is approximately $317.7 million. The second agreement will commence in or around January 2020 and has a term of ten years with an annual minimum volume commitment of 13.0 Bcf in years one through ten. The Company may be required to pay an annual shortfall fee for any volume deficiencies under this commitment, calculated based on the weighted average sales price during the corresponding annual period. Under its current drilling plans, the Company expects to meet these volume commitments.
Acquisition of Undeveloped Leasehold Acreage
The Company was party to an agreement during 2017 with an unrelated third party for which it has paid $247.6 million through December 31, 2018 to complete its leasing program of approximately 38,800 net acres of undeveloped leasehold.
General
The Company is subject to contingent liabilities with respect to existing or potential claims, lawsuits, and other proceedings, including those involving environmental, tax, and other matters, certain of which are discussed more specifically below. The Company accrues liabilities when it is probable that future costs will be incurred and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters and its experience in contesting, litigating, and settling other matters. As the scope of the liabilities becomes better defined, there will be changes in the estimates of future costs, which management currently believes will not have a material effect on the Company’s financial position, results of operations, or cash flows.
As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost or the Company may be required to pay damages if certain performance conditions are not met.
Legal Matters
From time to time, the Company is party to ongoing legal proceedings in the ordinary course of business. While the outcome of these proceedings cannot be predicted with certainty, the Company does not believe the results of these proceedings, individually or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations or liquidity.
Note 14-Related Party Transactions
Office Lease with Related Affiliate
In April 2016, the Company subleased office space to Star Peak Capital, LLC, of which a member of the Board of Directors is an owner, for $1,400 per month. The sublease commenced on May 1, 2016 and expires on February 28, 2020.
Units Repurchased from Officer
In May 2016, the Company repurchased 60,605 Tranche A Units and 82,578 Tranche C Units from its former Chief Accounting Officer, for $3.25 per unit for an aggregate purchase price of approximately $0.5 million.
Promissory Notes
In May 2014, the Company received full recourse promissory notes from two officers under which the Company advanced $5.4 million to the employees to meet their capital contributions. The promissory notes were due on May 29, 2021, or earlier in the event of termination or certain change in control events as stipulated in the individual promissory notes and any distributions of capital contributions were considered mandatory prepayments. The promissory notes had a stated interest rate of LIBOR plus 1% per annum. The promissory notes were recorded as a reduction of members’ equity.
In September 2016, the Company redeemed 1.2 million units from two of its executive officers, for an aggregate purchase price of $7.8 million. On the same date, the executive officers used $5.6 million of the redemption value to settle in full and terminate their obligations under the promissory notes, including accrued interest thereon.
Second Lien Notes
Several holders of Second Lien Notes were also members of Holdings. Of the $430.0 million outstanding on the Second Lien Notes as of December 31, 2015, members held approximately $311.7 million. These members were paid $314.8 million upon repayment and termination of the Second Lien Notes in July 2016, including the prepayment penalty.
2021 Senior Notes
Several 5% stockholders of the Company were also holders of the 2021 Senior Notes prior to the Tender Offer and the redemption of the 2021 Senior Notes. As of the initial issuance of the $550.0 million principal amount on the 2021 Senior Notes, such stockholders held $63.5 million.
2024 Senior Notes
Several 5% stockholders of the Company were also holders of the 2024 Senior Notes. As of the initial issuance in August 2017 of the $400.0 million principal amount on the 2024 Senior Notes, such stockholders held $54.9 million.
2026 Senior Notes
Several 5% stockholders of the Company were also holders of the 2026 Senior Notes. As of the initial issuance in January 2018 of the $750.0 million principal amount on the 2026 Senior Notes, such stockholders held $56.2 million.
Series A Preferred Units
All holders of the $75.0 million of Series A Preferred Units were also members of Holdings. The Company used $90.0 million of the net proceeds from its IPO to redeem the Series A Preferred Units in full on October 17, 2016, which included a premium of $15.0 million.
Series A Preferred Stock and Series B Preferred Units
As of the initial issuance of the $185.3 million of Series B Preferred Units, members of Holdings held approximately $135.3 million. Several holders of the Series A Preferred Stock are also 5% stockholders of the Company. As of the initial issuance in October 2016 of the $185.3 million of Series A Preferred Stock, such stockholders held $105.0 million.
