UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

 

For the fiscal year ended December 31, 2016

OR

 

For the transition period from              to             

Commission file number: 333-134748

 

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 

(405) 478-8770

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

None.

Securities registered pursuant to Section 12(g) of the Act:

None.

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☐    No  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☐     No  ☒

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The aggregate market value of common equity held by non-affiliates of the registrant is not determinable as such shares are privately held and there is no public market for such shares.

Documents incorporated by reference: Certain information called for in Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference to the registrant’s definitive proxy statement or will be included in an amendment to this Annual Report on Form 10-K.

Number of shares outstanding of each of the issuer’s classes of common stock as of March 31, 2017: 

 

 

 

 

 

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CHAPARRAL ENERGY, INC.

Index to Form 10-K

 

 

 

 

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CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described under the heading “Risk Factors,” the factors include:

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Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

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GLOSSARY OF CERTAIN DEFINED TERMS

The terms defined in this section are used throughout this annual report on Form 10-K:

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PART I

Unless the context requires otherwise, references in this annual report to the “Company,” “Chaparral,” “we,” “our” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis. We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of Certain Defined Terms” at the beginning of this annual report.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Overview

Founded in 1988, we are a Delaware corporation headquartered in Oklahoma City and a Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich STACK play, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage and Woodford formations. We also have significant production from CO₂ EOR methods underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state.

During 2016, our average net daily production was 24.4 MBoe and our oil and natural gas revenues were $252.2 million. As of December 31, 2016, we had estimated proved reserves of 131.3 MMBoe with a PV-10 value of approximately $529 million and an estimated reserve life of approximately 14.7 years. These estimated proved reserves included 30.8 MMBoe of reserves in our STACK play. Our reserves were 43% proved developed, 74% crude oil, and 9% natural gas liquids. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value below under “Non-GAAP Financial Measures and Reconciliations.”

Chapter 11 Reorganization

On May 9, 2016, the Company and 10 of its subsidiaries filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware.  On March 10, 2017, the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017, the Reorganization Plan became effective and we emerged from bankruptcy. Upon our emergence, all existing equity was cancelled and we issued new common stock to the previous holders of our Senior Notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to certain other parties as set forth in the Reorganization Plan, including to parties participating in a $50.0 million rights offering. To facilitate our discussion in this report, we refer to the post-emergence reorganized company as the “Successor” and the pre-emergence company as the “Predecessor.” See “Note 2—Chapter 11 reorganization” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of our bankruptcy and resulting reorganization.

Business Strategy

Our business strategy is to create economic and shareholder value by applying our core strengths in execution and cost control to exploit our robust inventory of horizontal drilling opportunities in the high-return STACK unconventional resource play.  Key components of our long-term business strategy include:

Preserving a strong and flexible capital structure. Maintaining a strong capital structure that protects our balance sheet and liquidity remains central to our business strategy. With our recent emergence from bankruptcy on March 21, 2017, we have an improved balance sheet and additional liquidity. This should allow us to access capital if and as necessary to maintain, and in some cases, improve our asset base.

Volatility of pricing can significantly impact the amount of revenue received for oil and natural gas production and the level of economic returns we receive on capital invested in our exploration and development activities. Our goal will be to continue to preserve financial flexibility through a conservative balance sheet and ample liquidity as we seek to manage the continued weakness in both oil and gas prices. We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility. Additionally, we carefully high-grade the allocation of capital to drilling and completions and focus the majority of our capital on low-risk locations or projects that have a greater certainty of robust economic returns. Our 2017 capital expenditure budget for acquisition, exploration and development activities is approximately $145.9 million.

Efficiently develop our STACK leasehold position / resource play. We are developing our acreage position to maximize the value of our resource potential, while maintaining flexibility to preserve future value when oil prices are low. During 2016 our operated and non-operated drilling was almost entirely focused on this play where we completed 16 operated wells and participated in 36 gross non-operated wells. Our 2017 capital plan for this play includes drilling 19 operated wells.

Adopt and employ leading drilling and completion techniques. Our team is focused on enhancing our drilling and completion techniques to maximize overall well economics. We have materially reduced the number of days that it takes to drill wells, and we

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have significantly improved completion techniques and designs over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well. High intensity multi-stage completion techniques have been particularly effective at increasing production rates and recoverable hydrocarbons as compared to prior completion techniques. We continuously evaluate our internal drilling and completion results and monitor the results of other operators to improve our operating practices. This continued evolution may enhance our initial production rates, increase ultimate recovery factors, lower well capital costs and improve rates of return on invested capital.

Continuously improving operations and returns. Managing the costs to find, develop and produce oil, natural gas and NGLs is critical to delivering robust returns on capital employed and creating shareholder value. Our focus areas in the STACK are characterized by large, contiguous acreage positions and multiple stacked geologic horizons. In 2016, we reduced our average well costs in all areas through faster drilling times and innovative optimizations of our completions. In addition, continued reduced service costs have positively impacted our business. We also have multiple initiatives underway to manage our base production, improve operational efficiencies and enhance future margins. We expect to be challenged in 2017 to control costs as the uptick in drilling and development activity from the recent oil price recovery has increased the demand for oilfield services which in turn is expected to result in higher prices for these services.

Selected monetization of assets.  We are continuing to evaluate options to monetize certain assets in our portfolio, which could result in increased liquidity and lower leverage. The proceeds from monetization of assets may be utilized for debt reduction and/or capital expenditure.

Stabilizing cash flow and managing risk exposure for a substantial portion of production by hedging production. As appropriate, we enter into derivative contracts to mitigate a portion of the commodity price volatility inherent in the oil and natural gas industry. By increasing the predictability of cash inflows for a portion of the company’s future production, we are better able to mitigate funding risks for our longer term development plans and lock in rates of return on our capital projects.

 2016 Highlights

The following are material events in 2016 with respect to our operations that have impacted our liquidity or results of operations, and/or are expected to impact these items in future periods. Events related to our bankruptcy petition and subsequent emergence are discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report.

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Operational Areas

The following table presents our proved reserves as of December 31, 2016, and average net daily production for both the year ended and quarter ended December 31, 2016, by our areas of operation. We have recently realigned our operational areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. Our operational areas currently include the following: the STACK, Active EOR Areas and Other. Reserves were estimated using a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices were defined by contractual arrangements. Please see Item 8. Financial Statements and Supplementary Data of this report for the results of our operations and financial position.

STACK Area

The STACK is an acronym for Sooner Trend Anadarko Canadian Kingfisher which is indicative of a play area in the Anadarko Basin of Oklahoma in which we operate. It is a horizontal drilling play in an area with multiple productive reservoirs which had previously been drilled with vertical wells. It encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. Our STACK play’s borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations and include the Woodford, Osage, Meramec, Oswego, and other intervals within the STACK area. The organic-rich Woodford Shale is the primary source of hydrocarbon migration into and present in the target reservoirs, which act as natural conduits for the oil migration from the Woodford. These complex carbonate-silt-shale stratigraphic intervals have proven to be very conducive to horizontal drilling and completion techniques. The stacking of plays allows us to effectively recover oil and gas from multiple formations using pad drilling, well spacing techniques and other operational efficiencies, which result in significant cost savings, reduced environmental impacts and attractive rates of return. We currently own approximately 98,000 net surface acres in this play. Within this play, we have 52 gross operated horizontal wells and are participating in an additional 94 gross horizontal wells operated by others.

Primarily as a result of our drilling activity, our production from this area was 2,667 MBoe in 2016 compared to 1,975 MBoe in 2015 and 1,603 MBoe in 2014. During 2016, we spent $61.2 million on drilling activities in our STACK play, compared to a budget of $50.3 million, where we drilled and/or participated in the drilling of 49 (16 net) horizontal wells. For 2017, our capital budget includes drilling and completing 19 wells, completing three wells that we drilled and rig-released in 2016 and participating in non-operated wells for a total budget of $81.8 million. Our drilling opportunities across the different intervals of the STACK are described below where acreage is duplicated for the stacked play position.

STACK – Meramec. We currently own approximately 68,500 net acres targeting the Meramec interval within our STACK play. Within this area, our drilling locations are in Kingfisher county, Canadian county and Garfield county. For a typical one mile lateral well in the Meramec, our estimated cost to drill and complete a well is approximately $3.5 million.

STACK – Osage. We currently own approximately 78,000 net acres targeting the Osage interval within our STACK play primarily located in Garfield, Kingfisher and Major counties. Within this area, our drilling locations are primarily in Garfield and Kingfisher counties. For a typical one mile lateral well, our estimated cost to drill and complete a well is approximately $3.3 million.

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STACK – Oswego. We currently own approximately 19,500 net acres targeting the Oswego interval within our STACK play. Within this area, our drilling locations are primarily in Kingfisher county where we estimate a typical one mile lateral well will cost approximately $2.7 million to drill and complete.

STACK – Woodford. We currently own approximately 78,000 net acres targeting the Woodford interval within our STACK play. Within this area, our drilling locations are primarily located within Canadian and Garfield counties. Our primary Woodford drilling focus is in Canadian county where we estimate a typical well will cost approximately $4.0 million to drill and complete.

As a result of the recent increase in seismic activity, the Oklahoma Corporation Commission (the “OCC”) issued multiple directives in 2016 to operators of salt water disposal wells to reduce salt water injection volumes in various “areas of interest.” These areas include those in central Oklahoma that encompass our STACK play. However, these directives do not significantly impact our operations in the STACK. Please see “Studies by both state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens” in  Item 1A. Risk Factors of this report for a further discussion of the OCC seismic-related directives.

During 2016, we incurred $15.9 million in capital expenditures on acquisitions to lease approximately 24,000 net acres in Garfield and Kingfisher counties, Oklahoma, which are prospective for drilling in our STACK play.

Active EOR Areas and Facilities

We have been actively implementing and managing CO₂ EOR since 2001. We currently have CO₂ supply agreements in place for the Burbank (Osage County, Oklahoma) and the Panhandle areas, and have built CO₂ pipelines to reach several of our field locations in both of these areas.

The U.S. Department of Energy–Office of Fossil Energy published reports in February 2006 estimating that significant oil reserves could be economically recovered in Oklahoma and Texas through CO₂ EOR processes. CO₂ miscible flooding is implemented and managed as a closed system consisting of the reservoir and surface facilities. The physical material balance of the system means that the CO₂ is produced and recycled numerous times after initial injection. Combined with the incoming purchased CO₂ supply, the recycled CO₂ supply allows us to systematically develop additional flood patterns in contiguous acreage to the active patterns, or to expand into new projects. If larger volumes of CO₂ become economically available and commodity prices are supportive, projects can be developed on accelerated timelines, while a more limited supply dictates a prolonged expansion. Due to the size of our EOR projects and the limitation of third party services, we expect the development of our EOR projects will extend beyond five years in many cases. Significant projects within our Active EOR Areas are discussed below.

The following table presents proved reserves, production, number of wells and average working interest related to our major Active EOR Areas:

North Burbank Unit. As of December 31, 2016, our North Burbank Unit, which is our largest property and for which we are the operator, accounted for 51%, of our total proved reserves and 93% of our Active EOR proved reserves. The producing zones are the Red Fork and Bartlesville formations and occur at a depth of approximately 3,000 feet. Our average net daily production from this Unit increased from 2014 to 2016 as a result of our CO₂ injection and its associated response, as well as optimizations that were made to facilities and in day-to-day operations. Due to the size of our North Burbank Unit the development cannot be completed within five years, and as a result the development of our North Burbank Unit will be an ongoing project.

The CO₂ utilized at this location is sourced from an existing nitrogen fertilizer plant in Coffeyville, Kansas as described further below. In 2013, we completed the Coffeyville CO₂ compression facility and a 68-mile pipeline to transport the CO₂ to the Burbank field. We began CO₂ injection at our North Burbank Unit in June 2013. Since 2013 we have injected CO₂ into additional patterns and

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as a result of the observed response, we gradually added CO₂ EOR reserves for all remaining phases of this unit. Development of remaining phases will follow in future years as a sufficient volume of purchased and recycled CO₂ is utilized.

Our total investment in our North Burbank Unit during 2016 was $37.5 million for infrastructure build out, development of a limited number of additional patterns, continuing CO₂ injection and field maintenance. Our budgeted capital expenditure in 2017, for which we have allocated $33.8 million, will be utilized to continue developing our North Burbank Unit, primarily for infrastructure build out, development of a limited number of additional patterns, continuing CO₂ injection and field maintenance. Significant additional capital expenditures will be required over multiple years to fully develop the North Burbank Unit.

Outside of our North Burbank Unit, we also actively inject CO₂ at our Camrick Area Units, our Booker Area Units and our Farnsworth Unit. Our capital plan for these units is one of judicious spending to efficiently and economically produce these units with production decline. Total investment in these units during 2016 was $17.4 million which we incurred for the purchase of CO₂ and remedial infrastructure and well work. Our capital budget for 2017 includes $13.6 million directed towards similar activities.

CO₂ Sources and Pipelines

We capture, compress and transport CO₂ to our Active EOR Areas from the following separate CO₂ sources.

Coffeyville. Our CO₂ source for the North Burbank Unit is located in Coffeyville, Kansas. In March 2011, we signed a 20-year contract with renewal options to purchase up to 100% of CO₂ emissions from the Coffeyville nitrogen fertilizer plant. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce our CO₂ purchases. We own and operate the Coffeyville CO₂ compression facility on land leased from the owner of the fertilizer plant, and 68 miles of CO₂ pipeline to transport the CO₂ to the Burbank field, both of which were completed in 2013. During 2016, we purchased an average of 28 MMcf/d from this source. By securing this contract and completing the compression facility and pipeline, we can provide CO₂ to our North Burbank Unit on an acceptable runtime basis and at a reasonably predictable cost, which will allow us to establish the platform to facilitate our CO₂ recovery operations in the North Burbank Unit.

Borger. We have a long-term contract to purchase up to approximately 20 MMcf/d of CO₂ produced at the Agrium nitrogen fertilizer plant in Borger, Texas. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, and has commenced installation of such additional equipment in 2014. We own and operate the Borger CO₂ compression facility on land leased from Agrium, and 80 miles of CO₂ pipelines to deliver the Borger-sourced CO₂ to our active EOR units in our Camrick Area and Farnsworth Units. During 2016 we purchased an average of 5 MMcf/d from this source. The Agrium fertilizer plant is currently undergoing a modification to allow additional fertilizer production and as a result of this modification, our CO₂ volumes could be reduced in 2017. If the available CO₂ volume is decreased below 5 MMcf/d in the immediate future, which is the minimum threshold required to operate the compression facility, we will not be able to continue CO₂ compression at this facility.  Unless modified or replaced, the CO₂ purchase contract expires in 2021.

Arkalon. We have a long-term contract to purchase up to approximately 15 MMcf/d of CO₂ produced at the Arkalon ethanol plant near Liberal, Kansas. We own and operate the Arkalon CO₂ compression and processing facility on land leased from Arkalon, as well as the 91 miles of CO₂ pipeline to deliver the Arkalon-sourced CO₂ to our active EOR units in our Booker Area and Farnsworth Units. With the installation of the “Twitchell Co2 Booster Pump” east of Perryton, Texas, we will have the ability to supply CO₂ to our Camrick and North Perryton Units from Arkalon beginning in the first quarter of 2017. This additional capacity allows us to replace the CO₂ from Borger once if we are no longer able to operate the facility. During 2016 we purchased an average of 8 MMcf/d from this source.

Enid. We previously had a contract to purchase CO₂ produced at the Koch nitrogen fertilizer plant in Enid, Oklahoma. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce our CO₂ purchases. We own a partial interest in the Enid CO₂ compression facility and 142 miles of CO₂ pipeline, which delivered the Enid-sourced CO₂ to our active EOR unit in southern Oklahoma. During 2016 we purchased an average of approximately 2 MMcf/d from this Enid CO₂ source. Both the CO₂ purchase contract and the operations agreement for the compression facility and pipeline expired December, 31 2016. Our interest in the pipeline is currently being marketed for sale.

Other Areas

We also have additional oil and gas properties throughout Oklahoma and the Texas Panhandle which includes the Mississippi Lime play. Our properties in these areas include mature properties and are held by production. In 2014, this category also included non-core properties that were disposed of at various times during that year. Acreage in this location is not attractive for drilling in the current $40- $60 per barrel price environment and therefore we have not allocated any significant capital to these areas in our 2017 budget. As we have not focused our capital spending in these areas in recent years, production has declined from 7,647 Mboe in 2014 to 6,089 MBoe in 2015 and 4,191 MBoe in 2016.

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Oil and Natural Gas Reserves

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and exclude escalations based upon future conditions.

Our policies regarding internal controls over the recording of reserves are structured to objectively estimate our oil and natural gas reserve quantities and values in compliance with Securities and Exchange Commission (“SEC”)  regulations. Users of this information should be aware that the process of estimating quantities of crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

The estimates of oil, natural gas and NGL reserves in this report are based on reserve reports, all of which are currently prepared by independent petroleum engineers. To achieve reasonable certainty, our engineers relied on an analysis and reporting software system designed specifically for reserves management that has been demonstrated to yield results with consistency and repeatability. Technical and economic data used include, but are not limited to, updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information.

Our Vice President - Corporate Reserves is the technical person primarily accountable for overseeing the preparation of our reserve estimates. He has a Bachelor of Sciences degree in Petroleum Engineering and a Masters of Business Administration, and has 28 years of industry experience that includes diverse petroleum engineering roles and reserves management. In addition, he is a member of the Society of Petroleum Engineers.

Our Corporate Reserves department continually monitors asset performance in collaboration with our Resource Development and EOR departments, making reserve estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Technical reviews are performed throughout the year by our geologic and engineering staff who evaluate pertinent geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of proved reserve quantities. Reporting to our Vice President - Corporate Reserves, our Corporate Reserve Department currently has a total of three full-time employees, comprised of two degreed engineers and one engineering analyst/technician.

We have internal guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. Internal controls within the reserve estimation process include:

Our Corporate Reserve Department works closely with the independent petroleum consultants to ensure the integrity, accuracy and timeliness of annual independent reserve estimates. Our internal reserve data is provided each year to the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. who prepare reserve estimates for the majority of our proved reserves using their own engineering assumptions and the economic data which we provide. The person responsible for overseeing the preparation of our reserve estimates at Cawley, Gillespie & Associates, Inc. is a registered Professional Engineer with more than 30 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a licensed Professional Engineer with over 30 years of practical experience in the

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estimation and evaluation of petroleum reserves. Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits 99.1 and 99.2 to this annual report.

The table below shows the percentage of the PV-10 value of our total proved reserves of oil, natural gas and NGLs prepared by us and each of our independent petroleum consultants for the years shown.

Proved Reserves

The following table summarizes our estimates of net proved oil and natural gas reserves, estimated future net revenues from proved reserves, the PV-10 value, the standardized measure of discounted future net cash flows, and the prices used in projecting those measures over the past three years. All of our reserves are located in the United States. We set forth our definition of PV-10 value (a non-GAAP measure) in the Glossary of Certain Defined Terms at the beginning of this annual report and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value below under “Non-GAAP Financial Measures and Reconciliations.”

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Our net proved oil and natural gas reserves and PV-10 values consisted of the following:

 

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Proved Undeveloped Reserves

The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2016.

 

Productive Wells

The following table sets forth the number of productive wells in which we have a working interest and the number of wells we operated as of December 31, 2016, by area. Productive wells consist of producing wells and wells capable of producing. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Gross wells is the total number of producing wells in which we have a working interest, and net wells is the sum of our working interest in all producing wells.

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Drilling Activity

The following table sets forth information with respect to wells drilled and completed during the periods indicated. Development wells are wells drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return. As of December 31, 2016, we had three gross operated wells drilling, completing or awaiting completion.

 

Developed and Undeveloped Acreage

The following table sets forth our gross and net interest in developed and undeveloped acreage as of December 31, 2016, by state. This does not include acreage in which we hold only royalty interests.

 

Many of our leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. The following table sets forth as of December 31, 2016 the expiration periods and net acres that are subject to leases in the undeveloped acreage summarized in the above table.

 

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Property Acquisition, Development and Exploration Costs

The following table summarizes our costs incurred for oil and natural gas properties and our reserve replacement ratio for each of the last three years:

Our reserve replacement ratio is calculated below by dividing the sum of reserve additions (from purchases of minerals in place, extensions and discoveries, and improved recoveries) by the production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in “Note 16—Disclosures about oil and natural gas activities (unaudited)” in Item 8. Financial Statements and Supplementary Data of this report. Management uses the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow reserves, thereby providing some information of the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. The reserve replacement ratio is comprised of the following:

 

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Production and Price History

The following table sets forth certain information regarding our historical net production volumes, average prices realized and production costs associated with sales of oil and natural gas for the periods indicated.

Non-GAAP Financial Measures and Reconciliations

PV-10 value is a non-GAAP measure that differs from the standardized measure of discounted future net cash flows in that PV-10 value is a pre-tax number, while the standardized measure of discounted future net cash flows is an after-tax number. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The decline in PV-10 and standardized measure of discounted future net cash flows from 2014 to 2015 and 2016 is primarily a result of the decline in commodity prices, which resulted in a reduction in proved reserves as certain previously recorded reserves became uneconomic, and a reduction in the profit margins on remaining reserves.

