Attached files

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EX-21.1 - EX-21.1 - Chaparral Energy, Inc.cpr-ex211_6.htm
EX-31.2 - EX-31.2 - Chaparral Energy, Inc.cpr-ex312_8.htm
EX-32.1 - EX-32.1 - Chaparral Energy, Inc.cpr-ex321_9.htm
EX-31.1 - EX-31.1 - Chaparral Energy, Inc.cpr-ex311_7.htm
EX-99.2 - EX-99.2 - Chaparral Energy, Inc.cpr-ex992_12.htm
EX-32.2 - EX-32.2 - Chaparral Energy, Inc.cpr-ex322_10.htm
EX-99.1 - EX-99.1 - Chaparral Energy, Inc.cpr-ex991_426.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

 

 

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR

 

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number: 333-134748

 

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

 

73-1590941

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

701 Cedar Lake Boulevard

Oklahoma City, Oklahoma

 

73114

(Address of principal executive offices)

 

(Zip code)

(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  o    No  x

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

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  o     No  x

(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  x    No  o

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.   x

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.

 

 

 

 

 

 

Large Accelerated Filer

¨

Accelerated Filer

¨

 

 

 

 

Non-Accelerated Filer

x

Smaller Reporting Company

¨

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

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.

Number of shares outstanding of each of the issuer’s classes of common stock as of March 25, 2016:  

 

 

Class

Number of shares

Class A Common Stock, $0.01 par value

334,545

 

Class B Common Stock, $0.01 par value

344,859

 

Class C Common Stock, $0.01 par value

209,882

 

Class E Common Stock, $0.01 par value

504,276

 

Class F Common Stock, $0.01 par value

1

 

Class G Common Stock, $0.01 par value

2

 

 

 

 


CHAPARRAL ENERGY, INC.

Index to Form 10-K

 

Part I

 

 

 

 

 

Items 1. and 2.

Business and Properties

7

 

 

 

Item 1A.

Risk Factors

29

 

 

 

Item 1B.

Unresolved Staff Comments

44

 

 

 

Item 2.

Properties

44

 

 

 

Item 3.

Legal Proceedings

44

 

 

 

Item 4.

Mine Safety Disclosures

45

 

 

 

Part II

 

 

 

 

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

46

 

 

 

Item 6.

Selected Financial Data

46

 

 

 

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

47

 

 

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

67

 

 

 

Item 8.

Financial Statements and Supplementary Data

70

 

 

 

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

113

 

 

 

Item 9A.

Controls and Procedures

113

 

 

 

Item 9B.

Other Information

114

 

 

 

Part III

 

 

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

115

 

 

 

Item 11.

Executive Compensation

117

 

 

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

129

 

 

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

130

 

 

 

Item 14.

Principal Accounting Fees and Services

132

 

 

 

Part IV

 

 

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

133

 

 

 

Signatures

137

 

 

 

1


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:

 

·

fluctuations in demand or the prices received for oil and natural gas;

 

·

the amount, nature and timing of capital expenditures;

 

·

drilling, completion and performance of wells;

 

·

competition and government regulations;

 

·

timing and amount of future production of oil and natural gas;

 

·

costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis;

 

·

changes in proved reserves;

 

·

operating costs and other expenses;

 

·

our future financial condition, results of operations, revenue, cash flows and expenses;

 

·

estimates of proved reserves;

 

·

exploitation of property acquisitions; and

 

·

marketing of oil and natural gas.

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:

 

·

the significant amount of our debt;

 

·

worldwide supply of and demand for oil and natural gas;

 

·

volatility and declines in oil and natural gas prices;

 

·

drilling plans (including scheduled and budgeted wells);

 

·

the number, timing or results of any wells;

 

·

changes in wells operated and in reserve estimates;

 

·

supply of CO2;

 

·

future growth and expansion;

 

·

future exploration;

 

·

integration of existing and new technologies into operations;

 

·

future capital expenditures (or funding thereof) and working capital;

 

·

borrowings and capital resources and liquidity;

 

·

changes in strategy and business discipline;

2


 

·

future tax matters;

 

·

any loss of key personnel;

 

·

future seismic data (including timing and results);

 

·

the plans for timing, interpretation and results of new or existing seismic surveys or seismic data;

 

·

geopolitical events affecting oil and natural gas prices;

 

·

outcome, effects or timing of legal proceedings;

 

·

the effect of litigation and contingencies;

 

·

the ability to generate additional prospects; and

 

·

the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

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.