Private Placement of Common Stock
Several 5% stockholders of the Company were also participants in the Private Placement. As of the initial issuance of $457.0 million of common stock in December 2016, such stockholders purchased 2,503,370 shares for $45.7 million.
Increased Ownership in an Unconsolidated Subsidiary
In May 2018, the Company exercised an option to increase its ownership percentage in an unconsolidated subsidiary funded with a $35.3 million promissory note. This note was extinguished with the transfer of units to the unconsolidated subsidiary. The Company also contributed an acreage dedication and minimum volume commitment.
Related Party-Employee
Mr. Troy Owens, brother of Mr. Matthew R. Owens, the Company's President and a member of the Company's Board of Directors, is employed by the Company as an engineer. Consistent with market compensation for his services, Mr. Troy Owens received approximately $0.2 million and $0.2 million in aggregate cash compensation relating to the fiscal years ended December 31, 2018 and 2017, respectively. In addition, Mr. Troy Owens received certain long-term incentives during the same periods in the form of restricted stock units that vest over a period of three years.
Note 15-Segment Information
See Note 2 - Basis of Presentation and Significant Accounting Policies, Segment Reporting for a description of the Company's determination of its reportable segments. The Company's exploration and production segment revenues are derived from third parties. The Company’s gathering and facilities segment is currently in the construction phase and no revenue generating activities have commenced.
Financial information of the Company's reportable segments was as follows for the year ended December 31, 2018. Capital expenditures for fixed assets later attributed to the gathering and facilities segment were $4.9 million for the year ended December 31, 2017. There were no such capital expenditures for the year ended December 31, 2016. There were no revenues, operating expenses or other income (expense) attributed to the gathering and facilities segment for the years ended December 31, 2017 and 2016.
The following table presents a reconciliation of Adjusted EBITDAX by segment to the GAAP financial measure of income (loss) before income taxes for the year ended December 31, 2018 (in thousands). The Company had a single reportable segment during the years ended December 31, 2017 and 2016, therefore no reconciliation is provided for these periods.
Note 16-Supplemental Oil and Gas Reserve Information (Unaudited)
Results of Operations for Oil, Natural Gas and NGL Producing Properties
The following are the results of operations (in thousands) of the Company’s oil and gas producing activities, before corporate overhead and interest expenses. The Company assumed a statutory rate of 24.7% for the year ended December 31, 2018 and 2017. The Company assumed a statutory tax rate of 38.0% for the year ended December 31, 2016, although the Company was not subject to federal and state income taxes prior to the Corporate Reorganization.
Oil, Natural Gas and NGL Reserve Quantities (Unaudited)
The reserves at December 31, 2018, 2017 and 2016 presented below were prepared by the independent engineering firm Ryder Scott Company, L.P. All reserves are located within the DJ Basin. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGL which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The principal methodologies employed are decline curve analysis and analogy. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
The following table sets forth information for the years ended December 31, 2018, 2017 and 2016 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:
•
The values for the 2018 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2018. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $65.56 per barrel (West Texas Intermediate price) for crude oil and NGL and $3.10 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and
basis differentials. The average resulting price used as of December 31, 2018 was $57.65 per barrel for oil, $1.47 per Mcf for natural gas and $20.45 per barrel for NGL.
•
The values for the 2017 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2017. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $51.34 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.98 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2017 was $42.89 per barrel for oil, $1.73 per Mcf for natural gas and $20.28 per barrel for NGL.
•
The values for the 2016 oil, natural gas and NGL reserves are based on the 12-month arithmetic average of the first day of the month prices for the period from January through December 31, 2016. The unweighted arithmetic average first-day-of-month prices for the prior twelve months were $42.75 per barrel (West Texas Intermediate price) for crude oil and NGL and $2.49 per MMBtu (Henry Hub price) for natural gas. All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2016 was $34.91 per barrel for oil, $1.39 per Mcf for natural gas and $11.63 per barrel for NGL.
For the year ended December 31, 2018, the Company had downward revisions of previous estimates of 3,325.1 MBoe. As a result of ongoing drilling and completion activities during 2018, the Company reported extensions, discoveries, and other additions of 82,732.7 MBoe. Additionally, during 2018 the Company sold reserves of 10,167.2 MBoe and purchased reserves of 13,672.0 MBoe.