The following table provides a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows for the periods shown:

 

Management uses adjusted EBITDA (as defined below) as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our Existing Credit Facility

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and our New Credit Facility, described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” We consider compliance with this covenant to be material.

Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income, adjusted to exclude (1) asset impairments, (2) interest and other financing costs, net of capitalized interest, (3) income taxes, (4) depreciation, depletion and amortization, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, (9) upfront premiums paid on settled derivative contracts, (10) impairment charges, (11) other significant, unusual non-cash charges, (12) proceeds from any early monetization of derivative contracts with a scheduled maturity date more than 12 months following the date of such monetization—this exclusion is consistent with our prior treatment, for EBITDA reporting, of any large monetization of derivative contracts and (13) certain expenses related to our cost reduction initiatives, reorganization and fresh start accounting activities for which our lenders have permitted us to exclude when calculating covenant compliance. The following table provides a reconciliation of net income to adjusted EBITDA for the specific periods:

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas companies in acquiring properties, contracting for drilling equipment and securing trained personnel. There is also substantial competition for capital available for investment in the crude oil and natural gas industry.  Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed developmental drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.  Recently, the number of providers of materials and services has decreased in the region in which we operate as a result of the significant decrease in commodity prices. In addition, the industry downturn has also led to a large displacement of experienced personnel through layoffs and many of the affected personnel are now in other industries.  However, we are currently experiencing an increase in drilling activity that began in late 2016. This has resulted in an increase in the number of active drilling rigs and stimulated demand for crews and associated supplies, oilfield equipment and services, and personnel, especially in highly lucrative oil fields such as the Permian Basin and the STACK. As a result of the competitive demand for available equipment and labor in the marketplace, we expect to encounter increased prices from our vendors and service providers.

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Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition of producing properties.

Stockholders Agreement

On March 21, 2017, we entered into a Stockholders Agreement with the holders of our common stock named therein to provide for certain general rights and restrictions for holders of common stock. These include:

The rights and preferences of each stockholder under the Stockholders Agreement will generally terminate on the earliest of (i) the termination of the Stockholders Agreement by the unanimous written consent of all stockholders of the Company; (ii) the dissolution, liquidation or winding up of the Company; or (iii) the listing of the Company’s common stock on a U.S. national securities exchange registered with the SEC.

Registration Rights Agreement

On March 21, 2017, we entered into a Registration Rights Agreement with certain holders of our common stock. The Registration Rights Agreement provides resale registration rights for the holders’ Registrable Securities (as defined in the Registration Rights Agreement).

Pursuant to the Registration Rights Agreement, the holders have customary underwritten offering and piggyback registration rights, subject to the limitations set forth therein. Under their underwritten offering registration rights, one or more holders holding, collectively, at least 20% of the aggregate number of Registrable Securities have the right to demand that the Company file a registration statement with the SEC, and further have the right to demand that the Company effectuate the distribution of any or all of such holders’ Registrable Securities by means of an underwritten offering pursuant to an effective registration statement, subject to certain limitations described in the Registration Rights Agreement. The holders’ piggyback registration rights provide that, if at any time the Company proposes to undertake a registered offering of Common Stock, whether or not for its own account, the Company must give at least 20 business days’ notice to all holders of Registrable Securities to allow them to include a specified number of their shares in the offering.

These registration rights are subject to certain conditions and limitations, including the Company’s right to delay or withdraw a registration statement under certain circumstances. The Company will generally pay all registration expenses in connection with its obligations under the Registration Rights Agreement, regardless of whether any Registrable Securities are sold pursuant to a registration statement. The registration rights granted in the Registration Rights Agreement are subject to customary indemnification and contribution provisions, as well as customary restrictions such as blackout periods and, if an underwritten offering is contemplated, limitations on the number of shares to be included in the underwritten offering that may be imposed by the managing underwriter.

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Markets

The marketing of oil and natural gas we produce will be affected by a number of factors that are beyond our control and whose exact effect cannot be accurately predicted. These factors include:

The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated most trade and investment barriers between the United States, Canada and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before the Federal Energy Regulatory Commission (“FERC”), as well as nondiscriminatory access requirements, could further increase the availability of natural gas imports to certain United States markets. Such imports could have an adverse effect on both the price and volume of natural gas sales from our wells.

Members of the Organization of Petroleum Exporting Countries establish prices and production quotas from time to time with the intent of managing the global supply and maintaining, lowering or increasing certain price levels. We are unable to predict what effect, if any, such actions will have on both the price and volume of crude oil sales from our wells.

In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated it will ultimately expand natural gas markets and improve their reliability.  

Environmental Matters and Regulation

We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities.

General

Our operations, like the operations of other companies in our industry, are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

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These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible or economically desirable. The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the oil and natural gas industry could significantly increase our operating costs.

We routinely monitor our properties and operations in an effort to ensure that our properties and operations are, and remain, in substantial compliance with all current applicable environmental laws and regulations. If, at any time, we determine that our properties and/or operations do not substantially comply with all current applicable environmental laws and regulations, we take action to remedy such noncompliance on our own volition and do not delay taking action until ordered to do so by a regulatory authority. We cannot predict how future environmental laws and regulations may affect our properties or operations.

For the years ended December 31, 2016, 2015 and 2014, we did not incur any material expenditures for the installation of remediation or pollution control equipment at any of our facilities or the conduct of remedial or corrective actions. As of the date of this report, we are not aware of any other environmental issues or claims that will require material capital expenditures during 2017 or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry include the following:

Hazardous Substances and Wastes

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (“EPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions. However, there is no guarantee that Congress, the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes as presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. Moreover, failure to comply with such waste handling requirements can result in the imposition of administrative, civil and criminal penalties.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws, imposes strict, and in certain circumstances joint and several liability, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Responsible parties include the current, as well as former, owner or operator of the site where the release occurred and persons that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, and analogous state laws, such persons may be liable for the costs of cleaning up the hazardous substances released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have produced oil and natural gas for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under, or from the properties owned or leased by us, or on, or under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, analogous state laws or common law requirements. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated soil or groundwater, or perform remedial plugging or pit closure operations to prevent future contamination.  

NORM.  In the course of our operations, some of our equipment may be exposed to naturally occurring radioactive materials, or NORM, associated with oil and gas deposits and, accordingly, may result in the generation of wastes and other materials containing NORM.  NORM exhibiting levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping and work areas affected by NORM may be subject to remediation or restoration requirements.

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Water Discharges

Clean Water Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. In May 2015, EPA and the United States Army Corps of Engineers jointly announced a final rule defining the “Waters of the United States” which are protected under the Clean Water Act.  The new rule, which became effective August 28, 2015, has the effect of making additional waters expressly Waters of the United States and therefore subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation.  Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. Issues pertaining to wastewater generated by oil and natural gas exploration and production activities are drawing increased scrutiny from state legislators. We believe we are in substantial compliance with the requirements of the Clean Water Act.  

Oil Pollution Act. The Oil Pollution Act of 1990 (OPA) establishes strict liability for owners and operators of facilities that release oil into waters of the United States. The OPA and its associated regulations impose a number of requirements on responsible parties related to the prevention of spills and liability for damages resulting therefrom. A “responsible party” under OPA includes owners and operators of certain facilities from which a spill may affect Waters of the United States.  

Disposal Wells

The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. Because some states have become concerned that the disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding such disposal methods. For example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geologic Survey recently released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including mitigation, following anomalous seismic activity within 1.25 miles of hydraulic fracturing operations.

Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

Hydraulic Fracturing

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. Congress has previously considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of bills previously proposed before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which is already required by some state agencies governing our operations, including the Oklahoma Corporation Commission and the Texas Railroad Commission. Such disclosure requirements could make it easier for third parties opposing the use of hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptions for hydraulic fracturing from the Safe Drinking Water Act.

These federal legislative efforts slowed while EPA studied the issue of hydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including RCRA and the Clean Water Act. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced water. EPA completed the study of the potential impacts of hydraulic fracturing activities on water resources and published its final assessment in December 2016. In its assessment, the EPA concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances. The results of the study or similar governmental reviews could spur initiatives to regulate

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hydraulic fracturing under the SDWA or otherwise. A number of states and communities are currently considering legislation to ban or restrict hydraulic fracturing.

On March 20, 2015, the Bureau of Land Management released its new regulations governing hydraulic fracturing operations on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule and a final decision is pending. These developments may result in additional levels of regulation or level of complexity with respect to existing regulations that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

The Clean Air Act. The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. On August 16, 2012, EPA promulgated new CAA regulations addressing criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Reviews.” These new rules broadened the scope of EPA’s NSPS and NESHAP to include standards governing emissions from most operations associated with oil and natural gas production facilities and natural gas processing, transmission and storage facilities with a compliance deadline of January 1, 2015. EPA states that greenhouse gases will be controlled indirectly as a result of these new rules. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In December 2014, the EPA released final updates and clarifications to the Oil and Natural Gas Sector NSPS that, among other things, distinguishes between multiple flowback stages during completion of hydraulically fractured wells and clarified that storage tanks removed from service are not affected by any requirements.

Endangered Species

The federal Endangered Species Act (“ESA”) and analogous state laws regulate a variety of activities that adversely affect species listed as threatened or endangered under the ESA or their habitats. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. Numerous species have been listed or proposed for protected status in areas in which we currently, or could in the future, undertake operations. For instance, the American Burying Beetle was listed as an endangered species by the U.S. Fish and Wildlife Service (“FWS”) in 1989.  Specifically, the FWS announced in November 2016 that it is considering listing the Lesser Prairie Chicken as threatened under the ESA, and is undertaking an assessment of the biological status of the species, which is expected to be complete in mid-2017. Both have habitat in some areas where we operate.  Although we are participants in a conservation agreement overseen by the FWS which may mitigate our exposure if the Lesser Prairie Chicken is listed as threatened, the presence of these and other protected species in areas where we operate could impair our ability to timely complete or carry out those operations, lose leaseholds as we may not be permitted to timely commence drilling operations, cause us to incur increased costs arising from species protection measures, and, consequently, adversely affect our results of operations and financial position.  

Climate Change

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol.  Legislation has been proposed in Congress directed at reducing greenhouse gas emissions, and which has support in various regions of the country for legislation Some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future federal or state restrictions on such emissions could impact our future operations. In June 2016, the EPA published final regulations setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Obama Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45% from 2012 levels by 2025.  In November 2016, the Bureau of Land Management published a final version of its venting and flaring rule, which impose stricter reporting obligations, or limit emissions of greenhouse gases from our equipment and operations, could require us to incur additional costs and to reduce emissions associated with our operations.  In response to these regulations, or other future federal, state or regional legislation, our operating costs could increase due to requirements to (1) obtain permits; (2) operate and maintain equipment and facilities (e.g. through the reduction or elimination of venting and flaring of methane); (3) install new emission controls; (4) acquire allowances authorizing greenhouse gas emissions; (5) pay taxes related to our greenhouse gas emissions; and (6) administer and manage greenhouse gas emission programs. Although our operations are not adversely impacted by current state and local climate change initiatives, at this time it is not possible to accurately estimate how potential future laws or regulations limiting or otherwise addressing greenhouse gas emissions would impact our business.

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Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. It is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds, and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction.  

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands and some Indian lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands and Indian lands in Osage County, Oklahoma require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects, or may result in cancellation of leases or other adverse action in the event of noncompliance. See Item 1A. Risk Factors of this report for further discussion.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.

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FERC also regulates interstate natural gas transportation rates and terms and conditions of service, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rulemakings that significantly fostered competition in the business of transporting and marketing natural gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy natural gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under the NGA, the rates for service on interstate natural gas facilities must be just and reasonable and not unduly discriminatory. Generally, the maximum filed recourse rates for interstate pipelines are based on the pipeline’s cost of service including recovery of and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are costs of providing service, allowed rate of return, volume throughput and contractual capacity commitment assumptions. FERC also allows pipelines to charge market-based rates if the transportation market in question is sufficiently competitive.  Section 1(b) of the NGA exempts natural gas gathering service, which occurs upstream of jurisdictional transmission services, from FERC jurisdiction.  Gathering service is instead regulated by the states onshore and in state waters. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress.  In fact, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point-of-sale locations. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA.  Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.  In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

Natural Gas Pipeline Safety

The Department of Transportation (“DOT”), and specifically the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), regulate transportation of natural and other gas by pipeline and impose minimum federal safety standards pursuant to the pipeline safety laws codified at 49 U.S.C. 60101, et seq., the hazardous material transportation laws codified at 49 U.S.C. 5101, et seq., regulations contained within 49 C.F.R. Parts 192 and 195, and similar state laws.  Our natural gas pipelines are subject to this regulation.  We believe we are in material compliance with all applicable regulations imposed by the DOT and PHMSA regarding our natural gas pipelines.  However, significant expenses could be incurred in the future if additional safety measures are required, or if safety standards are raised and exceed the degree of our current natural gas pipeline operations.  For instance, in April 2016, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas transmission pipelines.  The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and other requirements.  The DOT may also assess fines and penalties for violations of these and other requirements imposed by its regulations.

CO₂ Pipeline Safety

DOT and specifically PHMSA, regulate the transportation of hazardous liquids and carbon dioxide by pipeline and impose minimum federal safety standards pursuant to the pipeline safety laws codified at 49 U.S.C. 5101, et seq., and regulations contained within 49 C.F.R. Part 195 prescribe safety standards and reporting requirements for pipeline facilities use in transporting hazardous liquids or carbon dioxide. Our CO₂ pipelines are subject to this regulation, which, among other things, address pipeline integrity management and pipeline operator qualification rules. Significant expenses could be incurred in the future if additional safety measures are required, or if safety standards are raised and exceed the degree of our current CO₂ pipeline operations. The DOT may assess fines and penalties for violations of these and other requirements imposed by its regulations. We believe we are in material compliance with all applicable regulations imposed by the DOT and PHMSA regarding our CO₂ pipelines.

In early 2012, the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was enacted which, among other things, updated federal pipeline safety standards, increased penalties for violations of such standards, gave the DOT authority for new damage prevention and incident notification, and directed the DOT to prescribe new minimum safety standards for CO₂ pipelines. Implementation of this Act could affect our operations and the costs thereof. While some new regulations to implement this Act have been adopted or proposed, no such new minimum safety standards have been proposed or adopted for CO₂ pipelines.  In January 2017,

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PHMSA issued a final rule amending federal safety standards for hazardous liquid pipelines.  The final rule is the latest step in a lengthy rulemaking process that began in 2010 with a request for comments and continued with publication of a rulemaking proposal in October 2015.  The general effective date of this final rule is six months from publication in the Federal Register, but it is currently subject to further administrative review in connection with the transition of Presidential administrations.  The final rule addresses several areas including reporting requirements for gravity and unregulated gathering lines, inspections after weather or climatic events, leak detection system requirements, revisions to repair criteria and other integrity management revisions.  In addition, PHMSA issued new regulations in January 2017 on operator qualification, cost recovery, accident and incident notification and other pipeline safety changes.  These new regulations are to be effective March 2017. These regulations are also subject, however, to potential further review in connection with the transition of Presidential administrations.

States are responsible for enforcing the federal regulations and more stringent state pipeline regulations and inspection with respect to hazardous liquids pipelines, including crude oil, natural gas and CO₂ pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate.

Our Coffeyville CO₂ Pipeline has experienced four total pipeline failures from 2015 to 2016.  There were two underground mainline pipeline failures and one above ground peripheral tubing failure in 2015.  There was one underground mainline pipeline failure in 2016.  The 2015 above ground peripheral tubing failure was the result of a tubing connection failure.  The failed tubing connection was replaced with new equipment and all other like connections on the Coffeyville CO₂ pipeline were replaced as a precaution.   The three underground mainline pipeline failures on the Coffeyville CO₂ pipeline were the result of stray current interference that resulted in exterior metal loss.  All three locations were repaired by replacing the failed pipe section with new, pre-tested pipe.  We have performed extensive activities to locate and remediate additional areas of stray current interference, replaced or repaired pipe at locations with identified external corrosion and added additional protection measures to the cathodic protection system to prevent further occurrences of external corrosion. As a result of a 2015 Pipeline Safety Inspection, we have been issued a Notice of Proposed Violation with a Proposed Civil Penalty in the amount of $158,000. We are in the process of contesting this Proposed Civil Penalty and are currently in negotiations concerning the aforementioned penalty.

CO₂ Processing Safety

Our CO₂ capture, compression and processing facility near Liberal, Kansas is subject to the requirements of the Occupational Health and Safety Administration (“OSHA”) regulations for process safety management (“PSM”).  In order to condense the CO₂ from a gas to a liquid, propane is used as a refrigerant. OSHA has identified propane as a highly hazardous chemical.   Pursuant to OSHA regulations require companies to implement a PSM program to prevent or minimize consequences related to the catastrophic release of toxic, flammable, explosive, or reactive chemicals that may result in toxic, fire, or explosion hazards. Employers must develop a written action plan for implementation of process hazard analyses to assist in the identification of hazards posed by processes involving the highly hazardous chemicals in use, including information and understanding of the hazardous chemicals in use, process technology, and equipment used.  The process hazard analysis must be updated every five (5) years.  Written operating and change management procedures must also be in place and updated as necessary and training must be performed and updated for all employees involved in the process.  PSM also requires the development of procedures to ensure the mechanical integrity of process equipment, as well as ongoing inspection and quality assurance.

Various other federal and state regulations require that we implement a Hazard Communication (“HAZCOM”) program to train all employees who may use or be exposed to hazardous chemicals and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request.

Natural Gas Gathering Regulations

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements and complaint-based rate regulation.  The regulations generally require gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply over another similarly situated source of supply.  Such regulations can have the effect of imposing restrictions on a pipeline’s ability to decide with whom it contracts to gather natural gas. In addition, natural gas gathering is addressed in EPA’s proposed greenhouse gas monitoring and reporting rule, is subject to air permitting requirements where applicable, and may receive greater regulatory scrutiny in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

State Regulation

The various states regulate the drilling for, and the production, gathering, and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or

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both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation, and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.  

Seasonality

While our limited operations located in the Gulf Coast may experience seasonal fluctuations, we do not believe these fluctuations have had, or will have, a material impact on our consolidated results of operations.

Legal Proceedings

Please see Item 3. Legal Proceedings for a discussion of our material legal proceedings. In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

Title to Properties

We believe that we have satisfactory title to all of our owned assets. As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to undeveloped leasehold acreage rights acquired through oil and natural gas leases or farm-in agreements. Prior to the commencement of drilling operations on undeveloped leasehold, we conduct a title examination and perform curative work with respect to any significant title defects. Prior to completing an acquisition of an interest in significant producing oil and natural gas properties, we conduct due diligence as to title for the specific interest we are acquiring. Our interests in oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other similar burdens and minor easements, restrictions and encumbrances which we believe do not materially detract from the value of these interests either individually or in the aggregate and will not materially interfere with the operation of our business. We will take such steps as we deem necessary to ensure that our title to our properties is satisfactory. We are free, however, to exercise our judgment as to reasonable business risks in waiving title requirements.

Employees

As of December 31, 2016, we had 343 full-time employees. We also contract for the services of independent consultants involved in land, regulatory, accounting, finance and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

During 2016 and 2015, we terminated 64 and 213 employees, respectively, as part of our workforce reduction.  

ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.

We may not be able to achieve our projected financial results or service our debt

Although the financial projections recently disclosed in our Disclosure Statement filed with the Bankruptcy Court represent our view based on then current known facts and assumptions about the future operations of the Company there is no guarantee that the financial projections will be realized. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned after emergence from bankruptcy and may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things: (a) taking advantage of future opportunities; (b) growing our businesses; or (c) responding to future changes in the oil and gas industry. Further, our failure to meet the projected financial results or achieve projected revenues and cash flows could lead to cash flow and working capital constraints, which constraints may require us to seek additional working capital. We may not be able to obtain such working capital when it is required.

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Oil and gas price volatility, including the recent significant decline in oil and gas prices, have adversely affected and continue to adversely affect our financial condition, financial results, cash flows, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following:

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and gas price movements with any certainty. For example, during the five years prior to December 31, 2016, the posted price for West Texas Intermediate light sweet crude oil, commonly referred to as West Texas Intermediate, has ranged from a low of $26.19 per Bbl in February 2016 to a high of $110.62 per Bbl in September 2013. The Henry Hub daily spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. Since mid-2014, oil and natural gas prices have declined significantly, due in large part to increasing supplies and weakening demand growth.  The significant decline in oil and natural gas prices beginning in the second half of 2014 and continuing today has materially adversely impacted our operations, the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base.

Extended periods of continuing lower oil and natural gas prices will not only reduce our revenue but also will reduce the amount of oil and natural gas we can produce economically, and as a result, would have a material adverse effect on our financial condition, results of operations, and reserves. During periods of low commodity prices we shut in or curtail production from additional wells and defer drilling new wells, challenging our ability to produce at commercially paying quantities required to hold our leases.  A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.  

A decline in prices from current levels may lead to additional write downs of the carrying values of our oil and natural gas properties in the future which could negatively impact results of operations.