 

 

3


GLOSSARY OF TERMS

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

 

Basin

A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

 

 

Bbl

One stock tank barrel of 42 U.S. gallons liquid volume is used herein in reference to crude oil, condensate or natural gas liquids.

 

 

BBtu

One billion British thermal units.

 

 

Boe

Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

 

 

Boe/d

Barrels of oil equivalent per day.

 

 

Btu

British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

 

 

Completion

The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

 

 

CO2

Carbon dioxide.

 

 

Credit Facility

Eighth Restated Credit Agreement, dated as of April 12, 2010, by and among us, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent and each of the Lenders named therein, as amended.

 

 

Developed acreage

The number of acres that are assignable to productive wells.

 

 

Development well

A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

 

Dry well or dry hole

An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

 

E&P Areas

Areas where we engage in exploration and production activities including the following plays: the STACK, Mississippi Lime, Panhandle Marmaton and Legacy Production Areas.

 

 

Enhanced oil recovery (EOR)

The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after secondary recovery.

 

 

EOR Project Areas

Areas where we are currently injecting, plan to inject or have potential for injection of CO2 as a means of additional oil recovery. These Areas include our active EOR Project Areas and potential EOR Project Areas.

 

 

Exploratory well

A well drilled to find a new field or to find a new reservoir in a field previously found to produce oil or natural gas in another reservoir.

 

 

Field

An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

 

 

Horizontal drilling

A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

 

 

Legacy Production Areas

Includes mature producing properties with low production decline curves and reserves, which include most of our vertical production and horizontal production outside the STACK, Mississippi Lime and Panhandle Marmaton, including the Cleveland Sand and Granite Wash. For prior year comparative purposes the areas also include Ark-La-Tex, Permian Basin and North Texas properties that we have sold.

 

 

4


Limestone/carbonate

A sedimentary rock composed primarily of calcium carbonate. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It can be composed of various calcium

carbonate grains or chemically precipitated. It often contains variable amounts of silica, silt, and clay. It is highly soluble which often results in secondary porosity and karsting. This can vary greatly from place to place. These factors all generally make this rock type a more heterogeneous deposit than sandstone.

 

 

MBbls

One thousand barrels of crude oil, condensate, or natural gas liquids.

 

 

MBoe

One thousand barrels of crude oil equivalent.

 

 

Mcf

One thousand cubic feet of natural gas.

 

 

MMBbls

One million barrels of crude oil, condensate, or natural gas liquids.

 

 

MMBoe

One million barrels of crude oil equivalent.

 

 

MMBtu

One million British thermal units.

 

 

MMcf

One million cubic feet of natural gas.

 

 

MMcf/d

Millions of cubic feet per day.

 

 

Natural gas liquids (NGLs)

Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.

 

 

Net acres

The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres.

 

 

NYMEX

The New York Mercantile Exchange.

 

 

OPEC

Organization of the Petroleum Exporting Countries

 

 

Play

A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.

 

 

Productive well

A well that is currently producing oil or natural gas or is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

 

 

Proved developed reserves

Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

 

 

Proved reserves

The 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.

 

 

Proved undeveloped reserves

Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

 

 

PV-10 value

When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.

 

 

Sandstone

A clastic sedimentary rock composed mainly of cemented sand-sized minerals or rock grains. Most sandstone is composed of quartz or feldspar. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It is usually a more resistant rock than limestone and generally has less lateral variability in porosity.

 

 

 

 

 

SEC

The Securities and Exchange Commission.

 

 

Secondary recovery

The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

 

 

5


Seismic survey

Also known as a seismograph survey, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.

 

 

Senior Notes

Collectively, our 9.875% senior notes due 2020, 8.25% senior notes due 2021, and 7.625% senior notes due 2022

 

 

Spacing

The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

 

 

STACK

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.