For the year ended December 31, 2017, the Company had upward revisions of previous estimates of 2,894.0 MBoe. As a result of ongoing drilling and completion activities during 2017, the Company reported extensions, discoveries, and other additions of 56,487.9 MBoe. Additionally, during 2017 the Company purchased reserves of 14,188.3 MBoe.
For the year ended December 31, 2016, the Company had downward revisions of previous estimates of 7,620.8 MBoe. As a result of ongoing drilling and completion activities during 2016, the Company reported extensions, discoveries, and other additions of 56,698.5 MBoe. Additionally, during 2016 the Company purchased reserves of 41,281.2 MBoe.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves
The Company follows the guidelines prescribed in ASC 932, Extractive Activities-Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.
The information is based on estimates of proved reserves attributable to the Company’s interest in oil and gas properties as of December 31 of the years presented. These estimates were prepared by Ryder Scott Company L.P., independent petroleum engineers.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions. (2) The estimated future cash flows are compiled by applying the trailing twelve-month average of the first of the month prices applied to the Company’s proved reserve year-end quantities. (3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred. (4) Future net cash flows are discounted to present value by applying a discount rate of 10%.
The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the
recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC 932, Extractive Activities-Oil and Gas (in thousands):
(1)
For the years ended December 31, 2018, 2017 and 2016, future income tax expenses in the Company’s calculation of the standardized measure of discounted future net cash flows are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and gas properties, other deductions, credit and allowances relating to the Company’s proved reserves. For purposes of the standardized measure calculation, it was assumed that all of the Company’s operations are attributable to the Company’s oil and gas assets.
The following are the principal sources of change in the standardized measure (in thousands):
Note 17-Unaudited Quarterly Financial Data
The following is a summary of the unaudited quarterly financial data for each of the quarters from first quarter 2017 through fourth quarter 2018 (in thousands, except per share data). Historical results are not necessarily indicative of the results to be expected in future periods. You should read this data together with the Company's consolidated financial statements and the related notes included elsewhere in this Annual Report:
(1)
Oil, Natural gas and NGL sales revenue less lease operating expenses, transportation and gathering expenses, production taxes and depreciation, depletion, amortization and accretion.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
In accordance with the Securities Exchange Act of 1934, as amended (the "Exchange Act"), Rules 13a-15(b) and 15d-15(b), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2018. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2018 at the reasonable assurance level.
Management’s Annual Report on Internal Control over Financial Reporting
Our management, including our principal executive officer and principal financial officer, 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 Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with generally accepted accounting principles. 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.
Our management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2018, using the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that our internal control over financial reporting was effective as of December 31, 2018.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial reporting at December 31, 2018. Their "Report of Independent Registered Public Accounting Firm," which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting at December 31, 2018, is included in Item 8.
Changes in Internal Control over Financial Reporting
There were no changes in our system of internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The information responsive to Items 401, 405, 406 and 407 of Regulation S-K to be included in our definitive Proxy Statement for our 2019 Annual Meeting of Shareholders, to be filed within 120 days of December 31, 2018, pursuant to Regulation 14A under the Securities Exchange Act of 1934, as amended (the “2019 Proxy Statement”), is incorporated herein by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information responsive to Items 402 and 407 of Regulation S-K to be included in our 2019 Proxy Statement is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information responsive to Items 201(d) and 403 of Regulation S-K to be included in our 2019 Proxy Statement is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information responsive to Items 404 and 407 of Regulation S-K to be included in our 2019 Proxy Statement is incorporated herein by reference.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information responsive to Item 9(e) of Schedule 14A to be included in our 2019 Proxy Statement is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Documents Filed With This Report
1. FINANCIAL STATEMENTS
The following consolidated financial statements of the Company are filed as a part of this report:
2. FINANCIAL STATEMENT SCHEDULES
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements and related notes.
3. EXHIBITS
The exhibits to this report required to be filed pursuant to Item 15(b) are listed below in the “Index to Exhibits” attached hereto and are incorporated herein by reference.
INDEX TO EXHIBITS
† Management contract or compensatory plan or agreement.
* Filed herewith.
** Previously filed.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements 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.
Date: February 21, 2019.
Extraction Oil & Gas, Inc.
By:
/s/ MARK A. ERICKSON
Mark A. Erickson
Chairman and Chief Executive Officer
(Principal Executive Officer)
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.