We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the units-of-production method. However, these capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of estimated future net revenues attributable to proved oil and natural gas reserves discounted at 10% net of tax considerations, plus the cost of unproved properties not being amortized. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date. A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. We recorded ceiling test write-downs of $281 million in 2016 and $1.5 billion in 2015. Crude oil prices have staged a moderate recovery in late 2016 and early 2017 from previous historic lows in early 2016. However, oil and natural gas prices are volatile and this and other factors, without mitigating circumstances, could require us to further write down capitalized costs and

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incur corresponding noncash charges to earnings. Since the prices used in the cost ceiling are based on a trailing twelve-month period, the full impact of a sudden price decline is not recognized immediately.

The carrying value of our oil and natural gas assets will be restated under fresh start accounting upon our emergence from bankruptcy. The restated amount could exceed the full cost ceiling limit at March 31, 2017, which would result in a ceiling test impairment.

As a result of our reorganization under Chapter 11 and subsequent emergence from bankruptcy on March 21, 2017, we will apply fresh start accounting to our balance sheet which results in the carrying value of our oil and natural gas properties being restated based on their fair value. We are still in the process of estimating the fair value. It is possible that our estimate of the fair value of our oil and natural gas properties utilized as the fresh start opening balance upon our emergence from bankruptcy could result in the carrying value exceeding the full cost ceiling limit at March 31, 2017, which would require us to record a ceiling test impairment.

A significant portion of total proved reserves as of December 31, 2016, are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2016, approximately 57%, of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves at a total estimated undiscounted cost of $1.0 billion. You should be aware that actual development costs may exceed estimates, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves.

In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking or unless specific circumstances justify a longer time. A substantial portion of our proved undeveloped reserves are scheduled to be developed over a period extending beyond the typical five year time frame. These reserves are related to our Active EOR Areas and we believe that the specific facts and circumstances of the ongoing projects within these areas justify a longer development time frame. We may be required to write off any reserves that are not developed within this five-year time frame in the event that the SEC does not agree that the specific circumstances related to the longer-term reserves are otherwise exempted from the five-year reporting rules.

The actual quantities and present value of our proved reserves may be lower than we have estimated.

Estimating quantities of proved oil and natural gas reserves is a complex process. The quantities and values of our proved reserves in the projections are only estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly affect these estimates. Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserves reports. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of future net cash flows from our oil and natural gas reserves.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses associated with the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the SEC, the estimates of present values are based on a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. Our December 31, 2016 reserve report used SEC pricing of $2.49 per Mcf for natural gas and $42.75 per Bbl for oil.

The development of the proved undeveloped reserves in our Active EOR Areas may take longer and may require higher levels of capital expenditures than we currently anticipate.

As of December 31, 2016, undeveloped reserves in our Active EOR Areas comprised 55% of our total estimated proved reserves. As of December 31, 2016, we expect to incur future development costs of $0.9 billion, including $323 million for CO₂ purchase, compression and transportation, over the next 30 years to substantially develop these reserves. The future development costs for our Active EOR Areas are 86% of our total estimated future development and abandonment costs of $1.1 billion as of

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December 31, 2016. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of these reserves will require the use of EOR techniques, including water flood and CO₂ injection installations, the success of which is still subject to interpretation and predictability by reservoir engineers. Therefore, ultimate recoveries from these fields may not match current expectations.

Restrictive covenants in our New Credit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our New Credit Facility imposes operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:

The restrictions contained in the New Credit Facility could:

Our New Credit Facility includes provisions that require mandatory prepayment of outstanding borrowings and/or a borrowing base redetermination when we make asset dispositions over a certain threshold, which could limit our ability to generate liquidity from asset sales. Also, our New Credit Facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in oil and natural gas prices could result in our failing to meet one or more of the financial covenants under our New Credit Facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our New Credit Facility. A default under our New Credit Facility, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder, which in turn would trigger cross-acceleration and cross-default rights under our other debt.

Provisions in the Stockholders Agreement restrict may delay or prevent certain transactions that would be beneficial to our stockholders and our business, which could adversely affect our ability to conduct business.

The Stockholders Agreement contains certain provisions requiring the approval of 66 2/3% of our stockholders, thereby restricting the ability of our board of directors to effect certain transactions or other advantageous actions.  Such provisions requiring the approval of holders of at least 66 2/3% of our outstand common stock could make it more difficult or impossible for us to enter into transactions or agreements that are important to our business, even if the transaction or agreement would be beneficial to our stockholders, including:

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Competition in the oil and natural gas industry is intense and many of our competitors have greater financial and other resources than we do

We operate in the highly competitive areas of oil and natural gas production, acquisition, development, and exploration and face intense competition from both major and other independent oil and natural gas companies:

Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.

Drilling wells is speculative and capital intensive.

Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on commercially reasonable terms to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, which may have an adverse effect on our results of operations and financial condition. In addition, drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop, or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Recovery of such reserves will require significant capital expenditures and successful drilling and EOR operations. Our December 31, 2016 reserve estimates reflect that our production rate on current proved developed reserve properties will decline at annual rates of approximately 15%, 13%, and 15% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations, and cash flows are highly dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves. Due to lower oil prices, we have significantly reduced capital expenditures in 2015 and 2016 compared to 2014 which has therefore reduced our replacement of reserves when compared to previous years.

Development and exploration drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be economically recovered and/or produced. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit at then-realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. These risks are magnified when operating in an environment of low crude oil prices. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

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If, for any reason, we are unable to economically recover reserves through our exploration and drilling activities, our results of operations, cash flows, growth, and reserve replenishment may be materially affected.

Oil and natural gas drilling and production operations can be hazardous and may expose us to uninsurable losses or other liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, hydraulic fracturing fluids, toxic gas or other pollutants and other environmental and safety hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:

Our liability for environmental hazards sometimes includes those created on properties prior to the date we acquired or leased them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover any or all resulting losses or liabilities. Moreover, if we experience more insurable events, our annual premiums may increase further or we may not be able to obtain any such insurance on commercially reasonable terms. The occurrence of, or failure by us to obtain or maintain adequate insurance coverage for, any of the events listed above could have a material adverse effect on our financial condition and results of operations, as well as our growth, exploration, and employee recruitment activities.  

We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.

Availability under our New Credit Facility Revolver (the “New Revolver”) is subject to a borrowing base, initially set at $225.0 million as of March 21, 2017, and which is redetermined by the banks semi-annually on May 1 and November 1 of each year, commencing in May 1, 2018. In addition, the banks may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. Dispositions of our oil and natural gas assets or incurrence of permitted senior unsecured debt may also trigger automatic reductions in our borrowing base.  If the outstanding borrowings under our New Revolver were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 45 days or in equal monthly installments over a six-month period; (2) to submit within 45 days additional unburdened oil and gas properties to be mortgaged sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 45 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Asset sales may also reduce available collateral and availability under the New Credit Facility and could have a material adverse effect on our business and financial results. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.

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Resolution of litigation could materially affect our financial position and results of operations.

We have been named as a defendant in certain lawsuits. See Item 3. Legal Proceedings. In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods. We may also become involved in litigation over certain issues related to the Reorganization Plan, including the proposed treatment of certain claims thereunder. The outcome of such litigation could have a material impact on our financial position or results of operations in future periods.

We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside of our control, including the operator’s:

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

If the third parties we rely on for gathering and distributing our oil and natural gas are unable to meet our needs for such services and facilities, our future exploration and production activities could be adversely affected.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and refineries or processing facilities. Such third parties are subject to federal and state regulation of the production and transportation of oil and natural gas. If such third parties are unable to comply with such regulations and we are unable to replace such service and facilities providers, we may be required to shut-in producing wells or delay or discontinue development plans for our properties. A shut-in, delay or discontinuance could adversely affect our financial condition.

Limitations or restrictions on our ability to obtain water may have an adverse effect on our operating results.

Our operations require significant amounts of water for drilling and hydraulic fracturing. Limitations or restrictions on our ability to obtain water from local sources may require us to find remote sources. In addition, treatment and disposal or such water after use is becoming more highly regulated and restricted. Thus, costs for obtaining and disposing of water could increase significantly, potentially limiting our ability to engage in hydraulic fracturing. This could have a material adverse effect on our operations.

We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner, and feasibility of doing business.

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing, among other things: land use restrictions, drilling bonds and other financial responsibility requirements, reporting and other requirements with respect to emissions of greenhouse gases and air pollutants, utilization and pooling of properties, habitat and endangered species protection, reclamation and remediation, well stimulation processes, produced water disposal, CO₂ pipeline requirements, safety precautions, operational reporting, and tax requirements. These laws, regulations and related public policy considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators. Changes in, or additions to, environmental laws

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and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or other environmental protection requirements could have a material adverse effect on our operations and financial position.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development. Additionally, future federal and state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal and state income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently available to oil and gas companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the increase of the amortization period of geological and geophysical expenses, (iii) the elimination of current deductions for intangible drilling and development costs; and (iv) the elimination of the deduction for certain U.S. production activities. Moreover, other generally applicable features of proposed tax reform legislation, such as changes to the deductibility of interest expense, the cost recovery rules and the types of income subject to federal income taxes could impact our income taxes and resulting operating cash flow.  Although it is currently unclear whether any such proposals will be enacted or what form they might possibly take, the President and Congress could include some or all of these proposals as part of anticipated tax reform legislation to accompany lower U.S. federal income tax rates. The passage of such legislation or any other similar change in U.S. federal income tax law could eliminate, reduce or postpone certain tax deductions that are currently available to us or otherwise affect our U.S. federal income tax liability and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for petroleum products and thereby affect the prices we receive for our commodity products.

Potential legislative and regulatory actions could negatively affect our business.

In addition to the Safe Drinking Water Act and other potential regulations on hydraulic fracturing practices, numerous other legislative and regulatory proposals affecting the oil and gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by Congress, state legislatures and various federal and state agencies. Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress, and EPA regulations to reduce greenhouse gas emissions; and (2) legislation introduced in Congress to impose new taxes on, or repeal various tax deductions available to, oil and gas producers, such as the current tax deductions for intangible drilling and development costs, which deductions, if eliminated, could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities. Any of the foregoing described proposals could affect our operations, and the costs thereof. The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on demand for oil and natural gas or prices at which it can be sold. However, until such legislation or regulations are enacted or adopted into law and thereafter implemented, it is not possible to gauge their impact on our future operations or their results of operations and financial condition.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and waste water injector wells could result in increased costs and additional operating restrictions or delays.

Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Beginning in August 2012, the EPA issued a series of rules under the CAA that establish new emission control requirements for emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment. And in March 2015, the Bureau of Land Management finalized a rule governing hydraulic fracturing on federal lands, implementation of which has been stayed pending the resolution of legal challenges. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

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More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells (and to a lesser extent, hydraulic fracturing) has caused increased seismic activity in certain areas. In response, some states, including states in which we operate, have imposed additional requirements on the construction and operation of underground disposal wells.  For example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geologic Survey recently released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including mitigation, following anomalous seismic activity within 1.25 miles of hydraulic fracturing operations.

These developments, as well as increased scrutiny of hydraulic fracturing and underground injection activities by state and municipal authorities may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our cost of compliance and doing business

Studies by both state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens.

In recent years, Oklahoma has experienced a significant increase in earthquakes and other seismic activity. On April 21, 2015, the Oklahoma Geologic Survey (“OGS”) issued a document entitled “Statement of Oklahoma Seismicity,” in which the agency states “[t]he OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.” The Oklahoma Corporation Commission (“OCC”) has issued directives restricting injection of high volumes of water into the Arbuckle formation and into the crystalline basement below within a specified area of interest (“AOI”) in Central and Western Oklahoma. In the Spring of 2016 the OCC issued Regional Earthquake Response Plans for Western Oklahoma, Combined, the Plans expanded the 2015 AOI  to include more than 10,000 square miles and more than 600 Arbuckle disposal wells, resulting in a reduction of more than 800,000 barrels per day from the 2015 average injection volumes.  We operate 16 wells in the AOI and are fully compliant with all regulations relating to the disposal of produced water.  In addition, in September and November of 2016 the OCC issued additional directives requiring modification of disposal in wells in the vicinity of Pawnee and Cushing, Oklahoma requiring salt water disposal wells to be shut in or to reduce injection volumes into salt water disposal wells in the area.  We did not operate any of the disposal wells in the additional area.  On February 24, 2017, the OCC issued a new directive aimed at limiting the future growth of disposal rates into the Arbuckle by capping disposal volumes in the AOI, even those not operating under currently permitted volumes, to the thirty day disposal average.   Although we continue to operate disposal wells in the area, at this time our operations have not been affected.  We cannot predict whether future regulatory actions will result in further expansion of this “area of interest” or new or additional regulations by the OCC or other agencies with jurisdiction over our operations.  Any such expansion or new regulation could result in additional levels of regulation, or increased complexity with respect to existing regulations, that could lead to operational delays or increased operating costs and result in additional regulatory burdens that could make it more difficult to inject produced water into disposal wells, and may increase our costs of compliance and doing business.  In addition, even though we have conducted our operations in compliance with applicable laws, the increase in media and regulatory attention to the possible connection between seismic activity and produced water injection has led to litigation filed against us and other oil and gas producers requesting compensation for damages, including demands for earthquake insurance premiums on a going forward basis.  We cannot predict the outcome of this litigation or provide assurances that other similar claims will not be filed against us in the future.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.

Costs of environmental liabilities could exceed our estimates and adversely affect our operating results.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

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Although we believe we have established appropriate reserves for known liabilities, including cleanup costs, we could be required to set aside additional reserves in the future due to these uncertainties, incur material cleanup costs, other liabilities, and/or expend significant sums to defend ourselves against litigation related to legacy environmental issues, which could have an adverse effect on our operating results.

Our use of derivative instruments could result in financial losses or reduce our income.

To reduce our exposure to the volatility in the price of oil and gas and provide stability to cash flows, we enter into derivative positions. Our commodity hedges are currently comprised of fixed price swaps and collars with financial institutions. The volumes and average notional prices of these hedges are disclosed in in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report.

Derivative instruments expose us to risk of financial loss in some circumstances, including when:

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, none of our derivatives are classified as hedges for accounting purposes and therefore must be adjusted to fair value through income each reporting period.

While the primary purpose of our derivative transactions is to protect ourselves against the volatility in oil and natural gas prices, under certain circumstances, or if hedges are discontinued, or terminated for any reason, we may incur substantial losses in closing out our positions, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

We are subject to financing and interest rate exposure risks.

Our future success depends on our ability to access capital markets and obtain financing on reasonable terms. Our ability to access financial markets and obtain financing on commercially reasonable terms in the future is dependent on a number of factors, many of which we cannot control, including changes in:

Assuming a constant debt level of $375.0 million, equal to our borrowing base as of March 21, 2017 under the senior secured revolving loan of our New Credit Facility and our term loan under the same facility, the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $3.8 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects.

Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma and Texas, our operations are constantly at risk of extreme adverse weather conditions such as freezing rain, tornadoes and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or

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otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as freezing rain, hurricanes or floods, whether due to climate change or otherwise.

Changes in, or challenges to, our rates and other terms and conditions of service could have a material adverse effect on our financial condition and results of operations.

The rates charged by certain of our pipeline systems are regulated by the Federal Energy Regulatory Commission, or FERC, state regulatory agencies, or both.  These regulatory agencies also regulate other terms and conditions of the services these pipeline systems provide, including the types of services we may offer.  If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose, the profitability of our pipeline businesses would suffer.  If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which if delayed could further reduce our cash flow.  Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so.  The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction.  New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

A change in the jurisdictional characterization of our assets, or a change in policy, could result in increased regulation of our assets which could materially affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.

Certain of our pipeline assets are natural gas gathering facilities.  Unlike interstate natural gas transportation facilities, natural gas gathering facilities are exempt from the jurisdiction of the FERC under the Natural Gas Act of 1938, or NGA.  Although the FERC has not made a formal determination with respect to all of our facilities we believe to be gathering facilities, we believe that these pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction.  The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress.  If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978, or NGPA.  Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and cash flows.  In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.

The absence of a quorum at FERC, if it persists, could limit our ability to construct new facilities and/or expand certain existing facilities, which could have a material and adverse impact on our business and result of operations.

FERC, or the Commission, oversees, among other matters, the interstate sale at wholesale and transportation of natural gas.  FERC’s authority includes reviewing proposals to site, construct, expand and/or retire interstate natural gas pipeline facilities.  As set forth in the Department of Energy Authorization Act (“DOE Act”), the Commission is composed of up to five Commissioners, who are to be appointed by the President and confirmed by the Senate.  The DOE Act requires that at least three Commissioners be present “for the transaction of business.”  Without such a quorum of three or more Commissioners, FERC is unable to act on matters that require a vote of its Commissioners.  Norman Bay, a FERC Commissioner and former Chairman of the Commission, resigned effective February 3, 2017.  With Commissioner Bay’s departure, only two FERC Commissioners remained in office, as there were already two vacancies prior to Commissioner Bay’s resignation.  FERC has therefore lacked the quorum required for its Commissioners to issues orders and take other actions since February 3.  While FERC staff may still issue certain routine or uncontested orders under authority delegated by the Commission while it had a quorum, and such delegated authority was broadened immediately prior to Commissioner Bay’s departure, FERC is currently unable to resolve contested cases or issue major new orders, such as certificates of public convenience and necessity for new interstate natural gas pipelines or the expansion of existing FERC-certificated pipelines.  The current limitations on FERC’s ability to act have not had a material effect on our operations, but if the absence of a quorum continues for a long enough period of time, our ability to construct new facilities and/or expand the capacity of our pipelines could be materially affected.  The absence of a quorum will continue until a new FERC Commissioner is nominated by the President and confirmed by the Senate, provided the two remaining FERC Commissioners remain in office.  The President has not yet nominated any new FERC Commissioners to fill the vacancies.  

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Increased regulatory requirements regarding pipeline safety and integrity management may require us to incur significant capital and operating expenses to comply.

The ultimate costs of compliance with pipeline safety and integrity management regulations are difficult to predict. The majority of the compliance costs are for pipeline safety and integrity testing and the repairs found to be necessary. We plan to continue our efforts to assess and maintain the safety and integrity of our existing and future pipelines as required by the DOT and PHMSA rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. In addition, new laws and regulations that may be enacted in the future, or a revised interpretation of existing laws and regulations, could significantly increase the amount of these costs. We cannot be assured about the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs, or additional operating restrictions, could have a material adverse effect on our business, financial position, results of operations and prospects.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on us and our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. New or modified rules, regulations or requirements may increase the cost and availability to the counterparties of our hedging and swap positions which they can make available to us, as applicable, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities which may not be as creditworthy as the current counterparties. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

While many rules and regulations have been promulgated and are already in effect, other rules and regulations remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives that we use to hedge against commodity price fluctuations (including through requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter, and (iv) increase our exposure to less creditworthy counterparties.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

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 and natural gas prices, causing periodic shortages in such personnel.  The severe industry decline over the past couple of years has resulted in a large displacement of experienced personnel through layoffs and many of the affected personnel have moved on to careers in other industries. This structural shift in available workforce may be impactful in future periods. Recently the industry has experienced a modest price recovery that began in late 2016. This has resulted in an increase in the number of active drilling rigs and stimulated demand for crews and associated supplies, oilfield equipment and services, and personnel. As such we may encounter shortages of these resources as well as increased prices. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

A significant portion of our operations are located in Oklahoma and the Texas Panhandle, making us vulnerable to risks associated with operating in a limited number of major geographic areas.

As of December 31, 2016, almost 100% of our proved reserves and production was located in the Mid-Continent geographic area. This concentration could disproportionately expose us to operational and regulatory risk in this area. This lack of diversification in location of our key operations could expose us to adverse developments in our operating areas or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more geographically diversified.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of their exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas

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reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to their business. Our technologies, systems and networks may become the target of cyber-attacks or information security breaches that could result in the disruption of our business operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations. To date we have not experienced any material losses relating to cyber-attacks, however there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance their protective measures or to investigate and remediate any cyber vulnerabilities.

The adoption of climate change legislation or regulations restricting emissions of greenhouse gases could result in

increased operating costs and reduced demand for natural gas.

The EPA has determined that greenhouse gases present an endangerment to public health and the environment because such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented, and continues to adopt and implement, regulations that restrict emissions of greenhouse gases (“GHGs”) under existing provisions of the Clean Air Act (“CAA”). The EPA also requires the annual reporting of GHG emissions from certain large sources of GHG emissions in the United States, including certain oil and gas production facilities. The EPA has also taken steps to limit methane emissions from oil and gas production facilities. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. And 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. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement entered into force in November 2016. The United States is one of over 70 nations that has ratified or otherwise indicated that it intends to comply with the agreement. Restrictions on emissions of GHGs that may be imposed could adversely affect the natural gas industry by reducing demand for hydrocarbons and by making it more expensive to develop and produce hydrocarbons, either of which could have a material adverse effect on future demand for our services. Moreover, climate change may cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured. For a more detailed discussion of climate change, please see Environmental Matters and Regulation – Climate Change.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Item 1. Business and Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See our additional disclosures in “Liquidity and Capital Resources—Contractual Obligations” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as “Note 14—Commitments and contingencies” in Item 8. Financial Statements and Supplementary Data. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

Chapter 11 Proceedings. Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016. In connection with the proofs of claim asserted during bankruptcy from the proceedings or actions below, we are unable to estimate the amounts that will be allowed through the Bankruptcy proceedings due to the complexity and number of legal and factual issues presented by the matters and uncertainties with respect to, amongst other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcomes of the matters. As a result, no reserves have been established within our liabilities subject to compromise in connection with the proceedings and actions described below. To the extent that any of these legal proceedings result in a claim being allowed against us, such claims will be satisfied through the issuance of new stock in the Company. For additional information on the bankruptcy proceedings, see Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Trial Court”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma (“Naylor Farms Case”). The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma.