 

 

Undeveloped acreage

Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

 

 

Unit

The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

 

 

Wellbore

The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

 

 

Working interest

The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

 

 

Zone

A layer of rock which has distinct characteristics that differ from nearby layers of rock.

 

6


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 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 pure play 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, Woodford and Hunton formations. In addition, we have significant holdings in the Mississippi Lime play and a leadership position in CO2 EOR where we are now the third largest CO2 EOR operator in the United States based on the number of active projects. This EOR position is 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 2015, our average net daily production was 27.9 MBoe and our oil and natural gas revenues were $324.3 million. As of December 31, 2015, we had estimated proved reserves of 155.5 MMBoe with a PV-10 value of approximately $731 million and an estimated reserve life of approximately 15.2 years. These estimated proved reserves included 84.8 MMBoe of reserves in our active EOR Project Areas. Our reserves were 46% proved developed, 73% crude oil, and 8% 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.”

Beginning in 2011, we increased our focus on acquisitions of leasehold acreage and exploration in resource plays with repeatable drilling opportunities. Our focus has been concentrated in the Mid-Continent region, with most of our recent capital dollars being spent in the STACK play. By concentrating in this core area, we are developing a significant resource base to achieve future production and reserve growth.

Outlook

The upstream oil and gas business is cyclical and we are currently operating in a sustained lower commodity price environment. The commodity price decline that began in mid-2014 has continued its declining trajectory into 2016, with the price per barrel of West Texas Intermediate (“WTI”) oil falling below $30 on several occasions. The depressed pricing environment has continued for longer than expected. Our average realized prices for 2015 decreased 49% for crude oil, 42% for natural gas and 57% for NGLs as compared with 2014. These low prices resulted in a reduction in our capital spending program, had significant negative impacts on our revenues, profitability, cash flows, liquidity and proved reserves, resulted in asset impairments and caused us to reduce our workforce. At current prices, we also expect the next borrowing base redetermination of our Credit Facility to result in a borrowing base that is significantly less than the amount outstanding, which will result in a deficiency.

Significant factors that will affect 2016 commodity prices include: the impact of announced capital spending decreases on forecasted United States oil, NGL and gas supplies; the ongoing effect of economic stimulus initiatives; fiscal challenges facing the United States federal government and potential changes to the tax laws in the United States; continuing economic struggles in European and Asian nations; political and economic developments in North Africa and the Middle East; demand from Asian and European markets; the extent to which members of OPEC and other oil exporting nations are willing or able to manage oil supply through export quotas; the supply and demand fundamentals for NGLs in the United States and the pace at which export capacity grows; and overall North American gas supply and demand fundamentals, including gas storage levels.

Business Strategy

Given the uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, we have adapted our near-term business strategy to focus on improving our liquidity, reducing operating costs and efficiently executing our limited capital program. Our near term strategy will focus on:

Restructuring our debt to preserve liquidity and financial strength. Lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices are having a material and adverse effect on our liquidity. As a result of these adverse consequences, we may not have sufficient liquidity to meet our anticipated working capital, debt service and other liquidity needs, in particular those pertaining to any acceleration of indebtedness within the next 12 months. We are

7


currently pursuing or considering a number of actions to actively address our liquidity issues and high leverage levels. These alternatives include (i) debt- for-debt exchanges or debt-for-equity exchanges, (ii) potentially seeking relief under Chapter 11 of the U.S. Bankruptcy Code, (iii) obtaining waivers or amendments from our lenders, (iv) minimizing our planned capital investment,  (v) effectively managing our working capital, (vi) improving our cash flows from operations and (vii) dispositions of non-core assets. Our liquidity is discussed in further detail within “Liquidity and Capital Resources” in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Allocating our reduced capital investment to our higher return play acreage. We have reduced planned capital investments in 2016 to $110.6 million, approximately half of our 2015 capital spending. We have allocated $63.7 million, or 58% of our 2016 capital budget, to our E&P Areas of which $50.7 million of the expenditure will be on drilling and completion activities. While we commenced the year with three drilling rigs, we have reduced down to one drilling rig as of March 2016 which we expect to continue drilling in our higher return STACK play through the third quarter of 2016. We have allocated $44.8 million, or 41% of our 2016 capital budget, for development of our EOR projects in 2016, which includes expanding a limited number of CO2 flood patterns in our North Burbank Unit, infrastructure, continued CO2 purchases and maintenance.