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The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. Responsive briefs to both motions were filed in the fourth quarter of 2015. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. In response, on May 23, 2016, the court issued an order administratively closing the case, subject to reopening depending on the disposition of the bankruptcy proceedings. On July 22, 2016, attorneys for the putative class filed a motion in the Bankruptcy Court asking the court to lift the automatic stay and allow the case to proceed in the Naylor Trial Court. We did not object to lifting the automatic stay with regard to this case for the limited purpose of allowing the Naylor Trial Court to rule on the pending motion for class certification. On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the Plaintiffs originally sought to certify. On January 30, 2017, the Company filed a motion for reconsideration with the Naylor Trial Court, asking the court to rule the class cannot be immediately certified because Plaintiffs did not define dates for class membership.

The plaintiffs have indicated, if the class is certified, they seek damages in excess of $5.0 million which may increase with the passage of time, a majority of which would be comprised of interest. In addition to filing claims on behalf of the named plaintiffs and associated parties, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $150.0 million in our Chapter 11 Cases. The Company has objected treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. The Bankruptcy Court heard testimony and argument regarding class-wide treatment of the claim on February 28, 2017, but has not ruled on the matter. Under the Reorganization Plan, the Plaintiffs are identified as a separate class of creditors, Class 8.  The Plaintiffs voted to reject the Reorganization Plan.  Under the Reorganization Plan, Class 8 claims are entitled to receive their pro rata share of new stock issued to the holders of general unsecured claims (including claims of the Noteholders).  Although the members of Class 8 did not vote to accept the Plan, the Bankruptcy Court confirmed the Plan on March 10, 2017. If the Bankruptcy Court permits the plaintiffs to file their proof of claim on behalf of the putative class, the claim is certified on a class basis, and the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgment or settlement of the unsecured claims would be satisfied through the issuance of new stock in the Company. We continue to dispute the plaintiffs’ allegations, dispute the case meets the requirements for class certification, and are objecting to the claims both individually and on a class-wide basis.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson, filed a complaint against us in the District Court of Mayes County, Oklahoma, (“Dodson Case”) with an allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include claims for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At the time we filed our Bankruptcy Petitions, a class had not been certified and discovery had not yet commenced. As the plaintiffs in the Dodson case did not file proofs of claim either for the putative class or the putative class representative, we anticipate any liability related to this claim will be addressed only based on proofs of claim filed by individual royalty owners.

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs challenged leases and drilling permits approved by the Bureau of Indian Affairs without the environmental studies allegedly required under the National Environmental Protection (NEPA). The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. On March 31, 2016, the Court dismissed the case against the federal agencies named as defendants, and therefore against all defendants, as an improper challenge under NEPA and the Administrative Procedures Act. On April 29, 2016, the plaintiffs filed a motion to alter or amend the court’s opinion and vacate the judgment, arguing the court does have jurisdiction to hear the claims and dismissal of the federal defendants does not require dismissal of the oil company defendants. The plaintiffs also filed a motion to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. Several defendants have filed briefs objecting to plaintiffs’ motions. On May 20, 2016, the Company filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code, and has not responded to the plaintiffs’ motions. After a motion for reconsideration was denied, Plaintiffs filed a Notice of Appeal on December 6, 2016. On December 30, 2016, the Court of Appeals entered an Order Abating Appeal due to pending bankruptcy proceedings of multiple defendants. On January 13, 2017 Plaintiffs responded to the Order Abating Appeal, asking the Court to proceed with the appeal. The court has not ruled on the appeal as of the date of this report.

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As the plaintiffs in the Donelson case did not file proofs of claim either for the putative class or the putative class representatives, we anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class action.

Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On February 18, 2016, an alleged class action was filed against us, as well as several other operators in the District Court of Pottawatomie County, State of Oklahoma (“West Case”), alleging claims on behalf of named plaintiffs and all similarly situated persons having an insurable real property interest in eight counties in central Oklahoma (the “Class Area”). The plaintiffs allege the oil and gas operations conducted by us and the other defendants have induced or triggered earthquakes in the Class Area. The plaintiffs are asking the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through a future date defined as the time at which the court determines there is no longer a risk that our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief. The plaintiffs did not ask for damages related to actual property damage which may have occurred. We responded to the petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. On March 18, 2016, the case was removed to the United States District Court for the Western District of Oklahoma under the Class Action Fairness Act (“CAFA”). On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. On October 14, 2016, the plaintiffs filed an Amended Complaint adding additional defendants and increasing the Class Area to 25 Central Oklahoma counties. Although we are named as a defendant, the Amended Complaint expressly limits its claims against us to those asserted in the original petition unless and until the automatic stay is lifted. Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75.0 million in our Chapter 11 Cases. Other defendants have filed motions to dismiss the action based on various theories. The court has not ruled on these motions. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case.

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

 

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock has not been registered under the Securities Exchange Act of 1934, and there is no established public trading market for our common equity.

As of March 15, 2017, prior to our emergence from bankruptcy, there were 1,382,288 outstanding shares of common stock of the Predecessor held by 19 record holders. As of March 27, 2017, subsequent to our emergence from bankruptcy, there were 44,904,514 outstanding shares of common stock of the Successor held by 1 record holder. In addition, as of March 27, 2017, we had outstanding warrants for the purchase of 140,023 shares of common stock with an exercise price of $36.78 which are immediately exercisable and will expire on June 30, 2018.

We have not paid any dividends on our common stock in either of the last two years and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also restricted in our ability to pay dividends under our Existing Credit Facility and New Credit Facility. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for more information regarding the restrictions on our ability to pay dividends.

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ITEM 6. SELECTED FINANCIAL DATA

You should read the following historical financial data in connection with the financial statements and related notes and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this report. The financial data as of and for each of the five years ended December 31, 2016 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.

 

 

 

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. In addition to historical financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Introduction

Founded in 1988 and headquartered in Oklahoma City, we are a Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich STACK play, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage and Woodford formations. We also have significant production from CO₂ EOR methods underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state. As of December 31, 2016, we had estimated proved reserves of 131.3 MMBoe with a PV-10 value of approximately $529 million using SEC pricing as of the same date. Our reserves were 43% proved developed, 74% crude oil, 17% natural gas and 9% natural gas liquids.

Generally, our producing properties have declining production rates.  Our December 31, 2016 reserve estimates reflect that our production rate on current proved developed properties will decline at annual rates of approximately 15%, 13%, and 15% for the next three years.  To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production.  Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

Chapter 11 Reorganization

Bankruptcy petition and emergence. On May 9, 2016 (the “Petition Date”), Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2 , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C. (collectively, the “Chapter 11 Subsidiaries” and, together with Chaparral Energy, Inc., the “Debtors”) filed voluntary petitions seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”).

On March 10, 2017 (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy.

Debtor-In-Possession.  During the pendency of the Chapter 11 Cases, we operated our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by us which were designed primarily to minimize the impact of the Chapter 11 Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business required the approval of the Bankruptcy Court.

Automatic Stay. Subject to certain exceptions, under the Bankruptcy Code, the filing of the bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against us or our property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order from the Bankruptcy Court, substantially all of our pre-petition liabilities were subject to settlement under the Bankruptcy Code.

Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Existing Credit Facility  (collectively, the “Lenders”) and certain holders of the Company’s Senior Notes (collectively, the “Noteholders”), the following transactions were completed subsequent to the Confirmation Date and prior to or at the Effective Date:

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In support of the Reorganization Plan, the Company estimated the enterprise value of the Successor to be in the range of $1.05 billion to $1.35 billion with a midpoint of $1.2 billion, which was subsequently approved by the Bankruptcy Court. In accordance with the Reorganization Plan, our post-emergence new board of directors is made up of seven directors including our Chief Executive Officer, K. Earl Reynolds, and six members (including the chairman of the New Board). Our new board members are Mr. Robert Heineman, Mr. Douglas Brooks, Mr. Kenneth Moore, Mr. Matthew Cabell, Mr. Samuel Langford and Mr. Gysle Shellum.

Financial and Operating Performance

In addition to the reorganization related transactions above, our financial and operating performance during 2016 includes the following highlights:

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2017 Outlook

The oil and gas industry is cyclical, and global crude oil prices are volatile due to three key drivers: OPEC crude oil supply, non-OPEC crude oil supply and global crude oil demand. The crude oil price downturn that began in the latter half of 2014 continues to persist today. During 2014, crude oil became oversupplied as production from non-OPEC producers increased, primarily driven by US production growth from tight formations and the de-bottlenecking of transportation infrastructure, while global crude oil demand growth was muted on sub-par global economic growth. This oversupply, coupled with OPEC’s decision not to reduce production quotas, resulted in crude oil futures prices falling rapidly in late 2014. During 2015, prices fell to multi-year lows and the lowest levels since the global 2008 financial crisis. Crude oil prices continued to trade in a lower range during most of 2016 as continued oversupply, and uncertainty surrounding potential OPEC quota reductions, prevented a recovery. In late 2016, OPEC reached an agreement for a limited, six-month production cut, and, in response, global crude oil prices began to rise. However, OPEC's agreement is contingent on the cooperation of non-OPEC countries, including Russia; therefore, the extent to which these plans will be carried out remains uncertain. Furthermore, U.S. shale producers have responded to the modest price recovery by an increase in drilling activity where production increases from a potential shale rebound would hamper the rebalancing of supply and demand. Increased drilling activity has also caused demand for oilfield services and materials such as drilling rigs, hydraulic fracturing, sand and chemicals to increase. The increased demand coupled with a tighter supply as many service providers have been forced out of business during the industry downturn will likely lead to higher prices from our vendors and may lead to increases in our drilling and completion costs and lease operating expenses.  

The outlook for 2017 crude oil prices will continue to depend on supply and demand dynamics and global geopolitical and security concerns in crude oil-producing nations. Global oil inventories and production levels will be primary determinants for 2017 as the global crude oil market remains substantially oversupplied. Recent data in March 2017 on surging U.S. crude inventories has resulted a reversal of the price gains that occurred in late 2016. Longer term, supply and demand is expected to continue to re-balance. Recent reductions in industry investment will, over time, reduce production, helping to balance supply and demand in the crude oil market.

The U.S. domestic natural gas market is also oversupplied due to production growth from shale formations. During 2015 and most of 2016, prices remained weak, falling to multi-year lows. In addition, location differentials increased in some regions, resulting in further realized price declines. For a time, domestic production continued to grow, due to drilling efficiency and a backlog of drilled but uncompleted wells in the Marcellus Shale that came online with completion of new pipeline infrastructure, thereby outstripping demand growth. While domestic prices rebounded in late 2016/early 2017, the price gains have recently been reversed with daily spot prices in generally in the $3.00/MMBtu range since February 2017. Although the pace of drilling has slowed, it is possible that there may not be more significant improvement in the domestic natural gas supply and demand balance and that oversupply will persist, which could lead to continued price softness in 2017. At a minimum, U.S. natural gas prices are expected to continue to trade in a low range for the near term.

While 2015 and 2016 were challenging as we navigated through the historic industry downturn, we believe our 2016 results reflects successful execution in a difficult environment. Coupled with our emergence from bankruptcy, which leaves us with a stronger and more sustainable capital structure, we believe that we are well positioned to tackle the opportunities and challenges ahead.

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Low Price Environment Initiatives

We have taken and continue to seek measures to significantly reduce our drilling, operating and support costs. These include reductions in force at both the field and corporate level. Our workforce reductions in 2015 and 2016 reduced employee headcount by 213 and 64 employees, respectively. Further streamlining of corporate functions have resulted in an additional reduction of 12 employees during the first quarter of 2017. See “Results of Operations” below for a discussion of severance costs associated with these layoffs. The reduced headcount has enabled us to generate savings in lease operating and general and administrative expenses. Our cost reduction initiatives also include a more judicious evaluation of underperforming wells as well as workovers and repairs on wells. Underperforming wells have been shut-in while repairs and workovers are only conducted when the expected payoff from the work exceeds a minimum threshold. We also continue to monitor our contracts and pricing with vendors and service providers to bring costs in line with current market conditions.

Price Uncertainty and the Full-Cost Ceiling Impairment

The current oil price environment is characterized by a high degree of volatility and uncertainty. For instance, based on the implied volatility in early March 2017 from WTI futures contracts for June 2017 delivery, the U.S. Energy Information Administration (“EIA”) estimates an implied volatility of 24%, suggesting lower and upper limits of the 95% confidence interval for the market's expectations of monthly average WTI prices in June 2017 at $43.70/Bbl and $67.73/Bbl, respectively. In an environment of continued price volatility, the current modest price improvement trend could stall, or the industry could enter another downturn causing additional material negative impacts on our revenues, profitability, cash flows, liquidity, and reserves, and we could consider further reductions in our capital program or dividends, asset sales or additional organizational changes.

We deal with volatility in commodity prices primarily by insuring our overall cost structure is competitive and supportive in a $40/bbl to $60/bbl oil price environment. In addition, we maintain flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility. We also deal with price volatility by hedging a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases.  We currently have derivative contracts in place for oil and natural gas production in 2017, 2018 and 2019 (see Item 7A. Quantitative and Qualitative Disclosures About Market Risk).

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Price volatility also impacts our business through the full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. As a result of the industry downturn, the average price utilized during the past three years has followed a pattern of decline. For example, the ceiling test price for crude oil fell from $94.99/Bbl at the end of 2014 to $50.28/Bbl at the end of 2015 and $42.75/Bbl at the end of 2016. Due to decreasing average prices, we recorded ceiling test write-downs of $281 million and $1.5 billion during 2016 and 2015, respectively. Since the prices used in the cost ceiling are based on a trailing 12-month period, the full impact of price changes on our financial statements is not recognized immediately but will be spread over several reporting periods. Prices rebounded in late 2016 as the market reacted to the November 30, 2016, OPEC agreement to cut production; however, some of the price gains have since reversed in March 2017 in response to data on surging U.S. crude inventories. Based on current NYMEX strip prices, we expect to see increases in the trailing 12-month average price of crude oil as we progress through 2017.

In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

As a result of our reorganization under Chapter 11 and subsequent emergence from bankruptcy on March 21, 2017, we will apply fresh start accounting to our balance sheet which results in the carrying value of our oil and natural gas properties being restated based on their fair value. We are still in the process of estimating the fair value. It is possible that our estimate of the fair value of our oil and natural gas properties utilized as the fresh start opening balance upon our emergence from bankruptcy could result in the carrying value exceeding the full cost ceiling limit at March 31, 2017, which would require us to record a ceiling test impairment.

Capital Program

Our oil and natural gas capital expenditures, of $149.4 million in 2016 were significantly lower compared to $209.3 million in 2015. The reduction in capital spending was a result of our adjustment to by historic lows in crude oil prices experienced in 2016 as well as liquidity constraints. Cash outlays for capital during the year were almost fully funded by internally generated cash flows from operations and receipts from our derivative settlements. We began 2016 with three rigs which was reduced to one rig in March 2016 that we deployed through the completion of our 2016 drilling program in June 2016. We resumed drilling in December 2016 and had three wells in progress at the end of the year. During 2016 we drilled and completed 11 wells in our STACK play and completed five wells that were spudded in the previous year. All our operated drilling and completion activity during 2016 was focused on wells in our STACK play. Our capital spending in 2016 was also deployed to expand our CO₂ floods in our North Burbank Unit, participate in attractive STACK non-operated wells and on selective leasehold acquisitions to protect and strengthen our position in the STACK.

Our capital budget for 2017 will be predominantly focused on profitable lower risk opportunities with the remaining portion dedicated to higher risk delineation drilling. Our profitable lower risk projects for 2017, which will account for 80% of our capital budget, will include drilling and completing 10 development wells in Kingfisher county within our STACK play, continuing CO₂ purchases within our Active EOR Areas to develop our North Burbank Unit and efficiently producing our other units experiencing production declines, and selectively participating in high-return STACK non-operated wells with established operators. Our riskier delineation drilling plans will include drilling wells around the northern and southern boundaries of our STACK acreage. By drilling nine wells in these areas, we hope to increase our technical understanding of our acreage which would allow us to effectively de-risk certain drilling locations and guide our future development plans. Our oil and natural gas capital budget for 2017 is $145.9 million which we plan to fund with a combination of cash flows from operations and proceeds from the sale of non-core assets from which we expect to generate $25 million to $30 million in proceeds.

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Results of Operations

Overview

Total production and commodity sales have decreased each year from 2014 to 2016 and is a reflection of the industry downturn we experienced. Commodity sales have decreased as a result of both price and production declines over the two year period with the price decline being predominant cause of the first year decline while both price and production having equal role in the second year decline. As discussed below, production declines are the result of our scaling back of capital spending due to low commodity pricing and liquidity constraints. As a result, production from new drills in 2015 to 2016 did not fully offset production decreases stemming from natural decline during that time period. In addition, production has also been impacted by certain cost reduction measures to shut-in uneconomic wells and postpone well repairs or workovers that do not yield an attractive returns. We recorded ceiling test impairments of $281 million and $1.5 billion in 2016 and 2015, respectively, which along with lower commodity sales, largely explains our net losses of $416 million and $1.3 billion over the last two years. We have been able to partially mitigate our losses by aggressively reducing operating costs including lease operating expense and general and administrative expenses. In addition, our operating results have benefited from a hedging program that has yielded $154 million and $234 million in settlement gains during 2016 and 2015, respectively.

 

Production

Production volumes by area were as follows (MBoe):

 

Production decreased in 2016 compared to 2015 due to production declines in all our areas outside the STACK. Areas outside the STACK experienced declining production to a decrease in development activity. Production in our STACK play increased as a result of the 16 additional wells that we completed in 2016 and our participation in new outside-operated wells in that play. We did not direct any significant capital to areas outside the STACK other than to expand a limited number of new patterns at our North Burbank Unit and for the purchase of CO₂ and maintenance within our Active EOR Areas. Increases in production at our North Burbank Unit as a result of ongoing investment partially mitigated the decreases experienced at our Booker, Camrick and Farnsworth units.  

Production decreased in 2015 compared to 2014 primarily due to a production decline in our Other Areas partially offset by higher production in our Active EOR Projects and STACK Areas.  The year-over-year decrease in our Other Areas is primarily due to strategic divestitures of our non-core properties in 2014, reduced drilling and development activity and the temporary shut-in of marginal wells due to the current pricing environment. Our strategic divestitures in 2014 included sales of properties in the Permian Basin, Ark-La-Tex, and North Texas areas. These decreases were offset partially by increased production in our Active EOR Projects due to production response in our North Burbank Unit and Farnsworth Unit and increased production in our STACK Areas due to our drilling and development activities.

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Revenues

The following table presents information about our commodity sales before the effects of commodity derivative settlements:

Commodity sales decreased from 2015 to 2016 due to both price and production declines on all three commodities. Production declines had a slightly larger role in causing the revenue decrease unlike the prior year. Production declines in oil and natural gas were most pronounced in our Other Areas. As discussed above, these decreases were due to a lack of capital spending in these plays as our capital activity in 2016 was focused on developing wells in our high-return STACK area.

Commodity sales decreased from 2014 to 2015 due to both price and production declines on all three commodities. The price decline in 2015, which was the predominant cause of our decreased sales, is a reflection of the severe ongoing downturn in the industry. Production declines in oil and natural gas were most pronounced in our Other Areas. As discussed above, these decreases were largely a result of asset divestitures, decreased development, shutting-in marginal wells and natural well declines.

The relative impact of changes in commodity prices and sales volumes on our commodity sales before the effects of hedging is shown in the following table:

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Derivative Activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, collars, put options, enhanced swaps and basis protection swaps.

We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices:

 

The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

 

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Non-hedge derivative (losses) gains” in the consolidated statements of operations. The fluctuation in non-hedge derivative (losses) gains from period to period is due primarily to the significant volatility of oil and natural gas prices and basis differentials and to changes in our outstanding derivative contracts during these periods. The effects of derivative activities on our results of operations and cash flows were as follows:

 

 

On March 26, 2015, we entered into early terminations of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 and covering 495 MBbls of oil and 12,280 BBtu of natural gas for net proceeds of $15.4 million in order to maintain compliance with the hedging limits imposed by covenants under our Existing Credit Facility.

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In May 2016 all of our outstanding derivative contracts were terminated early as a result of our defaults under the master agreements governing our derivative contracts. The derivative defaults were triggered by defaults on our debt. The early-terminated contracts, originally scheduled to settle from 2016 through 2018, covered 3,400 MBbls of oil and 28,800 BBtu of natural gas. Proceeds from the early terminations, inclusive of amounts receivable at the time of termination for previous settlements, totaled $119.3 million. Of this amount, in the third quarter of 2016, $103.6 million was utilized to offset outstanding borrowings under our Existing Credit Facility and the remainder was remitted to the Company. Realized gains (losses) from early terminations are reflected in “Settlement gains (losses)” in the table above.

Lease Operating Expenses 

 

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our EOR projects are more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of CO₂.

Lease operating expenses decreased from 2015 to 2016 primarily due to lower expense for our Other and Active EOR Areas partially offset by higher expense in our STACK Area. The decrease at our Other Areas was primarily due to decreases in production combined with a slight decrease attributable to divestiture of certain non-core assets. However, lease operating expenses for our Other Areas increased on a Boe basis from 2015 to 2016 primarily as the reduction in expense from lower production was proportionately smaller than the decrease in production. Lease operating expenses for our STACK Areas increased from 2015 to 2016 primarily due increased production in this area from new wells coming online in 2016 which led to additional costs of oil field goods and services. However, our lease operating expenses in the STACK decreased significantly on a Boe basis from 2015 to 2016 as economies of scale and improved efficiencies resulted in a smaller proportionate increase in lease operating expenses compared to the increase in production volume.  

Lease operating expenses decreased from 2014 to 2015 on an absolute dollar and on a Boe basis for all our operational areas. The decreases were due to cost reductions from third party service providers and improved operational efficiencies which included temporary shut-in of marginal wells due to the current low price environment. Lower production volumes and the divestiture of certain non-core assets with higher operating costs within our Other Areas also contributed to the decrease in total expense.  Lease operating expense was lower in our STACK area and Active EOR Areas despite a production increase as the proportionate cost savings from operational and scale efficiencies more than offset the increase in production volumes.

Transportation and Processing Expenses

Transportation and processing expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and processing costs of gas into natural gas liquids. Our transportation and processing expenses were approximately flat from 2014 to 2016.

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Production Taxes (which include ad valorem taxes)

Production taxes generally change in proportion to commodity sales. Some states offer exemptions or reduced production tax rates for horizontal drilling, enhanced recovery projects and high cost gas wells. Prior to July 1, 2015, new wells in Oklahoma previously qualified for a tax incentive and were taxed at a lower rate of 1% during their initial 48 months of production. As of July 1, 2015, the tax incentive rate for new wells has increased to 2% for the initial 36 months of production, although we have yet to see a substantial impact to date due to our reduced drilling activity. After the incentive period expires, the tax rate reverts to the statutory rate.

Production taxes from 2015 to 2016 were relatively flat. Increases in production taxes due to fewer production tax credits realized were more than offset by lower ad valorem taxes attributable to lower valuation of our oil and gas properties. The 2015 decrease in production taxes from 2014 was primarily due to the decline in revenues driven by depressed prices and lower production. Also contributing to the decline were our strategic divestitures in 2014 of non-core properties within our Other Areas, which generally had higher tax rates, and reduced tax rates for horizontal drilling and our EOR projects.

Depreciation, Depletion and Amortization (“DD&A”)

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and future costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties decreased from 2015 to 2016 of which $25.6 million was due to lower production and $67.3 million was due to a lower rate per equivalent unit of production. DD&A on oil and natural gas properties decreased from 2014 to 2015 of which $16.5 million was due to lower production and $10.6 million was due to a lower rate per equivalent unit of production. Our DD&A rate per equivalent unit of production decreased over the 2014 – 2016 period primarily as a result of the ceiling test write-offs that occurred in 2015 and 2016, which subsequently lowered the carrying value of our amortization base. Although the ceiling test impairment was larger in 2015 compared to 2016, its impact on DD&A via a lower DD&A rate was more pronounced in 2016 compared to 2015. This result arises because impairments are recorded after DD&A is assessed and therefore the full impact of our ceiling impairments in 2015 did not manifest in lower DD&A until the following year.  

We record the estimated future value of a liability for an asset retirement obligation in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.  

Asset Impairments

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Property impairments. Due to the substantial decline of commodity prices beginning in late 2014, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at various fiscal quarter-ends during the past two years resulting in ceiling test write-downs of $281 million and $1.5 billion recorded in 2016 and 2015, respectively. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date and these prices have demonstrated a declining trend as disclosed below:

The magnitude of our ceiling test write-down was impacted by two additional factors. The first were impairments of unevaluated non-producing leasehold, which resulted in a transfer of amounts from unevaluated oil and natural gas properties to the full cost amortization base. Impairments of non-producing leasehold of $55.1 million and $151.3 million were recorded in 2016 and 2015, respectively. The impairments in 2016 and 2015 were recorded as a result of changes in our drilling plans due to the low pricing environment and lower than expected results for certain exploratory activities which resulted in certain undeveloped properties not expected to be developed before lease expiration. The second factor, as it relates to our impairment in 2015, was a reclassification of $70.4 million for the construction of CO₂ delivery pipelines and facilities from unevaluated oil and natural gas properties to the full cost amortization base in 2015 in conjunction with our recognition of proved reserves from the future development of all remaining phases at our North Burbank Unit. Both factors combined to increase the carrying value of our full cost amortization base which in turn contributed to the ceiling test write-downs by the same amount.

Impairment of other assets. Our impairment loss for 2016 consists a $1.4 million market adjustment on our equipment inventory. Our impairment losses for 2015 consists of write-downs of $6.0 million related to impairments of our stacked drilling rigs and $10.2 million related to a market adjustment on our equipment inventory. As a result of the deterioration in commodity prices and reduced drilling activity, the value of our drilling rigs had declined while utilizing third party equipment has become more cost effective, resulting in us impairing the value of the rigs to their estimated fair value. These rigs were sold in January 2017. The industry conditions described above have also caused the demand for equipment utilized in drilling to decrease, resulting in lower market prices for such equipment. The market adjustments during 2016 and 2015 on our equipment inventory reflects the decrease in market prices as well as adjustments for excess and obsolescence.

General and Administrative expenses (“G&A”)  

Gross G&A expenses decreased from 2014 to 2015 and from 2015 to 2016, primarily due to lower compensation and benefits costs and lower costs for equity based compensation awards. Compensation and benefits were lower due to lower headcount subsequent to our workforce reductions that began in early 2015. Our reduction in workforce in 2016 and 2015 included 48 and 131 corporate employees, respectively. Compensation was also lower in 2016 compared to the prior year as we were not able to accrue annual bonuses for 2016 in conjunction with a provision that required separate Bankruptcy Court approval for any bonuses paid prior to our emergence. These bonuses, which totaled $6.3 million compared to $6.1 million in 2015, were paid on March 24, 2017 subsequent to our emergence from bankruptcy and will be recorded as an expense in 2017. Our gross equity based compensation costs decreased from $6.2 million in expense during 2014 to credits of $2.2 million and $6.2 million in 2015 and 2016 respectively. Expense for equity based awards decreased from 2014 to 2015 as a result of forfeitures and a decrease in the fair value of our liability awards due to depressed industry conditions. Expense for equity based awards decreased from 2015 to 2016 primarily as a result of a

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cumulative catch up adjustment of $6.0 million to reverse the aggregate compensation cost associated with certain equity awards that carried performance conditions. The catch-up adjustment was made to reflect a change in our expectations wherein it was no longer probable that requisite service would be achieved for these awards. Other than compensation and benefits, we had reductions across several other G&A categories in 2015 and 2016 in line with our initiatives to reduce costs in the current environment.  

Capitalized exploration and development costs decreased from 2014 to 2015 and from 2015 to 2016 due the overall decrease in G&A as well as a lower proportion of costs subject to capitalization as we have reduced our exploration, acquisition and development activities in this low commodity price environment.

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. These expenses include one-time severance and termination benefits in connection with our reductions in force as well as third party legal and professional services we have engaged to assist in these initiatives as follows (in thousands):

Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 petition, such expenses, to the extent that they are incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations.

Reorganization Items

Reorganization items reflect, where applicable, expenses, gains and losses incurred that are incremental and a direct result of the Chapter 11 reorganization of the business. We have incurred significant costs associated with the reorganization and we expect to incur an additional $27 million in bankruptcy related professional fees in 2017. Reorganization costs for 2016 are as follows (in thousands):

Other Income and Expenses

Interest expense. The following table presents interest expense for the periods indicated:

 

Total interest expense decreased from 2015 to 2016 as a result of lower interest expense on our Senior Notes as we ceased accruing interest upon the filing of our bankruptcy petition. This reduction in expense was partially offset by an increase in interest on our Existing Credit Facility due to increased levels of borrowing and higher interest rates as well as a reduction in capitalized interest. Total interest expense increased from 2014 to 2015 primarily due to increased levels of borrowing on our Existing Credit Facility and reduced capitalized interest. The reduction in capitalized interest from 2014 to 2015 and from 2015 to 2016 was a result of a lower carrying amount of unevaluated non-producing leasehold subsequent to the leasehold impairments recorded in 2015 and 2016.

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Gain on extinguishment of debt. During December 2015, we repurchased approximately $42.0 million of principal value of our outstanding Senior Notes on the open market for $10.0 million in cash. As a result, we recorded a $31.6 million gain on extinguishment of debt, which included retirement of unamortized issuance costs, discounts and premiums associated with the repurchased debt.

Senior Note issuance costs, discount and premium. In March 2016, we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes for a net charge of approximately $17.0 million. These deferred items are typically amortized over the life of the corresponding bond. However, as a result of not paying the interest due on our 2021 Senior Notes by the end of our 30-day grace period on March 31, 2016, we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively allowed the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount.

Income Taxes

 

Our federal net operating loss carryforwards were approximately $689.0 million as of December 31, 2016, which will expire between 2028 and 2036 if not utilized in earlier periods. As of December 31, 2016, our state net operating loss carryforwards were approximately $844.0 million, which will expire between 2017 and 2036 if not utilized in earlier periods.

Our effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year but are not consistent from year to year. At December 31, 2016, we have $574.3 million, or 100%, valuation allowance against our deferred tax assets that exceed deferred tax liabilities due to uncertainty regarding their realization. For the year ended December 31, 2016, we recorded approximately $163.2 million of our total valuation allowance. For further discussion of our valuation allowance, see “Note 10—Income taxes” in Item 8. Financial Statements and Supplementary Data in this report.

Our ability to utilize our loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “IRC”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, and Section 382 of the IRC imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards after an ownership change. We do not have a Section 382 limitation on our ability to utilize our loss carryforwards as of December 31, 2016. In 2017, however, upon emergence from bankruptcy, as described in “Note 2—Chapter 11 reorganization,” we experienced an ownership change that may limit the availability of our loss carryforwards to fully offset taxable income in future years.  For further discussion of the impact of our emergence from bankruptcy on the amount and availability of our loss carryforwards, see “Note 10—Income taxes” in Item 8. Financial Statements and Supplementary Data in this report. Future equity transactions involving us or our shareholders (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes, further limiting the availability of our loss carryforwards to reduce future taxable income.

Deferred income taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.  The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.

Valuation allowance on deferred tax assets. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. In making this assessment, we consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies, and projected future taxable income. If the ultimate realization of deferred tax assets is dependent upon future book income, assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative, as to whether it is more likely than not that a deferred tax assets will be realized.

Liquidity and Capital Resources

The severe and sustained decline in oil and natural gas prices since mid-2014 has negatively impacted revenues, earnings and cash flows, and our liquidity. In late 2015, declining cash flows from lower commodity prices and the prospect that prices would remain depressed made it difficult for us to sustain a cash interest burden in excess of $100 million annually on approximately $1.2

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billion in outstanding principal of our Senior Notes. In addition, due to lower commodity prices, we were also faced with a significant upcoming reduction in the borrowing base on our Existing Credit Facility in early 2016 which would have required us to repay a material portion of our outstanding borrowings at that time. The uncertainty regarding our ability to repay our outstanding debt obligations, especially in the event of any acceleration of indebtedness, indicated substantial doubt about our ability to continue as a going concern. This doubt was expressed in the audit opinion of our annual consolidated financial statements for the year ended December 31, 2015, and constituted an event of default under our Existing Credit Facility.

On March 1 and April 1, 2016, we elected not to make interest payments on our 8.25% Senior Notes and 9.875% Senior Notes, respectively. Upon the lapse of the respective 30-day grace periods to cure the nonpayment, we were subsequently in default on those Senior Notes. Our failure to make such interest payments within the 30-day grace period also resulted in a cross default under our Credit Facility, capital leases and mortgage note. These defaults resulted in cross defaults on our remaining indebtedness and therefore subjected all our debt to potential acceleration in the event that the outstanding amounts were called by our lenders.

Faced with these defaults, we entered into agreements (the “Forbearance Agreements”) with the lenders under our Existing Credit Facility and an ad hoc committee of noteholders collectively holding more than 50% of the Senior Notes outstanding to forbear from exercising remedies on account of the missed interest payments and certain other alleged defaults specified in the Forbearance Agreements through and including May 1, 2016. While the Forbearance Agreements were in effect, we continued to engage in good-faith arm’s-length negotiations regarding a potential restructuring of the Existing Credit Facility and the Senior Notes that would materially delever our balance sheet and allow us to retain sufficient liquidity to continue to operate our business going forward. In the course of these negotiations, we and our various creditor stakeholders exchanged and considered, with the assistance of their respective advisors, numerous restructuring proposals.

On May 9, 2016, we filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code.  The enforcement of any obligations under our pre-petition debt was automatically stayed as a result of the bankruptcy petition. During the pendency of our bankruptcy, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. On March 10, 2017, the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy. On the Effective Date, our obligations under the Senior Notes, including principal and accrued interest, were fully extinguished in exchange for equity in the successor company. In addition, our Existing Credit Facility, previously consisting solely of a senior secured revolving credit facility was restructured into a New Credit Facility consisting of a senior secured first-out revolving facility (“New Revolver”) and a senior secured second-out term loan (“New Term Loan”).

Our cash balance as of March 27, 2017, was approximately $33 million of which $13 million was restricted for the payment of debtor-related professional fees and convenience class claims pursuant to our Reorganization Plan. Our primary sources of internally generated cash are cash flows from operations and receipts from derivative settlements. Cash flows from operations is comprised of receipts from commodity sales and payments for lease operating expenses, general and administrative expenses, taxes and debt service. We rely on cash flows from operations to fund our capital program which includes exploration and development, leasehold and property acquisitions. Our industry requires that we continuously commit substantial investment to drill and develop our oil and natural gas properties such that production from new wells can offset the natural production decline from existing wells. During the past three years, cash flows from operations have been insufficient to fully fund our capital programs and instead, we have also relied on cash from derivative settlements, proceeds from asset dispositions and borrowings under our Existing Credit Facility. Our external sources of liquidity are not only comprised of outstanding debt but also private issuances of equity for which we have engaged in from time to time in the past.  

Our cash flows and liquidity are highly dependent on the prices we receive for oil, natural gas and NGLs. Prices we receive are determined by prevailing market conditions, regional and worldwide economic and geopolitical activity, supply versus demand, weather, seasonality and other factors that influence market conditions and often result in significant volatility in commodity prices. We are now in the third year of a low price environment that began in 2014 and these lower commodity prices have negatively impacted revenues, earnings, cash flows and liquidity. Low prices also adversely affect our liquidity through the impact on our borrowing base. Availability under our previous Existing Credit Facility and under our New Credit Facility is subject to a borrowing base based on the value of our oil and natural gas properties that collateralize the facilities. When commodity prices decline, the price deck approved by our lenders to determine our borrowing base decreases which leads to a reduction in our borrowing base and hence the available amount we can borrow.

We mitigate the impact of volatility in commodity prices, in part through the use of derivative instruments which help stabilize our cash flow. As a result of defaults triggered by our bankruptcy, all our outstanding derivatives were terminated in May 2016. Subsequent to the terminations, we were unable to actively enter into new hedging contracts for the remainder of the year until December 2016 where upon Bankruptcy Court approval we entered into new contracts covering production from 2017 to 2019.

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Our outstanding contracts as of March 21, 2017 based on strip prices that day were as follows:

 

Sources and Uses of Cash

Our net increase (decrease) in cash is summarized as follows:

 

Our operating cash flow is primarily influenced by the prices we receive for our oil, natural gas and NGL production and the quantity we produce. Our cash flows from operating activities are also impacted by changes in working capital.

Our cash flows from operations were higher in 2016 compared to 2015 primarily due to a reduction in cash interest paid. During 2016, we elected not to make interest payments on our Senior Notes that were due on March 1 and April 1, 2016, resulting in defaults on the Senior Notes.  Upon filing the Chapter 11 Cases, we suspended interest payments on the Senior Notes for the remainder of the bankruptcy. As a result, we did not pay any cash interest related to our Senior Notes in 2016 which led to a year over year decrease in cash interest paid of $90.6 million. The increase in operating cash flows due to our nonpayment of interest was offset by a decline in revenues due to lower prices and production. In addition, although we were able to generate cash savings by reducing recurring expenses such as lease operating and general and administrative expenses, these savings were more than offset by costs we incurred to restructure our debt and in connection with our bankruptcy.

Our cash flows from operating activities were lower in 2015 compared to 2014 due to the significant decrease in commodity sales driven primarily by lower prices on all our commodities and, to a lesser extent, by a decrease in production volumes sold. Cash flows from operations were also lower due to higher interest charges and expenses associated with our cost reduction initiatives. These reductions in cash flows were partially offset by lower lease operating, general and administrative and production tax expenses.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. During the past three years, cash flows from operations have been insufficient to fully fund our capital programs and instead, we have also relied on cash from derivative settlements, proceeds from asset dispositions and borrowings under our Existing Credit Facility. During 2016, cash used in investing activities was comprised of cash outflows for capital expenditure, which included paydown of accounts payable, of $146.3 million, partially offset by cash inflows from derivative settlements of $90.6 million and asset dispositions of $1.3 million. During 2015, cash used in investing activities was comprised of cash outflows for capital expenditure, which included paydown of accounts payable, of $313.5 million, partially offset by cash inflows from derivative settlements of $233.6 million and asset dispositions of $42.6 million. Our significant receipts from derivative settlements in 2015 were the result of a robust hedging program in response to the low prices that prevailed during 2015. Our paydown of accounts payable was a result of payments in the current year for capital expenditures accrued at the end of the prior year. During 2014, cash flows used in investing activities included capital expenditures of $685.5 million offset by proceeds of $291.4 million primarily from the sale of non-core properties. During 2014, we also paid $20.6 million in premiums for put options associated with our crude oil commodity derivatives settling in 2016.

Cash flows from financing activities in 2016 included borrowing and repayments on our long-term debt of $181.0 million and $1.9 million, respectively, and payment of $2.5 million on our capital leases. During 2016, the outstanding balance on our Existing Credit Facility was reduced by $103.6 million by directly offsetting proceeds payable to us from the termination of our derivative contracts against outstanding borrowings under the Existing Credit Facility. The ability to offset was possible as the previous counterparties to our derivative contracts were also lenders under our Existing Credit Facility. Since cash was not exchanged in this transaction, it is not reflected in the statement of cash flows. Cash flows from financing activities in 2015 included borrowing and repayments on our long-term debt of $120.0 million and $103.0 million, respectively, and payment of $2.4 million on our capital leases. We also paid $1.4 million in bank fees in connection with the amendment to our Existing Credit Facility as well as $10.0

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million to repurchase our Senior Notes on the open market, both which are discussed below. In 2014, we had proceeds from and repayments of debt of $302.1 million and $228.6 million, respectively, most of which were attributable to our Existing Credit Facility. In addition, principal payments under our capital lease obligations were $2.3 million during 2014.

Asset sales. During 2014, a significant source of liquidity was derived from asset dispositions which included various oil and natural gas properties primarily located in our Ark-La-Tex, Permian Basin, and North Texas areas. Our asset sales in 2014 generated a total of $291.4 million in cash. Our capital expenditures for 2015 were funded, in part, by approximately $42.6 million of proceeds generated from asset divestitures. Although we did not have significant divestitures in 2016, our 2017 budget contemplates asset sales that we expect could yield between $25 million to $30 million in proceeds. Proceeds from our property sales provide us with an additional source of liquidity to pay down borrowings under our Credit Facility, fund capital expenditures and for general corporate purposes.

Capital Expenditures

Our actual costs incurred, including costs that we have accrued, for 2016 and our budgeted 2017 capital expenditures for oil and natural gas properties are summarized in the following table:

 

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $0.8 million for property and equipment during 2016.

We utilized our 2016 capital to, among other things, drill and complete 11 wells, complete five wells drilled in 2015, expand our CO₂ floods in our North Burbank Unit and on selective leasehold acquisitions to strengthen our position in the STACK. All our operated drilling and completion activity during 2016 was focused solely on wells in our STACK play. The majority of our capital budget for 2017 will be focused on profitable lower risk opportunities with the remaining portion dedicated to higher risk delineation drilling. Our profitable lower risk projects for 2017 will include drilling and completing 10 development wells in Kingfisher county within our STACK play, continuing CO₂ purchases within our Active EOR Areas to develop our North Burbank Unit and efficiently producing our other units experiencing production declines, and selective participation in high-return STACK non-operated wells with established operators. Our riskier delineation drilling plans will include drilling nine exploratory wells around the northern and southern boundaries of our STACK acreage. We plan to fund capital budget for 2017 with a combination of cash flows from operations and proceeds from the sale of non-core assets.

We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2017 may be higher or lower than our budgeted amounts. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors. We will continue to monitor our capital spending in 2017 closely and may adjust our spending accordingly based on actual and projected cash flows, our liquidity and our capital requirements.