Maximize cost savings and efficiency gains. We are preserving the significant reductions in our drilling and completions costs, lease operating expenses and general and administrative expenses achieved during 2015 and are aggressively pursuing further cost reductions in 2016. Our current cost reduction efforts are focused on targeting further price concessions from third party vendors, specifically those involved in our drilling and completion activities and day-to-day well maintenance. We are also monitoring the size of our workforce to ensure that we are appropriately staffed during the current downturn.

Upon returning to a normalized commodity price environment, our business strategies would return to strategies substantially similar to those that we have pursued over the last several years, which include delivering shareholder value through consistent growth of cash flow, production and reserves. Key components of our long-term business strategy include:  

 

·

Focused drilling program on our repeatable resource plays in the Mid-Continent Area;

 

·

Expanding production through expansion and development of our EOR projects;

 

·

Developing our high-quality asset portfolio;

 

·

Maintaining a talented workforce, experienced management team and strong investor support; and

 

·

Stabilizing cash flow and managing risk exposure for a substantial portion of production by hedging production.

 2015 Highlights

The following are material events 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:

 

·

Proved property impairments. Due to the depressed commodity price environment that prevailed throughout 2015, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at the end of the second, third and fourth quarters of 2015, resulting in a ceiling test write-down of $1.5 billion for the year as further discussed in “Management Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” in Item. 7 and “Note 1—Nature of operations and summary of significant accounting policies” in Item 8. Financial Statements and Supplementary Data of this report.

 

·

Cost reduction initiatives. In response to the decrease in crude oil prices, we implemented a Company-wide effort to decrease our capital, operating and administrative costs. Our cost reduction initiatives included a reduction in our workforce in 2015 by 213 employees, of which 131 were located at the Oklahoma City headquarters office and 82 were located at various field offices. In connection with our workforce reduction, we recorded charges of $7.7 million related to one-time severance and termination benefits and $2.3 million related to third party legal and professional services in 2015.

 

·

Cost efficiencies. We have aggressively pursued reductions in our drilling and completion costs, lease operating expenses and general and administrative expenses. Our cost reduction efforts included targeting price concessions from third party vendors, delaying completions of wells drilled early in the year into the second half of the year so we could benefit from multi-well bid competition and other operational efficiencies. As a result of our efforts, general and administrative expense and lease operating expense were 27% and 22%, respectively, lower in 2015 compared to the prior year. Furthermore our average per well drilling and completion costs in 2015 were approximately 30% to 40% lower than the prior year.

8


 

·

Lower capital expenditure. In recognition of depressed pricing, we established our 2015 capital budget based on an expectation of spending within available cash flows from operations. Our oil and natural gas capital expenditures for 2015 were $209 million compared to a budget in the range of $175-225 million and lower than the prior year by 72%. We reduced our operated rig count from 10 operated rigs at year-end 2014 to one rig as of April 2015. We added a second rig in December 2015 and a third rig in January 2016. We have currently reduced back down to one operated rig which we expect to operate through the third quarter of 2016. With the reduction in capital expenditure from the prior year, our net production on a year-over-year and fourth quarter-over-fourth quarter basis declined 7% and 18%, respectively.

 

·

Derivative settlements. As a result of our robust commodity hedging program, we received $202.9 million on our crude oil derivatives and $30.7 million on our natural gas derivatives during 2015. Based on NYMEX forward prices as of March 24, 2016, we have 4.4 million barrels of crude production hedged in 2016 at an average of $68.63 per barrel and 14,000 BBtu of 2016 natural gas production hedged at an average of $4.19/MMBtu.

 

·

Credit Facility and liquidity. We entered into an amendment to our Credit Facility effective April 1, 2015, pursuant to which our borrowing base was redetermined to $550.0 million and certain covenants were revised. Our semi-annual redetermination effective October 29, 2015, kept the borrowing base at the same level. We expect our next borrowing base redetermination, which will occur in spring 2016, to result in a borrowing base significantly lower than the current level.