Pre-emergence Indebtedness

Chapter 11 Proceedings and Emergence. The bankruptcy petition constituted an event of default with respect to our pre-petition Existing Credit Facility and Senior Notes. Prior to the petition date, these facilities were also in default as a result of nonpayment of interest, violations of financial covenants and the inclusion of a going concern explanatory paragraph in the audit opinion of our 2015 annual financial statements. The enforcement of any obligations under our pre-petition debt was automatically stayed as a result of the Chapter 11 Cases. On the Effective Date, our obligations under the Senior Notes, including principal and accrued interest, were fully extinguished in exchange for equity in the post-emergence Company. In addition, our Existing Credit Facility, previously consisting of

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a senior secured revolving credit facility, was restructured into a New Credit Facility consisting of the New Revolver and the New Term Loan.

Reclassification of Debt. The balances outstanding under our Senior Notes were classified as liabilities subject to compromise at December 31, 2016. The outstanding balances under our Existing Credit Facility, real estate mortgage notes, installment notes and capital leases were not classified as subject to compromise at December 31, 2016, as these obligations were secured. Furthermore, as a result of certain debt defaults discussed above, which occurred in early 2016 and remained uncured during the pendency of the Chapter 11 Cases, all outstanding long-term debt was classified as current as of December 31, 2015 and 2016.

Our debt consists of the following as of the dates indicated:

__________________________________

Senior Notes. The Senior Notes, as of December 31, 2016, were our senior unsecured obligations and ranked equally in right of payment with all of our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The Senior Notes were redeemable, in whole or in part, prior to their maturity at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption. Interest on the Senior Notes were payable semi-annually, and the principal was due upon maturity

Existing Credit Facility. In April 2010, we entered into the Eighth Restated Credit Agreement (the ‘Existing Credit Facility”), which is collateralized by our oil and natural gas properties and, as amended, was originally scheduled to mature on November 1, 2017. Availability under our Existing Credit Facility was subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually. The initial borrowing base on our Existing Credit Facility for 2016 was $550.0 million, however subsequent to the defaults on this facility in March 2016, we no longer had availability under the facility until our debt was restructured upon exiting bankruptcy. Amounts borrowed under our Existing Credit Facility were subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elected to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). Our Existing Credit Facility, as amended, also had certain negative and affirmative covenants that required, among other things, maintaining a Current Ratio, a Consolidated Net Secured Debt to Consolidated EBITDAX ratio and an Interest Coverage Ratio (all ratios as defined in the amendment). Subsequent to our debt defaults in March 2016 and through the pendency of our Chapter 11 Cases, we ceased quarterly reporting of our covenant compliance, which included these ratios, to the administrative agent of the facility.

Post-emergence indebtedness

As discussed above, our post-emergence exit financing consists of the New Credit Facility, which is comprised of the New Revolver and the New Term Loan, entered into on the Effective Date. The initial outstanding amounts under the New Credit Facility were (in thousands):

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New Term Loan. The loan, which is collateralized by our oil and natural gas properties, is scheduled to mature on March 21, 2021. Interest on the outstanding amount of the New Term Loan will accrue at an interest rate equal to either: (a) the Alternate Base

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Rate (as defined in the New Credit Facility) plus a 6.75% margin or (b) the Adjusted LIBO Rate (as defined in the New Credit Facility), plus a 7.75% margin with a 1.00% floor on the Adjusted LIBO Rate.

We are required to make scheduled, mandatory principal payments in respect of the New Term Loan according to the schedule below, with the remaining outstanding balance due upon maturity (in thousands):

New Revolver. The New Revolver is a $400.0 million facility collateralized by our oil and natural gas properties and is scheduled to mature on March 21, 2021. Availability under our New Revolver is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on the Effective Date was $225.0 million and the first borrowing base redetermination has been set for on or about May 1, 2018.

Interest on the outstanding amounts under the New Revolver will accrue at an interest rate equal to either (i) the Alternative Base Rate plus a margin that ranges between 2.00% to 3.00% depending on utilization or (ii) the Adjusted LIBO Rate applicable to one, two three or six month borrowings plus a margin that ranges between 3.00% to 4.00% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the applicable rate while in default will be the Alternative Base Rate plus an additional 2.00% and plus the applicable margin.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the margin used to determine the interest rate applicable to New Revolver borrowings that are based on Adjusted LIBO Rate.

If the outstanding borrowings under our New Revolver were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 45 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency.

The New Credit Facility contain covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our New Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others. The financial covenants require, for each fiscal quarter ending on and after March 31, 2017, that we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, (2) an Asset Coverage Ratio (as defined in the New Credit Facility) of no less than 1.35 to 1.00, (3) Liquidity (as defined in the New Credit Facility) of at least $25.0 million and (4) a Ratio Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 3.5 to 1.0 calculated on a trailing four-quarter basis.

Please see “Note 6—Debt” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of the other provisions governing our New Credit Facility

Capital leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The lease financing obligations are for 84 -month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are $3.2 million annually.

Liquidity outlook

As of March 27, we had $33 million in cash and $104 million in availability under our New Revolver. Upon consummation of the Reorganization Plan, our capital structure has been significantly improved as it is no longer burdened by $1.2 billion of previous

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Senior Note debt and the associated interest obligation, which previously averaged approximately $107 million each year. Our New Credit Facility is now partially composed of a term loan (the New Term Loan) rather than being entirely borrowing base driven and therefore is less susceptible to swings in commodity prices and provides us with stability in regards to credit availability. We believe our current liquidity level and balance sheet provide flexibility and that we are well-positioned to fund our business throughout the commodity price cycle. Although we will continue to evaluate the commodity price environment and our level of capital spending throughout 2017, we currently believe that we are able to meet our obligations and fund our drilling plans for the next 12 months.

Financial position

The following were material changes in our balance sheet:

 

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Contractual obligations

Absent any acceleration of our debt resulting from defaults or conversion to equity as a result of our Chapter 11 reorganization, the following table summarizes our contractual obligations and commitments as of December 31, 2016:

 

_______________________________

The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations.

We have three long-term contracts with three different suppliers to purchase CO_2. Only one of the contracts, the contract with the plant in Coffeyville, Kansas, includes a commitment to purchase a minimum amount of CO₂ over the term of the contract. The resulting commitment is reflected in the contractual obligations and commitments table, above. Additional details regarding the three long-term contracts are discussed, below.

We purchase CO₂ manufactured at the Arkalon ethanol plant near Liberal, Kansas under a fixed-price contract that expires in May 2024 but provides the option for renewal.  During 2016, we purchased approximately 8 MMcf/d of CO₂ under this contract, and we expect to purchase an average of approximately 13.5 MMcf/d in 2017. Purchases under this contract were $0.8 million, $1.1 million, and $1.3 million during 2016, 2015, and 2014, respectively.

We have rights under two additional contracts with fertilizer plants under which we purchase CO₂ that is restricted, in whole or in part, for use only in EOR projects. The fertilizer plants retain the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce the CO₂ available to us. Pricing under both of these contracts is dependent on certain variable factors, including the price of oil.

The first contract, with the plant in Borger, Texas, expires in February 2021. However, the plant is currently undergoing a modification which may reduce available CO₂ volumes to below the minimum threshold required to operate our compression facility. We are in the process of assessing the future availability of CO₂ from this source as a result of the plant modification. During 2016, we purchased an average of approximately 5 MMcf/d of CO₂ and expect our purchases to average approximately 0.5 MMcf/d in 2017. Purchases under this contract were $0.2 million, $0.4 million, and $1.1 million during 2016, 2015, and 2014, respectively.

The second contract, with the plant in Coffeyville, Kansas, expires in 2033 but provides an option for renewal. Pricing under the contract is fixed for the first five years and variable thereafter. We are obligated to purchase approximately 35 MMcf/d for the remaining contract years or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our required purchase rate with six months’ notice. During 2016, we purchased 28 MMcf/d of CO₂ from this source and expect to purchase 28 MMcf/d in 2017. Purchases under this contract totaled $1.0 million, $1.0 million, and $1.4 million during 2016, 2015, and 2014, respectively.

We rent equipment used on our oil and natural gas properties and have operating lease agreements for office equipment. Rent expense for the years ended December 31, 2016, 2015, and 2014 was $6.7 million, $8.8 million, and $11.1 million, respectively. Our operating leases include leases relating to office equipment, which have terms of up to five years, and leases on CO₂ recycle compressors, which have terms of seven years, at our EOR facilities. Amounts related to our operating lease obligations are disclosed in the table above.

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Other commitments consist of contracts in place as of December 31, 2016, that are not currently recorded on our consolidated balance sheets. The $14.2 million of other commitments primarily consist of fees due to financial advisors in connection with work performed on our bankruptcy and capital restructuring. Commitments for drilling rig services and information technology services make up the remainder.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and other sources that we believe are reasonable at the time. Actual results may differ from the estimates and assumptions we used in preparation of our financial statements. We evaluate our estimates and assumptions on a regular basis. Described below are the most significant policies and the related estimates and assumptions we apply in the preparation of our financial statements. See “Note 1—Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data in this report for an additional discussion of accounting policies and estimates made by management.

 

Bankruptcy Proceedings. We have applied Accounting Standards Codification 852 “Reorganizations” (“ASC 852”) in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization items, net” in the accompanying Consolidated Statements of Operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our consolidated balance sheets at December 31, 2016 in "Liabilities subject to compromise". These liabilities are reported at the amounts we anticipate will be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. See “Note 2—Chapter 11 Reorganization” in Item 8. Financial Statements and Supplementary Data of this report for more information.

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received.

Derivative instruments. We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and natural gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2. We determine fair value for our collars, enhanced swaps, and put options using an option pricing model which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for these instruments, we have determined that their fair value measurements are categorized as Level 3. Derivative instruments are discounted using a rate that captures our nonperformance risk for derivative liabilities or that of our counterparties for derivative assets. Our derivative contracts have been executed with institutions that are parties to our Existing Credit Facility as well as our New Credit Facility. We believe the credit risks associated with all of these institutions are acceptable.

From time to time, we may enter into derivative contracts which require payment of a premium. The premium can be paid at the time the contracts are initiated or deferred until the contracts settle. The fair value of our derivatives contracts are reported net of any deferred premium that are payable under the contracts.

Since we have elected to not designate any of our derivative contracts as hedges, we mark our contracts to their period end market values and the change in the fair value of the contracts is included in “Non-hedge derivative (losses) gains” in our consolidated statements of operations. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.

Oil and natural gas properties.

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Our proved reserve information included in this report is based on estimates prepared by Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 100% of the estimated future net revenues of our proved reserves as of December 31, 2016. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

We record a liability for the estimated fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. Significant assumptions used in estimating such obligations include estimates of the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments, all of which are Level 3 inputs in the fair value hierarchy. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.

Income taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.  The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.

Valuation allowance on deferred tax assets. In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. In making this assessment, we consider the scheduled reversal of deferred tax liabilities, available taxes in carryback  periods, tax planning strategies,

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and projected future taxable income. If the ultimate realization of deferred tax assets is dependent upon future book income, assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative, as to whether it is more likely than not that a deferred tax assets will be realized.

Impairment of long-lived assets. Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.

Recent Accounting Pronouncements

See “Note 1—Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of recently adopted and issued accounting standards. Additionally, we are monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and International Accounting Standards Board.

Effects of inflation and pricing

While the general level of inflation affects certain of our costs, factors unique to the oil and natural gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us.  

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity prices 

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration, and development activities. Based on our production for the year ended December 31, 2016, our gross revenues from commodity sales would change approximately $6.3 million for each $1.00 change in oil and NGL prices and $1.6 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, which in the past has included commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative (losses) gains in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Please see “Note 7—Derivative instruments” in Item 8. Financial Statements and Supplementary Data of this report for further discussion of our derivative instruments.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those reviewed when deciding to enter into the original derivative position.

The fair value of our outstanding derivative instruments at December 31, 2016, was a net liability of $13.4 million. Based on our outstanding derivative instruments as of December 31, 2016, summarized below, a 10% increase in the December 31, 2016, forward curves used to mark-to-market our derivative instruments would have increased our net liability position to $56.6 million, while a 10% decrease would have put us in a net asset position of $29.8 million.

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Our outstanding oil derivative instruments as of December 31, 2016, are summarized below:

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Our outstanding natural gas derivative instruments as of December 31, 2016, are summarized below:

 

During January 2017, we entered into additional oil and natural gas swap contracts. The following table summarizes the additional contracts:

 

Interest rates 

All of the outstanding borrowings under our Existing Credit Facility as of December 31, 2016 are subject to market rates of interest as determined from time to time by the banks. As of December 31, 2016, borrowings bear interest at the Alternate Base Rate, as defined under the Existing Credit Facility, which resulted in a weighted average interest rate of 5.25% on the outstanding amount. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level under our Existing Credit Facility of $444.4 million, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $4.4 million.

 

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to financial statements  

 

 

 

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Report of independent registered public accounting firm

Board of Directors and Shareholders

Chaparral Energy, Inc.

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. (a Delaware corporation) and subsidiaries (Debtor in possession) (the “Company”) as of December 31, 2016 and 2015 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chaparral Energy, Inc. and subsidiaries (Debtor in possession) as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, the Company adopted new accounting guidance in 2016 related to the presentation of deferred income taxes, and adopted new accounting guidance in 2016 and 2015 related to the presentation of debt issuance costs.

As discussed in Note 2 to the consolidated financial statements, on May 9, 2016 the Company filed voluntary petitions seeking relief under Chapter 11 of the U.S. Bankruptcy Code. The Company’s plan of reorganization was confirmed on March 10, 2017 and the Company emerged from bankruptcy on March 21, 2017.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

March 31, 2017

 

 

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Chaparral Energy, Inc. and subsidiaries

(Debtor in possession)

Consolidated balance sheets

 

The accompanying notes are an integral part of these consolidated financial statements.

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Chaparral Energy, Inc. and subsidiaries

(Debtor in possession)

Consolidated balance sheets—continued

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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Chaparral Energy, Inc. and subsidiaries

(Debtor in possession)

Consolidated statements of operations

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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Chaparral Energy, Inc. and subsidiaries

(Debtor in possession)

Consolidated statements of stockholders’ equity (deficit)

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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Chaparral Energy, Inc. and subsidiaries

(Debtor in possession)

Consolidated statements of cash flows

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Note 1: Nature of operations and summary of significant accounting policies

Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Our properties are located primarily in Oklahoma and Texas. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to March 21, 2017. As discussed in “Note 2—Chapter 11 reorganization” we filed voluntary petitions for bankruptcy relief and subsequently operated as debtor in possession, in accordance with the applicable provisions of the Bankruptcy Code, until emergence on March 21, 2017.

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Principles of consolidation

The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring use of assumptions, judgments and estimates on our consolidated financial statements include: quantities of proved oil and natural gas reserves; cash flow estimates used in impairment tests of other long-lived assets; depreciation, depletion and amortization; asset retirement obligations; estimates of our stock-based compensation awards, assigning fair value and allocating purchase price in connection with business combinations; forecasting our effective income tax rate and valuation allowances associated with deferred income taxes; valuation of derivative instruments; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could significantly differ from these estimates.

Reclassifications

Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2016, cash with a recorded balance totaling $36,502 and $48,023 was held at JP Morgan Chase Bank, N.A. and Arvest Bank, respectively. In addition, we also held cash equivalents in the form of treasury securities with a recorded balance of $101,127 at Arvest Wealth Management. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

We have restricted cash of $1,400 which is included in “Cash and cash equivalents” in our consolidated balance sheets. The restricted funds were maintained as a requirement during the pendency of our bankruptcy and were no longer restricted after emergence from bankruptcy.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We establish our allowance for doubtful accounts by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and our assessment of the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery. Accounts receivable consisted of the following at December 31:

 

 

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. We evaluate our inventory each quarter and when there is evidence that the utility of our inventory, in their disposal in the ordinary course of business, will be less than cost, whether due to physical deterioration, obsolescence, changes in price levels, or other causes, we record an impairment loss for the difference. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories consisted of the following at December 31:

 

We recorded lower of cost or market adjustments, for the periods disclosed below, due to depressed industry conditions which resulted in lower demand for such equipment and hence lower market prices. These adjustments are reflected in “Loss on impairment of other assets” in our consolidated statements of operations.

 

Property and equipment

Property and equipment is capitalized and stated at cost, while maintenance and repairs are expensed currently.

Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives of our assets are as follows:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Oil and natural gas properties

Capitalized Costs. We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, and other internal costs directly attributable to these activities.

The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work-in-progress costs are included in unevaluated oil and natural gas properties. See “Note 15—Oil and natural gas activities” for further details of our unevaluated oil and natural gas properties.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.

Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of December 31, 2016, 2015, and 2014 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC.

Due to the substantial decline of commodity prices that began in mid-2014 and which continue to remain low, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at the end of each quarter beginning with the second quarter of 2015 through the second quarter of 2016, resulting in ceiling test write-downs in those periods. The amount of any future impairment is generally difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.

We recorded impairment losses of $6,015 related to four drilling rigs during the year ended December 31, 2015. The loss was recorded as a result of the deterioration in commodity prices and drilling activity whereby the value of such equipment had declined while utilizing third party equipment had become more cost effective. The loss is reflected in “Loss on impairment of other assets” in our consolidated statements of operations.

In October 2016, the Company entered into an agreement for the sale of our four drilling rigs for a price of $2,000. The sale closed in January 2017.

Our bankruptcy filing on May 9, 2016, (see “Note 2—Chapter 11 reorganization”) was an event that required an assessment whether the carrying amounts of our long-lived assets would be recoverable. Our evaluation indicated that no additional impairment was necessary as a direct result of the bankruptcy.

Income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

realized. See “Note 10—Income taxes” for further discussion of our income taxes including the expected impacts of our emergence from Chapter 11 bankruptcy proceedings on the amount and availability of our loss carryforwards to offset future taxable income.

If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2016 and 2015, we have no uncertain tax positions and as such have not recorded a liability or accrued interest or penalties related to uncertain tax positions.

We file income tax returns in the U.S. federal jurisdiction and in various states, each with varying statutes of limitations. The 2009 through 2016 tax years generally remain subject to examination by federal and state tax authorities.

Derivative transactions

We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. The Company’s derivative instruments are not designated as hedges for accounting purposes, thus changes in the fair value of derivatives are reported immediately in “Non-hedge derivative (losses) gains” in the consolidated statements of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the consolidated statements of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.

We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See “Note 7—Derivative instruments” for additional information regarding our derivative transactions.  

Fair value measurements

Fair value is defined by the Financial Accounting Standards Board (“FASB”) as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Assets and liabilities recorded at fair value in the consolidated balance sheets are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and our drilling rigs, which were sold subsequent to December 31, 2016. See “Note 8—Fair value measurements” for additional information regarding our fair value measurements.

Asset retirement obligations

We own oil and natural gas properties that require expenditures to plug, abandon or remediate wells and to remove tangible equipment and facilities at the end of oil and natural gas production operations in accordance with applicable federal and state laws. We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in “Depreciation, depletion and amortization” in our consolidated statements of operations. In certain instances, we are required to make deposits to escrow accounts for plugging and abandonment obligations. See “Note 9—Asset retirement obligations” for additional information regarding our asset retirement obligations.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Environmental liabilities

We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2016 and 2015, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.

Revenue recognition

Sales of oil, natural gas and NGLs are recorded when title of production passes to the customer. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products are recognized at the time of delivery of materials.

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its ratable portion of the natural gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their ratable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2016 and, 2015 our aggregate imbalance due to under production was approximately 0 MMcf and 0 MMcf, respectively. As of December 31, 2016 and 2015, our aggregate imbalance due to over production was approximately 1,218 MMcf and 1,253 MMcf, respectively, and a liability for gas imbalances of $1,405 and $1,303, respectively, was included in accounts payable and accrued liabilities.

Stock-based compensation

Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan. We consider the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy.

The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.

The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, stock-based compensation expense could have been significantly impacted if other assumptions had been used.

The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.

See “Note 11—Deferred compensation” for additional information relating to stock-based compensation.

Liability management

Liability management expense includes third party legal and professional service fees incurred from our activities to restructure our debt and in preparation for our bankruptcy petition. As a result of our Chapter 11 petition, such expenses, to the extent that they are incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations.

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to depressed commodity pricing environment. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows:

 

 

Recently adopted accounting pronouncements

Other Expenses. In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations.

In August 2014, the FASB issued authoritative guidance that required entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and required additional disclosures if certain criteria was met. The guidance was adopted on December 31, 2016 and other than discussions regarding our emergence from bankruptcy and the related exit financing in “Note 2 — Chapter 11 reorganization” and “Note 6—Debt”, there were no additional required disclosures as contemplated by this guidance.

In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment required debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. The guidance was adopted on January 1, 2016, and resulted in us reclassifying our unamortized Senior Note issuance costs of $18,359 as of December 31, 2015, from “Other assets” to a reduction of long-term debt on the consolidated balance sheets. The initial guidance released in April 2015 did not address presentation or subsequent measurement related to line-of-credit arrangements. In August 2015, the FASB issued guidance that clarified the issue by allowing an entity to make an election to defer and present debt issuance costs as an asset and subsequently

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance was adopted on January 1, 2016, in conjunction with the adoption of the initial guidance. We made an accounting policy election to present line-of-credit arrangement debt issuance costs as a deduction from the carrying amount of our line-of-credit arrangement. As a result of this election, we reclassified our unamortized Existing Credit Facility issuance costs as of December 31, 2016 and 2015, respectively, of $2,303 and $5,067 from “Other assets” to a reduction of long-term debt on the consolidated balance sheets.