Properties

The following table presents our proved reserves as of December 31, 2015, and average net daily production for both the year ended and quarter ended December 31, 2015, by our areas of operation. 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. Prices used as of December 31, 2015, before the effect of differentials, were $50.28 per Bbl of oil, $2.58 per Mcf of natural gas and $15.84 per Bbl of natural gas liquids.

 

 

 

Average daily production (MBoe per day)

 

 

Proved reserves as of December 31, 2015

 

 

 

Year ended December 31, 2015

 

 

Quarter ended December 31, 2015

 

 

Oil

(MBbls)

 

 

Natural gas

(MMcf)

 

 

Natural

gas liquids

(MBbls)

 

 

Total

(MBoe)

 

 

Percent of

total MBoe

 

 

PV-10

value

($MM)

 

E&P Areas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mississippi Lime

 

 

5.8

 

 

 

4.7

 

 

 

6,875

 

 

 

56,190

 

 

 

2,396

 

 

 

18,636

 

 

 

12.0

%

 

$

99

 

STACK - Meramec

 

 

0.4

 

 

 

0.4

 

 

 

834

 

 

 

5,265

 

 

 

720

 

 

 

2,432

 

 

 

1.6

%

 

 

13

 

STACK - Osage

 

 

1.5

 

 

 

1.4

 

 

 

2,218

 

 

 

19,855

 

 

 

1,456

 

 

 

6,983

 

 

 

4.5

%

 

 

29

 

STACK - Oswego

 

 

1.1

 

 

 

1.1

 

 

 

2,996

 

 

 

1,689

 

 

 

216

 

 

 

3,494

 

 

 

2.2

%

 

 

45

 

STACK - Woodford

 

 

1.4

 

 

 

2.1

 

 

 

442

 

 

 

13,328

 

 

 

1,496

 

 

 

4,159

 

 

 

2.7

%

 

 

26

 

Panhandle Marmaton

 

 

1.6

 

 

 

1.1

 

 

 

907

 

 

 

2,433

 

 

 

312

 

 

 

1,625

 

 

 

1.0

%

 

 

16

 

Legacy Production Areas

 

 

6.7

 

 

 

5.6

 

 

 

4,942

 

 

 

70,498

 

 

 

3,612

 

 

 

20,304

 

 

 

13.1

%

 

 

107

 

Total E&P Areas

 

 

18.5

 

 

 

16.4

 

 

 

19,214

 

 

 

169,258

 

 

 

10,208

 

 

 

57,633

 

 

 

37.1

%

 

 

335

 

EOR Project Areas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Active EOR Projects

 

 

6.1

 

 

 

6.1

 

 

 

84,810

 

 

 

8

 

 

 

5

 

 

 

84,816

 

 

 

54.5

%

 

 

317

 

Potential EOR Projects

 

 

3.3

 

 

 

3.0

 

 

 

9,742

 

 

 

8,952

 

 

 

1,858

 

 

 

13,092

 

 

 

8.4

%

 

 

79

 

Total EOR Project Areas

 

 

9.4

 

 

 

9.1

 

 

 

94,552

 

 

 

8,960

 

 

 

1,863

 

 

 

97,908

 

 

 

62.9

%

 

 

396

 

Total

 

 

27.9

 

 

 

25.5

 

 

 

113,766

 

 

 

178,218

 

 

 

12,071

 

 

 

155,541

 

 

 

100.0

%

 

$

731

 

E&P Areas

We have recently realigned the plays within our E&P Areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. E&P Areas currently include the following plays: the STACK, Mississippi Lime, Panhandle Marmaton and Legacy Production Areas. During 2015, capital expenditures on drilling in the STACK and Mississippi Lime plays accounted for 55% and 35%, respectively of our drilling expenditures. E&P Areas also includes our Legacy Production Areas which primarily include mature properties with low production decline curves and non-core properties that we have disposed (see “Note 4—Acquisitions and divestitures” in Item 8. Financial Statements and Supplementary Data). Presently, the majority of properties in our Legacy Production Areas are located in the Mid-Continent and are held by production.

STACK Play. 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 of previously drilled vertical wells

9


with multiple productive reservoirs. 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. We currently own approximately 219,000 (110,000 net) surface acres in this play.

Primarily as a result of our drilling activity, our average net daily production from this area was 4,458 Boe/d in 2015 compared to 3,542 Boe/d in 2014 and 464 Boe/d in 2013. During 2015, we spent $62.9 million on drilling activities in our STACK play, compared to a budget of $57.2 million, where we drilled and/or participated in the drilling of 34 (16 net) horizontal wells. 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 84,000 (36,000 net) acres targeting the Meramec interval within our STACK play. Within this area, our drilling locations are in Kingfisher county (“North Meramec”) and Canadian county (“South Meramec”). For a typical well in the North Meramec, we estimate the anticipated ultimate recovery per well to be 354 MBoe, of which 53% is prospective for oil, at an estimated completed well cost of approximately $3.0 million. For a typical well in the South Meramec, we estimate the anticipated ultimate recovery per well to be 434 MBoe, of which 67% is prospective for oil, at an estimated completed well cost of approximately $4.0 million.

STACK – Osage. We currently own approximately 183,000 (107,500 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 well in Kingfisher county, we estimate the anticipated ultimate recovery per well to be 315 MBoe, of which 52% is prospective for oil, at an estimated completed well cost of approximately $3.0 million. For a typical well in Garfield county, we estimate the anticipated ultimate recovery per well to be 434 MBoe, of which 30-60% are liquids, at an estimated completed well cost of approximately $3.1 million.

STACK – Oswego. We currently own approximately 117,000 (87,000 net) acres targeting the Oswego interval within our STACK play. Within this area, our drilling locations are primarily in Kingfisher and Garfield counties. Our primary Oswego drilling focus is in Kingfisher county where we estimate a typical well’s anticipated ultimate recovery to be 351 MBoe, of which 94% is prospective for oil, at an estimated completed well cost of approximately $2.7 million.

STACK – Woodford. We currently own approximately 162,000 (84,000 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’s anticipated ultimate recovery to be 443 MBoe, of which 59% is prospective for oil, at an estimated completed well cost of approximately $4.5 million.

Mississippi Lime Play – Various Counties, Oklahoma. The Mississippi Lime, located in North-Central Oklahoma, is a shallow carbonate play (mostly Limestone) with depths ranging from 5,000 feet to 6,000 feet. Our Mississippi Lime play is not a new play, but is now a horizontal development among and bordering on legacy vertical producing fields. This area has a long history of production from vertical wells and a well-developed infrastructure system to support further development. Our operations in our Mississippi Lime play are focused in the northwest region of Oklahoma and currently consist of 71,000 (50,000 net) acres. Across the play, we estimate the anticipated ultimate recovery per well to be 376 MBoe, of which 46% is prospective for oil, at an estimated completed well cost of $2.5 million.

Primarily as a result of our drilling activity, our average net daily production from this area was 5,811 Boe/d in 2015 compared to 5,367 Boe/d in 2014 and 3,416 Boe/d in 2013. During 2015, we spent $40.5 million on drilling activities in the play. We drilled and/or participated in the drilling of 26 (13 net) horizontal wells that were completed during 2015. As we align our 2016 drilling capital budget expenditures and focus on the plays that provide the highest returns, this area will be allocated materially less capital in 2016.

Panhandle Marmaton Play – Texas and Oklahoma Panhandles. Our Panhandle Marmaton play development program began in 2012. Our leasehold position provides for horizontal drilling opportunities targeting the Marmaton lime, which consists of numerous productive carbonate benches. We currently own approximately 126,000 (86,500 net) acres in this play. As a result of decreased capital spending in this area, our net average daily production from this area was approximately 1,645 Boe/d in 2015 compared to 2,878 Boe/d and 889 Boe/d in 2014 and 2013, respectively. We did not incur significant capital expenditure in this play in 2015 and have not budgeted any significant capital expenditures in this play for 2016.