In November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. To simplify presentation, the new guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. Importantly, the guidance does not change the existing requirement that only permits offsetting within a jurisdiction – that is, companies are still prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. This guidance was early adopted on a prospective basis during the second quarter of 2016 and allowed us to offset our noncurrent deferred income tax asset with our current deferred income tax liability. Prior periods were not retrospectively adjusted. Other than the preceding balance sheet change, the adoption did not have a material impact on our financial statements and results of operations.

Recently issued accounting pronouncements

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The updated guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The new standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. During 2015 and 2016, the FASB released further updates that, among others, provided supplemental guidance and clarification to this topic including clarification on principal vs. agent considerations and identifying performance obligations and licensing. We are currently evaluating the effect the new standard and its subsequent updates will have on our financial statements and results of operations. In 2017, we established an implementation team (“team”) and engaged external advisers to develop a multi-phase plan to assess our business and contracts, as well as any changes to processes to adopt the requirements of the new standard and its related updates.

In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. We do not expect this guidance to materially impact our financial statements or results of operations.

In February 2016, the FASB issued authoritative guidance significantly amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. Furthermore, all leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2018 and interim periods thereafter, and should be applied using a modified retrospective approach. Early adoption is permitted. Based on an assessment of our current operating leases, which are predominantly comprised of leases for CO₂ compressors, we do not expect this guidance to materially impact our balance sheet or results of operations. However, we also enter into contractual arrangements relating to rights of ways or surface use that are typical of upstream oil and gas operations. We are currently assessing whether such arrangements are included in the new guidance and the potential impact, if any, on our financial statements or results of operations from these arrangements.

In March 2016, the FASB issued authoritative guidance with the objective to simplify several aspects of the accounting for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter. Early adoption is permitted. We do not expect this guidance to materially impact our financial statements or results of operations in connection with our outstanding awards.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in ASC 815. The guidance is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted in any interim period for which financial statements have not been issued, but would be retroactively applied to the beginning of the year that includes the interim period. We do not expect this guidance to materially impact our financial statements or results of operations.

In June 2016, the FASB issued authoritative guidance which modifies the measurement of expected credit losses of certain financial instruments. The guidance is effective for fiscal years beginning after December 15, 2020, however early adoption is permitted for fiscal years beginning after December 15, 2018. The updated guidance impacts our financial statements primarily due to its effect on our accounts receivables. Our history of accounts receivable credit losses almost entirely relates to receivables from joint interest owners in our operated oil and natural gas wells. Based on this history and on mitigating actions we are permitted to take    such as netting past due amounts against revenue and assuming title to the working interest,  we do not expect this guidance to materially impact our financial statements or results of operations.

In August 2016, the FASB issued authoritative guidance which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. Early adoption is permitted. We do not expect this guidance to have a material impact on our consolidated statement of cash flows.

Note 2: Chapter 11 Reorganization

Bankruptcy petition and emergence. On May 9, 2016 (the “Petition Date”), Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2 , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C. (collectively, the “Chapter 11 Subsidiaries” and, together with Chaparral Energy, Inc., the “Debtors”) filed voluntary petitions seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”).

On March 10, 2017 (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy.

Debtor-In-Possession.  During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by us which were designed primarily to minimize the impact of the Chapter 11 Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business required the approval of the Bankruptcy Court.

Automatic Stay. Subject to certain exceptions, under the Bankruptcy Code, the filing of the bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against us or our property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order from the Bankruptcy Court, substantially all of our pre-petition liabilities were subject to settlement under the Bankruptcy Code.

Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Existing Credit Facility (collectively, the “Lenders”) and certain holders of our Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date:

82

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

In support of the Reorganization Plan, the Company estimated the enterprise value of the Successor to be in the range of $1,050,000 to $1,350,000 with a midpoint of $1,200,000, which was subsequently approved by the Bankruptcy Court. In accordance with the Reorganization Plan, our post-emergence new board of directors is made up of seven directors consisting of the Chief Executive Officer of the post-emergence Company (K. Earl Reynolds) and six members (including the chairman of the New Board). Our new board members are Mr. Robert Heineman, Mr. Douglas Brooks, Mr. Kenneth Moore, Mr. Matthew Cabell, Mr. Samuel Langford and Mr. Gysle Shellum

83

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Liabilities Subject to Compromise. In accordance with ASC 852 “Reorganizations,” our financial statements include amounts classified as liabilities subject to compromise which represent estimates of pre-petition obligations that were allowed as claims in our bankruptcy case. These liabilities are reported at the amounts allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise may be subject to future adjustments depending on the Bankruptcy Court actions, further development with respect to disputed claims, and other events:

 

Reorganization Items. We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred significant costs associated with the reorganization. Reorganization items for the year ended December 31, 2016, are as follows:

 

Fresh Start Accounting. In connection with our emergence from bankruptcy, we will be required to apply fresh start accounting to our financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Reorganization Plan was less than the post-petition liabilities and allowed claims. Fresh start accounting will be applied to our consolidated financial statements as of the Effective Date. Under the principles of fresh start accounting, a new reporting entity was considered to be created, and, as a result, we will allocate the reorganization value of the Company to its individual assets based on their estimated fair values. The process of estimating the fair value of the Company’s assets, liabilities and equity upon emergence is currently ongoing and, therefore, such amounts have not yet been finalized. In support of the Reorganization Plan, the enterprise value of the post emergence Company was estimated and approved by the Bankruptcy Court to be in the range of $1,050,000 to $1,350,000 with a midpoint of $1,200,000.

 

Note 3: Supplemental disclosures to the consolidated statements of cash flows  

Supplemental disclosures to the consolidated statements of cash flows are presented below:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Note 4: Acquisitions and divestitures

2016 Divestitures

During 2016, we did not have any significant divestitures of our oil and natural gas properties.

2015 Divestitures

During 2015, we sold various non-core oil and gas properties for total proceeds of $36,654. The properties sold include acreage in various counties in South-Central Oklahoma in the SCOOP play (“South-Central Oklahoma Oil Province”) and oil and gas properties in Osage County.

As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

2014 Divestitures

During 2014, we closed on the sales of four of the five property packages that comprise our plan to divest our assets in Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $23,702  and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $124,717. In July 2014, we sold our Ark-La-Tex and Central Basin Platform property packages to RAM Energy, LLC (“RAM”) for cash proceeds of $49,078 and $46,830, respectively. Proceeds from these property packages are net of post-closing adjustments. As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

In addition to the packages discussed above, we had various other divestitures during the year ended December 31, 2014. These divestitures resulted in cash proceeds of $20,007 from the sale of leasehold interests in the Eagle Ford Formation in Texas and $24,478  from the sale of various other properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.

 

Note 5: Property and equipment

Major classes of property and equipment consist of the following at December 31:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Note 6: Debt

Chapter 11 Proceedings and Emergence

The bankruptcy petition constituted an event of default with respect to the Company’s pre-petition Existing Credit Facility and Senior Notes. Prior to the petition date, these facilities were also in default as a result of nonpayment of interest, violations of financial covenants and the inclusion of a going concern explanatory paragraph in the audit opinion of our 2015 annual financial statements. The enforcement of any obligations under the Company’s pre-petition debt was automatically stayed as a result of the Chapter 11 Cases. On the Effective Date, our obligations under the Senior Notes, including principal and accrued interest, were fully extinguished in exchange for equity in the post-emergence Company. In addition, our Existing Credit Facility, previously consisting of a senior secured revolving credit facility, was restructured into a New Credit Facility consisting of a senior secured first-out revolving facility (“New Revolver”) and a senior secured second-out term loan (“New Term Loan”).

Reclassification of Debt

The balances outstanding under our Senior Notes were classified as liabilities subject to compromise on the accompanying consolidated balance sheets at December 31, 2016. The outstanding balances under our Existing Credit Facility, real estate mortgage notes, installment notes and capital leases were not classified as subject to compromise at December 31, 2016, as these obligations were secured. Furthermore, as a result of certain debt defaults discussed above, which occurred in early 2016 and remained uncured during the pendency of the Chapter 11 Cases, all outstanding long-term debt was classified as current as of December 31, 2015 and 2016.

Pre-emergence Debt

As of the dates indicated, debt consists of the following:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

We recorded amortization of our Senior Note debt issuance costs of $602, $1,921 and $2,335 for the years ended, December 31, 2016, 2015 and 2014, respectively.

 

Absent any acceleration of our debt resulting from defaults or conversion to equity as a result of our Chapter 11 reorganization, the initial maturities of debt and capital leases would be as follows as of December 31, 2016:

 

 

Senior Notes

The Senior Notes, as of December 31, 2016, are our senior unsecured obligations and rank equally in right of payment with all of our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The Senior Notes were redeemable, in whole or in part, prior to their maturity at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption.

Interest on the Senior Notes were payable semi-annually, and the principal was due upon maturity. Certain of the Senior Notes were issued at a discount or a premium which is amortized to interest expense over the term of the respective series of Senior Notes. Net amortization of the discount (premium) was $32, $945, and $(268) during the years ended December 31, 2016, 2015 and 2014, respectively.

During December 2015, we repurchased approximately $42,045 of our outstanding Senior Notes on the open market for $9,995 in cash. As a result, we recorded a gain on extinguishment of debt of $31,590 for the year ended December 31, 2015.

In March 2016 we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes. These deferred items are typically amortized over the life of the corresponding bond. However, as a result of not paying the interest due on our 2021 Senior Notes by the end of our 30-day grace period on March 31, 2016, we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount as follows:

Pursuant to accounting guidance, while in bankruptcy, we did not accrue interest expense on our Senior Notes during the pendency of the Chapter 11 Cases as we do not expect to pay such interest. As a result, reported interest expense is $65,225 lower than contractual interest for the year ended December 31, 2016.

As discussed in “Note 2—Chapter 11 reorganization”, on the Effective Date, our obligations with respect to the Senior Notes, including principal and accrued interest, were cancelled and holders of the Senior Notes received their agreed-upon pro-rata share of the Company’s post-emergence equity.

Existing Credit Facility

In April 2010, we entered into an Eighth Restated Credit Agreement (the ‘Existing Credit Facility”), which is collateralized by our oil and natural gas properties and, as amended, was originally scheduled to mature on November 1, 2017. Availability under our

87

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Existing Credit Facility was subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually.

The initial borrowing base on our Existing Credit Facility for 2016 was $550,000; however subsequent to the defaults on this facility in March 2016, we no longer had availability under the facility until our debt was restructured upon exiting bankruptcy.  During 2016, we had additional borrowings of $181,000 and repayments of $103,560 on our Existing Credit Facility. As discussed in “Note 7—Derivative instruments,” our repayment of $103,560 was effectuated by directly offsetting proceeds payable to us from the termination of our derivative contracts against outstanding borrowings under the Existing Credit Facility during the third quarter of 2016. The ability to offset was possible as the previous counterparties to our derivative contracts were also lenders under the Existing Credit Facility.

Amounts borrowed under our Existing Credit Facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at December 31, 2016 was subject to the ABR which resulted in a weighted average interest rate of 5.25% on the outstanding amount. This rate did not include an additional 2.00% default margin which was waived by the Lenders pursuant to our Reorganization Plan.

Our Existing Credit Facility, as amended, also had certain negative and affirmative covenants that required, among other things, maintaining a Current Ratio, a Consolidated Net Secured Debt to Consolidated EBITDAX ratio and an Interest Coverage Ratio (all ratios as defined in the amendment). Subsequent to our debt defaults in March 2016 and through the pendency of our Chapter 11 Cases, we ceased quarterly reporting of our covenant compliance, which included these ratios, to the administrative agent of the facility.

Pursuant to the Reorganization Plan and in conjunction with a repayment of the entire balance of $444,440 on the Effective Date, our Existing Credit Facility was amended and restated in its entirety by the New Credit Facility as discussed below.

Post-emergence Debt

As discussed above, our post-emergence exit financing consists of the New Credit Facility, which includes the New Revolver and the New Term Loan, which was entered into on the Effective Date. The initial outstanding amounts under the New Credit Facility were:

 

 

(1) Upfront fees of 0.5% were paid to the lenders under the New Credit Facility. The amount paid in connection with the New Term Loan is reflected as a discount on the loan and will be amortized under the effective interest method. The amount paid in connection with the New Revolver will be reflected as a reduction to the liability whenever outstanding borrowings exceed the remaining unamortized issuance costs, otherwise such amount will be reflected as an asset. The issuance cost related to the New Revolver will be amortized ratably over the life of the facility.

New Term Loan

The New Term Loan, which is collateralized by our oil and natural gas properties, is scheduled to mature on March 21, 2021. Interest on the outstanding amount of the New Term Loan will accrue at an interest rate equal to either: (a) the Alternate Base Rate (as defined in the New Credit Facility) plus a 6.75% margin or (b) the Adjusted LIBO Rate (as defined in the New Credit Facility), plus a 7.75% margin with a 1.00% floor on the Adjusted LIBO Rate.

88

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

We are required to make scheduled, mandatory principal payments in respect of the New Term Loan according to the schedule below, with the remaining outstanding balance due upon maturity:

 

New Revolver

The New Revolver, is a $400,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on March 21, 2021. Availability under our New Revolver is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on the Effective Date was $225,000 and the first borrowing base redetermination has been set for on or about May 1, 2018. Availability on the New Revolver as of the Effective Date, after taking into account outstanding borrowings and letters of credit on that date, was $104,172.

Interest on the outstanding amounts under the New Revolver will accrue at an interest rate equal to either (i) the Alternate Base Rate plus a margin that ranges between 2.00% to 3.00% depending on utilization or (ii) the Adjusted LIBO Rate applicable to one, two three or six month borrowings plus a margin that ranges between 3.00% to 4.00% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the applicable rate while in default will be the Alternate Base Rate plus an additional 2.00% and plus the applicable margin.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the margin used to determine the interest rate applicable to New Revolver borrowings that are based on Adjusted LIBO Rate.

If the outstanding borrowings under our New Revolver were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 45 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency.

Other Provisions

Interest payment dates are dependent on the type of borrowing. In the case of Alternate Base Rate loans, interest is payable quarterly in arrears. In the case of Adjusted LIBO Rate borrowings, interest is payable on the last day of each relevant interest period and, in the case of any interest period longer than three months, on each successive date three months after the first day of such interest period.

As a precedent condition under the New Credit Agreement, we were required to have $100,000 of Liquidity (as defined in the New Credit Facility) upon emergence from our Chapter 11 Cases.

The New Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our New Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others.

The financial covenants require, for each fiscal quarter ending on and after March 31, 2017, that we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, (2) an Asset Coverage Ratio (as defined in the New Credit Facility) of no less than 1.35 to 1.00, (3) Liquidity (as defined in the New Credit Facility) of at least $25,000 and (4) a Ratio Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 3.5 to 1.0 calculated on a trailing four-quarter basis.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

The New Credit Facility is guaranteed by all of our wholly owned subsidiaries, subject to customary exceptions, and is secured by first priority security interests on substantially all of our assets.

Capital Leases

In 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are $3,181 annually.

 

Note 7: Derivative instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and natural gas liquids. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. See “Note 1—Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for derivative transactions.

From time to time, we may enter into derivative contracts, such as put options and collars, which are not costless but instead require payment of a premium. The premium can be paid at the time the contracts are initiated or deferred until the contracts settle. Payment of deferred premiums at the contract settlement date reduces the proceeds to be received upon settlement of the contracts. The fair value of our derivative contracts are reported net of any deferred premiums that are payable under the contracts.

Commodity price swaps allow us to receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (purchased put) and ceiling price (sold call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar utilizing the value associated with the sale of a put option.

Purchased put options are designed to provide a fixed price floor in an environment where prices have declined. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. In such an environment, put options may also be purchased to offset the downside from sold puts that are originally associated with enhanced swaps or collars.

Enhanced swaps enhance the value of swaps by combining them with sold puts or put spread contracts. The use of a sold put or put spread allows us to receive an above-market swap price while also providing a measure of downside protection. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will pay the spread between the sold put option price and the purchased put option price from the counterparty. A put spread may also be constructed by entering into separate sold put and purchased put contracts.

Basis protection swaps are used to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas

90

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

Due to defaults under the master agreements governing our derivative contracts, our outstanding derivative positions were terminated in May 2016. As discussed in “Note 8—Fair value measurements,” all the counterparties to our derivative transactions are also financial institutions within the lender group under our Existing Credit Facility. The derivative master agreements with these counterparties generally specify that a default under any of our indebtedness, as well as any bankruptcy filing, is an event of default which may result in early termination of the derivative contracts.

In December 2016, an agreement was reached with the Lenders regarding the resumption of hedging activity prior to our emergence from bankruptcy and thus we began entering into new derivative instruments. We entered into the bulk of our new derivative positions prior to December 31, 2016; however additional derivatives positions were entered into subsequent to year end.

The following table summarizes our crude oil derivatives outstanding as of December 31, 2016:

 

 

The following table summarizes our natural gas derivative instruments outstanding as of December 31, 2016:

 

 

On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts, originally scheduled to settle from 2015 through 2017 and covering 495 MBbls of oil and 12,280 BBtu of natural gas, in order to maintain compliance with the hedging limits imposed by covenants under our Existing Credit Facility. As a result, we received net proceeds of $15,395 which are included in “non-hedge derivative gains (losses)” disclosed below for the year ended December 31, 2015.

 

As discussed previously, our outstanding derivatives, as of May 2016, were early terminated as a result of our defaults under the master agreements governing our derivative contracts. These derivative contracts, originally scheduled to settle from 2016 through 2018, covered 3,400 MBbls of oil and 28,800 BBtu of natural gas. Proceeds from the early terminations, inclusive of amounts receivable at the time of termination for previous settlements, totaled $119,303. Of this amount, in the third quarter of 2016, $103,560 was utilized to offset outstanding borrowings under our Existing Credit Facility and the remainder was remitted to the Company.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

During January 2017, we entered into additional oil and natural gas swap contracts. The following table summarizes the additional contracts:

 

 

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the consolidated balance sheets at fair value. See “Note 8—Fair value measurements” for additional information regarding fair value measurements. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.

 

 

Effect of derivative instruments on the consolidated statements of operations

We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Non-hedge derivative (losses) gains” in the consolidated statements of operations.

“Non-hedge derivative (losses) gains” in the consolidated statements of operations is comprised of the following:

 

 

Note 8: Fair value measurements

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 7—Derivative instruments”). We had no Level 1 assets or liabilities as of December 31, 2016 or December 31, 2015. Our derivative contracts classified as Level 2 as of December 31, 2016 consisted of commodity price swaps and as of December 31, 2015 consisted of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from these derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at a rate that captures our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

As of December 31, 2016 our derivative contracts classified as Level 3 consisted of collars. As of December 31, 2015, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, and purchased puts. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.

The fair value hierarchy for our financial assets and liabilities is shown by the following table:

 

 

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy at December 31, 2016 and 2015 were:

 

 

Nonrecurring fair value measurements

Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the years ended December 31, 2016 and 2015 were escalated using an annual inflation rate of 2.42% and 2.91%, respectively, and discounted using our credit-adjusted risk-free interest rate of 17.05% and 15.09%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 9 —Asset retirement obligations” for additional information regarding our asset retirement obligations.

Impairment of long-lived assets. As discussed in “Note 1—Nature of operations and summary of significant accounting policies”, we recorded an impairment of $6,015 during the second quarter of 2015 related to our four stacked drilling rigs and drill pipe. The estimated fair value related to the impairment assessment was primarily based on third party estimates and, therefore, was classified within Level 3 of the fair value hierarchy. No impairment was recognized on our drilling rigs for the years ended December 31, 2016 and 2014. As discussed in “Note 1—Nature of operations and summary of significant accounting policies,” our four drilling rigs were sold in January 2017.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Fair value of other financial instruments

Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.

The carrying value and estimated fair value of our debt at December 31, 2016 and 2015 were as follows:

 

 

 

The fair value of our Senior Notes was estimated based on quoted market prices. The carrying value of our other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms.

See “Note 1—Nature of operations and summary of significant accounting policies” for additional information regarding our accounting policies for fair value measurements.

Concentrations of credit risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our Existing Credit Facility and our New Credit Facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender, or an affiliate of a lender, under our Existing Credit Facility can be offset against amounts owed to such counterparty lender under our Existing Credit Facility. As of December 31, 2016, the counterparties to our open derivative contracts consisted of four financial institutions, of which four were subject to our rights of offset under our Existing Credit Facility.

94

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our Existing Credit Facility that are available to offset our net derivative assets due from counterparties that are lenders under our Existing Credit Facility.

 

 

 

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our Existing Credit Facility. Payment on our derivative contracts could be accelerated in the event of a default on our Existing Credit Facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $13,553 at December 31, 2016.

Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.

Commodity sales to our top three purchasers accounted for the following percentages of our total commodity sales, excluding the effects of hedging activities, for the years ended December 31:

 

 

* Less than 10%

If we were to lose a purchaser, we believe we are able to secure other purchasers for the commodities we produce.

 

95

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Note 9: Asset retirement obligations

The following table presents the balance and activity of our asset retirement obligations:

 

 

Liabilities incurred include obligations related to new wells drilled and wells acquired during the period. Revisions in estimated cash flows for the year ended December 31, 2016 increased significantly when compared to the previous year. Approximately two-thirds of the increase resulted from shortening the estimated life of certain wells and the remaining third resulted from increasing our cost estimates for the plugging and abandonment of certain wells. Estimated lives were shortened as continued depressed commodity prices have diminished the prospects for any near term price recovery. Our cost estimates were increased as a result of recent experience on the complexity of plugging wells within the high pressure CO₂ floods in our  North Burbank Unit.

We have funds held in escrow that are legally restricted for certain of our asset retirement obligations. The balance of this escrow account was $1,519 and $1,567 at December 31, 2016 and 2015, respectively, and is included in “Other assets” in our consolidated balance sheets. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.

See “Note 8—Fair value measurements” for additional information regarding fair value measurements.

 

Note 10: Income taxes

Income tax (benefit) expense from continuing operations consists of the following for the years ended December 31:

 

 

A reconciliation of the U.S. federal statutory income tax rate to the effective tax rate is as follows for the years ended December 31:

 

96

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

 

Components of the deferred tax assets and liabilities are as follows at December 31:

 

 

Deferred tax asset valuation allowance. The ultimate realization of our deferred tax assets is dependent upon the generation of future taxable income during the periods in which those deferred tax assets would be deductible. We assess the realizability of our deferred tax assets each period by considering whether it is more likely than not that all or a portion of our deferred tax assets will not be realized. We consider all available evidence (both positive and negative) when determining whether a valuation allowance is required. We evaluated possible sources of taxable income that may be available to realize the benefit of deferred tax assets, including projected future taxable income, the reversal of existing temporary differences, taxable income in carryback years and available tax planning strategies in making this assessment.

Due to the full cost ceiling impairments recognized during 2016, we maintained our deferred tax asset position at December 31, 2016. We believe that it is more likely than not that these deferred tax assets will not be realized and recorded a $163,191 increase in valuation allowance to $574,338 maintaining the full valuation allowance against our net deferred tax asset at December 31, 2016. In our view, our cumulative historical three year pre-tax loss for the three years ended December 31, 2016, outweighs the other subjective factors, such as the possibility of future growth. We concluded in the third quarter of 2015 it was more likely than not that our deferred tax assets would not be realized and recorded valuation allowance totaling approximately $411,147 (including approximately $126,000 recorded as a discrete item associated with our federal and state net operating loss carryforwards for the year ended December 31, 2014) against our net deferred tax asset of as of December 31, 2015.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can determine that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if we recognize taxable income. As long as we conclude that the valuation allowance against its net deferred tax assets is necessary, we likely will not have any additional deferred income tax expense or benefit.

Net operating loss carryforwards. We have federal net operating loss carryforwards of approximately $689,000 at December 31, 2016, which will expire between 2028 and 2036 if not utilized in earlier periods. At December 31, 2016, we have state net operating loss carryforwards of approximately $844,000, which will expire between 2017 and 2036 if not utilized in earlier periods. In addition, at December 31, 2016 we had federal percentage depletion carryforwards of approximately $12,000, which are not subject to expiration.

97

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Our ability to utilize our loss carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of the Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of the equity of the Company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold.

The IRC provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Our emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the IRC. However, the IRC provides alternatives for taxpayers emerging from a Chapter 11 bankruptcy proceeding that may mitigate or even eliminate an annual limitation. We are in the process of analyzing these alternatives in order to minimize the impact of the ownership change on its ability to utilize tax attributes in future periods. This analysis will be dependent on a number of factors, including verifying qualification for each alternative, analyzing the possibility of a second ownership change during the two year period following emergence, and analyzing transactions subsequent to emergence generating taxable gains or losses.  We will make a final determination regarding the most beneficial alternative upon filing its 2017 U.S. Federal income tax return prior to its extended due date in the Fall of 2018.  

Important in the determination of the tax attributes of a debtor corporation following emergence from Chapter 11 is the amount of cancellation of indebtedness income realized.  On the emergence date, as described in “Note 2—Chapter 11 reorganization,” pursuant to the Reorganization Plan, $1,267,410 of indebtedness, including accrued interest, attributable to our Senior Notes and $2,981 of general unsecured claims were extinguished. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The IRC of 1986, as amended provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. While we are currently in the process of finalizing the bankruptcy related calculations, it is our expectation that the fair market value of the consideration received by our creditors upon emergence is substantially the same as the adjusted issue price of the indebtedness extinguished. Accordingly, the amount of CODI realized upon emergence may be relatively low, possibly zero.  However, to the extent the finally determined fair market value of the consideration is less than the adjusted issue price of the indebtedness, and CODI was realized, such amount of CODI would be excluded from taxable income and would reduce our prior tax attributes, which could include net operating losses, capital losses, alternative minimum tax credits and tax basis in assets. Any reduction of tax attributes is expected to be fully offset by a corresponding decrease in valuation allowance. Finally, any required reduction in tax attributes will not occur until the first day of our tax year ending subsequent to the date of emergence, or January 1, 2018.

 

Note 11: Deferred compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Plan”), to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to Participants in total up to 2% of the fair market value of the Company. No Participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.

Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan.

98

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Under the RSU plan, restricted stock units may be awarded to Participants in an aggregate amount of up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.

We did not grant any Phantom Unit or RSUs awards during 2016 and all remaining unvested awards were cancelled upon our emergence from bankruptcy on the Effective Date.

A summary of our phantom stock and RSU activity during the three years ended December 31, 2016 is presented in the following table:

 

Due to the severe decline in commodity pricing, which has resulted in a steep decline in our estimated proved reserves, the estimated fair value per phantom share and RSU as of December 31, 2016 is $0.00.

2015 Cash Incentive Plan

We adopted the Long-Term Cash Incentive Plan (the “2015 Cash LTIP”) on August 7, 2015. The 2015 Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in equal annual increments over a four-year period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We accrue for the cost of each annual increment over the period service is required to vest. Amounts related to our 2015 Cash LTIP are presented below:

 

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our Affiliated Entities’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.

99

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested conditions (the “Performance Vested” awards). The Time Vested awards vest in equal annual installments over the five -year vesting period, but may also vest on an accelerated basis in the event of a transaction whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

Our 2010 Plan allows participants to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.

Effective January 1, 2013, we amended and restated the Performance Vested awards to reflect that: (i) those shares which would vest if CCMP receives net cash proceeds from a Transaction that yields a return of at least 400% per share, or 20% of the Performance Vested awards then outstanding, were removed from the initial Performance Vested awards and an equal number of Time Vested shares were granted effective as of January 1, 2013; and (ii) the remaining number of Performance Vested shares outstanding were reallocated among five targets for vesting. Effective October 1, 2014, we terminated all outstanding grants of Performance Vested awards and issued new grants of Performance Vested awards to reflect that (i) a certain number of shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 350% per share were removed from the initial Performance Vested awards and an equal amount were granted effective as of October 1, 2014, as Time Vested awards; and (ii) the remaining number of shares subject to the previous Performance Vested awards were reallocated among three targets for vesting. These vesting targets will apply for any new grants of Performance Vested awards. As a result of these modifications, vesting requirements for all remaining Performance Vested awards are set at the following levels:

 

 

The modifications above changed the classification of the canceled and reissued awards from equity to liability instruments. The modifications in 2014 and 2013 both resulted in estimated incremental compensation cost of $8,536 and $4,322, which will be recognized over the remaining requisite service period using the accelerated method. Incremental compensation cost is measured as the excess of the fair value of the modified award over the fair value of the original award immediately before the modification, and is adjusted for changes in the fair value of the modified awards in each period until the awards are vested or forfeited.

Our bankruptcy filing in 2016 affected the valuation of our Time and Performance awards. Specifically, since our Reorganization Plan contemplates the cancellation of all existing common equity without any residual interest or consideration provided to the equity holders, the fair value of our Time and Performance awards was determined to be $0.00 per share as of the Petition Date. Prior to our bankruptcy, a combined income and market valuation methodology was used in the past to estimate the fair value of our common equity per share. The fair value of the Time Vested awards granted during 2015, and 2014 was considered to be equal to the estimated fair value of our common equity per share, net of a discount for lack of marketability of 25% and 20%, respectively. A control discount was not applied to the valuation pursuant to guidance released by the AICPA that discourages incorporating a control premium in the enterprise value used in valuing minority interest securities within an enterprise, except to the extent that such a premium reflects improvements to the business that a market participant would expect under current ownership.

100

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

The Monte Carlo simulation method was used to value the Performance Vested awards. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows:

 

 

Our expected volatility was calculated based on the average of the historical stock price volatility and the volatility implicit in the prices of the options or other traded financial instruments of our peer group. Our peer group consisted of the following oil and natural gas exploration and production companies in 2015: Cimarex Energy Co., Denbury Resources, Inc., Jones Energy, Inc., Laredo Petroleum Holdings, Inc., Midstates Petroleum Company, Inc., Resolute Energy Corporation, Bonanza Creek Energy, Inc. and Newfield Exploration Co. Our peer group in 2014 consisted of Cimarex Energy Co., Denbury Resources, Inc., Jones Energy, Inc., Laredo Petroleum Holdings, Inc., Midstates Petroleum Company, Inc., Pioneer Natural Resources Co., Resolute Energy Corporation, Sandridge Energy, Inc., Whiting Petroleum Corp. and Newfield Exploration Co.

A summary of our Time and Performance award activity during the three years ended December 31, 2016 is presented in the following table:

 

 

During 2016, 2015, and 2014, respectively, we repurchased and canceled 2,597, 5,725, and 2,025 vested shares but we do not expect to repurchase any restricted shares prior to the cancellation of all Predecessor common stock upon our emergence from bankruptcy. Based on an estimated fair value of $0.00 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $0 as of December 31, 2016.

101

---

Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Stock-based compensation cost

A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the years ended December 31:

 

 

During the third quarter of 2016, we recorded a cumulative catch up adjustment of $5,985 to reverse the aggregate compensation cost associated with our Performance Vested awards in order to reflect a decrease in the probability that requisite service would be achieved for these awards. Expense during 2016 was a credit as a result of the aforementioned catch up adjustment, forfeitures and the reduction in fair value of our liability-based awards. Payments for stock-based compensation were $49, $3,991, and $2,995 during 2016, 2015, and 2014, respectively. As of December 31, 2016 and 2015, accrued payroll and benefits payable included $0 and $81, respectively, for stock-based compensation costs expected to be settled within the next twelve months. The remaining unrecognized stock-based compensation cost of approximately $207 as of December 31, 2016 is expected to be recognized in its entirety upon the cancellation of all Predecessor common stock on the Effective Date.

 

Note 12: Stockholders' equity

Pre-emergence Common Stock

Our Amended and Restated Certificate of Incorporation filed April 12, 2010, created seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our existing stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to two existing stockholders.

On January 13, 2014, CHK Energy Holdings Inc. (“CHK Energy Holdings”), an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), sold all of its equity interest in us to Healthcare of Ontario Pension Plan Trust Fund. The 279,999 class D shares and one class G share owned by CHK Energy Holdings automatically converted to class A common stock and all associated rights with the class D and class G common stock were terminated.

Effective April 12, 2010, we implemented a Stockholders Agreement to provide for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under the indentures for our Senior Notes. The Stockholders Agreement was amended and restated on January 12, 2014 in conjunction with the sale of Chesapeake’s ownership interest in us to Healthcare of Ontario Pension Plan Trust Fund. Since the respective rights under the different classes of common stock generally relate to capital transactions that are outside the ordinary course of business, such transactions have been under purview of the Bankruptcy Court during the pendency of the Chapter 11 Cases rather than at the discretion of the existing stockholders.

On the Effective Date, all existing common stock of the Predecessor was cancelled and each holder of such stock did not receive any distribution or retain any property on account of their stock interest.

Post-emergence Common Stock

On the Effective Date, we issued or reserved for issuance a total of 45,000,000 shares of Successor common stock consisting of 37,125,000 shares of Class A common stock and 7,875,000 shares Class B common stock pursuant to our Reorganization Plan and our new organizational documents.  The new Class A shares and Class B shares have identical economic and voting rights, except that the new Class B shares shall be subject to certain redemption provisions in the event the Company undertakes an initial public offering.

102

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Summary of changes in common stock

The following is a summary of the changes in our common shares outstanding during the years ended December 31, 2016, 2015 and 2014.

 

 

 

Note 13: Retirement benefits

We provide a 401(k) retirement plan for all employees and matched 100% of employee contributions up to 7% of each employee’s gross wages during 2016, 2015 and 2014. At December 31, 2016, 2015, and 2014, there were 315, 395, and 625 employees, respectively, participating in the plan. Our contribution expense was $1,781, $2,363, and $3,592 for the years ended December 31, 2016, 2015 and 2014, respectively.

 

 

Note 14: Commitments and contingencies

Letters of Credit. Standby letters of credit (“Letters”) available under our Existing Credit Facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. Our outstanding letters of credit, as of both December 31, 2016 and 2015, totaled $828. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the years ended December 31, 2016, 2015, or 2014.

Commitments. We have three long-term contracts with three different suppliers to purchase CO₂. Pricing under one of these contracts is fixed while another varies with the price of oil. The third contract provides fixed pricing through May 2018 but becomes dependent upon the price of oil subsequently. Under this contract, we are obligated to purchase an average of approximately 35 MMcf/d for the remaining contract term or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate with six months’ notice.

As of December 31, 2016, we were purchasing approximately 43 MMcf/d of CO₂, from all sources combined and we expect to purchase approximately 42 MMcf/d in 2017. Purchases under these contracts were $2,289, $3,000, and $4,890 during 2016, 2015, and 2014, respectively.

103

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Based on current prices, our estimated minimum purchase obligations under our CO₂ contract is as follows:

 

 

In addition to our CO₂ commitments, we have other commitments totaling $14,211, substantially all of which are due in one year. These commitments are primarily related to restructuring fees due to consultants upon emergence from bankruptcy.

 

Operating Leases. We rent equipment used on our oil and natural gas properties and have operating lease agreements for CO₂ recycle compressors and office equipment. Rent expense for the years ended December 31, 2016, 2015, and 2014 was $6,693, $8,753, and $11,088, respectively. Our leases relating to office equipment have terms of up to five years. In June 2014, we entered into two non-cancelable operating leases for CO₂ recycle compressors at our EOR facilities which expire in 2021. In May 2016, we took delivery of an additional CO₂ compressor for which we have entered into a non-cancelable operating lease which expires in 2023.

As of December 31, 2016, total remaining payments associated with our operating leases were:

 

 

Litigation and Claims

Chapter 11 Proceedings. Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016. In connection with the proofs of claim asserted during bankruptcy from the proceedings or actions below, we are unable to estimate the amounts that will be allowed through the Bankruptcy proceedings due to the complexity and number of legal and factual issues presented by the matters and uncertainties with respect to, amongst other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcomes of the matters. As a result, no reserves have been established within our liabilities subject to compromise in connection with the proceedings and actions described below. To the extent that any of these legal proceedings result in a claim being allowed against us, such claims will be satisfied through the issuance of new stock in the Company.

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Trial Court”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma (“Naylor Farms Case”). The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. Responsive briefs to both motions were filed in the fourth quarter of 2015. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the

104

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

United States Bankruptcy Code. In response, on May 23, 2016, the court issued an order administratively closing the case, subject to reopening depending on the disposition of the bankruptcy proceedings. On July 22, 2016, attorneys for the putative class filed a motion in the Bankruptcy Court asking the court to lift the automatic stay and allow the case to proceed in the Naylor Trial Court. We did not object to lifting the automatic stay with regard to this case for the limited purpose of allowing the Naylor Trial Court to rule on the pending motion for class certification. On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the Plaintiffs originally sought to certify. On January 30, 2017, the Company filed a motion for reconsideration with the Naylor Trial Court, asking the court to rule the class cannot be immediately certified because Plaintiffs did not define dates for class membership.

The plaintiffs have indicated, if the class is certified, they seek damages in excess of $5,000 which may increase with the passage of time, a majority of which would be comprised of interest. In addition to filing claims on behalf of the named plaintiffs and associated parties, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $150,000 in our Chapter 11 Cases. The Company has objected treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. The Bankruptcy Court heard testimony and argument regarding class-wide treatment of the claim on February 28, 2017, but has not ruled on the matter. Under the Reorganization Plan, the Plaintiffs are identified as a separate class of creditors, Class 8. The Plaintiffs voted to reject the Reorganization Plan. Under the Reorganization Plan, Class 8 claims are entitled to receive their pro rata share of new stock issued to the holders of general unsecured claims (including claims of the Noteholders). Although the members of Class 8 did not vote to accept the Plan, the Bankruptcy Court confirmed the Plan on March 10, 2017. If the Bankruptcy Court permits the plaintiffs to file their proof of claim on behalf of the putative class, the claim is certified on a class basis, and the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgment or settlement of the unsecured claims would be satisfied through the issuance of new stock in the Company. We continue to dispute the plaintiffs’ allegations, dispute the case meets the requirements for class certification, and are objecting to the claims both individually and on a class-wide basis.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson, filed a complaint against us in the District Court of Mayes County, Oklahoma, (“Dodson Case”) with an allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include claims for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At the time we filed our Bankruptcy Petitions, a class had not been certified and discovery had not yet commenced. As the plaintiffs in the Dodson case did not file proofs of claim either for the putative class or the putative class representative, we anticipate any liability related to this claim will be addressed only based on proofs of claim filed by individual royalty owners.

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs challenged leases and drilling permits approved by the Bureau of Indian Affairs without the environmental studies allegedly required under the National Environmental Protection (NEPA). The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. On March 31, 2016, the Court dismissed the case against the federal agencies named as defendants, and therefore against all defendants, as an improper challenge under NEPA and the Administrative Procedures Act. On April 29, 2016, the plaintiffs filed a motion to alter or amend the court’s opinion and vacate the judgment, arguing the court does have jurisdiction to hear the claims and dismissal of the federal defendants does not require dismissal of the oil company defendants. The plaintiffs also filed a motion to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. Several defendants have filed briefs objecting to plaintiffs’ motions. On May 20, 2016, the Company filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code, and has not responded to the plaintiffs’ motions. After a motion for reconsideration was denied, Plaintiffs filed a Notice of Appeal on December 6, 2016. On December 30, 2016, the Court of Appeals entered an Order Abating Appeal due to pending bankruptcy proceedings of multiple defendants. On January 13, 2017 Plaintiffs responded to the Order Abating Appeal, asking the Court to proceed with the appeal. The court has not ruled on the appeal as of the date of this report.

As the plaintiffs in the Donelson case did not file proofs of claim either for the putative class or the putative class representatives, we anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class action.

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On February 18, 2016, an alleged class action was filed against us, as well as several other operators in the District Court of Pottawatomie County, State of Oklahoma (“West Case”), alleging claims on behalf of named plaintiffs and all similarly situated persons having an insurable real property interest in eight counties in central Oklahoma (the “Class Area”). The plaintiffs allege the oil and gas operations conducted by us and the other defendants have induced or triggered earthquakes in the Class Area. The plaintiffs are asking the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through a future date defined as the time at which the court determines there is no longer a risk that our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief. The plaintiffs did not ask for damages related to actual property damage which may have occurred. We responded to the petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. On March 18, 2016, the case was removed to the United States District Court for the Western District of Oklahoma under the Class Action Fairness Act (“CAFA”). On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. On October 14, 2016, the plaintiffs filed an Amended Complaint adding additional defendants and increasing the Class Area to 25 Central Oklahoma counties. Although we are named as a defendant, the Amended Complaint expressly limits its claims against us to those asserted in the original petition unless and until the automatic stay is lifted. Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75,000 in our Chapter 11 Cases. Other defendants have filed motions to dismiss the action based on various theories. The court has not ruled on these motions. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case.

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.

Note 15: Oil and natural gas activities

Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31:  

 

 

Depreciation, depletion, and amortization expense of oil and natural gas properties was as follows for the years ended December 31:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Oil and natural gas properties not subject to amortization consists of unevaluated leasehold acquisition costs, capitalized interest related to the leasehold costs and wells or facilities for which reserve volumes are not classified as proved until completed.

 

 

The wells and facilities in progress of completion were completed in 2017 and transferred to the amortization base while we expect to complete our evaluation for the majority of the leasehold acreage costs within the next two to five years.

 

Note 16: Disclosures about oil and natural gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P., each independent petroleum and geological engineers, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.  

107

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2016 are as follows:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

The following information was developed using procedures prescribed by GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

We believe that, in reviewing the information that follows, the following factors should be taken into account:

Future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil, gas and natural gas liquids, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open derivative positions (see “Note 7—Derivative instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

 

 

 

The following prices for oil, natural gas, and natural gas liquids before field differentials were used in determining future net revenues related to the standardized measure calculation.

 

 

 

 

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation as of the end of the fiscal year ended December 31, 2016, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, 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.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in the 2013 Internal Control-Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2016.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.  

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 11. EXECUTIVE COMPENSATION

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information relating to this item will be included in an amendment to this report and is incorporated by reference in this report.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements, Schedules and Exhibits

(1) Financial Statements-Chaparral Energy, Inc. and Subsidiaries:

The Financial Statements listed in the Index to Consolidated Financial Statements are filed as part of this report on Form 10-K (see Part II, Item 8-Financial Statements and Supplementary Data).

(2) Financial Statement Schedules

All other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.

(3) Exhibits

The exhibits listed below in the Exhibit Index, following the Signatures page, are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

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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: March 31, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

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EXHIBIT INDEX

 

115

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116

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117