10


Legacy Production Areas. Our Legacy Production Areas primarily include mature producing properties with low production decline curves and includes most of our vertical production and our horizontal production outside of the STACK and Mississippi Lime including formations of the Cleveland Sand and, Granite Wash. For prior year comparative purposes, these areas also include our Ark-La-Tex, Permian Basin, and North Texas properties which we divested in 2014. The production volumes from the divested properties are reflected in production volumes for the prior year period. We did not incur significant capital expenditure in these areas in 2015 and have not budgeted any significant capital expenditures for 2016.

In an effort to curb a recent increase in seismic activity, the Oklahoma Corporation Commission (the “OCC”) issued a directive on February 16 to operators of salt water disposal wells in northwestern Oklahoma to reduce injection volumes by approximately 40% from 2015 levels. This area of interest encompasses our Mississippi Lime play. Due to proactive measures taken by us in 2015 and normal production decline, we do not anticipate this directive to impact production of our operated wells as our injected volumes are currently below limits imposed by the directive. Although the directive may impact production from our non-operated wells, we do not expect any impact to be significant. On March 7, in a second directive, the OCC expanded its salt water volume reduction directive to include areas in central Oklahoma, which encompasses our STACK play. We are currently evaluating the impact of the second OCC directive on our operations but do not anticipate any significant impact. 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 2015, we incurred $25.9 million in capital expenditures on acquisitions which were comprised primarily of leasehold acreage in Kingfisher, Canadian and Garfield counties in Oklahoma, which are prospective for drilling in our STACK play.

EOR Project Areas

Our EOR Project Areas include both our active EOR projects and potential EOR projects, as reflected in the following table:

 

As of and for the year ended December 31, 2015

 

Active EOR

 

 

Potential EOR

 

 

Total for EOR Project Areas

 

Reserves (MBoe)

 

 

84,816

 

 

 

13,092

 

 

 

97,908

 

Production (Boe/d)

 

 

6,104

 

 

 

3,260

 

 

 

9,364

 

Capital expenditures excluding acquisitions (in thousands)

 

$

50,800

 

 

$

6,194

 

 

$

56,994

 

 

We have been actively implementing and managing CO2 EOR in the Panhandle and Central Oklahoma areas since 2001. We now have CO2 supply agreements in place in the Burbank, Panhandle, and Central Oklahoma areas, and we have built CO2 pipelines to reach several of our field locations in each 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. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of those reserves. CO2 miscible flooding is implemented and managed as a closed system consisting of the reservoir and surface piping. The physical material balance of the system means that the CO2 is produced and recycled many times once it has been injected. 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 available, projects could be developed on accelerated timelines, while a more limited supply dictates a prolonged expansion. Due to the size of our EOR projects, the fixed rate of CO2 availability which is secured for the long-term period, and the limitation of third party services, we expect the development of our EOR projects will extend beyond five years in many cases. Our significant active EOR projects are discussed below.

11


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

 

 

 

Proved reserves as of December 31, 2015

 

 

Production (MBoe)

 

 

Number of wells as of December 31, 2015

 

 

 

 

 

 

 

Proved developed (MBoe)

 

 

Proved undeveloped

(MBoe)

 

 

2015

 

 

2014

 

 

Producing

 

 

Active water & CO2 injection

 

 

Shut-in and temporarily abandoned

 

 

Average working interest

 

Active EOR

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

North Burbank Unit

 

 

15,192

 

 

 

62,689

 

 

 

814

 

 

 

517

 

 

 

282

 

 

 

184

 

 

 

521

 

 

 

99.3

%

Camrick Area Units

 

 

2,596

 

 

 

1,333

 

 

 

399

 

 

 

428

 

 

 

37

 

 

 

40

 

 

 

24

 

 

 

60.1

%

Booker Area Units

 

 

380

 

 

 

 

 

 

298

 

 

 

288

 

 

 

11

 

 

 

9

 

 

 

4

 

 

 

99.4

%

Farnsworth Unit

 

 

2,457

 

 

 

 

 

 

625

 

 

 

499

 

 

 

31

 

 

 

19

 

 

 

45

 

 

 

100.0

%

Other

 

 

169

 

 

 

 

 

 

92

 

 

 

102

 

 

 

26

 

 

 

10

 

 

 

3

 

 

 

100.0

%

Total Active EOR

 

 

20,794

 

 

 

64,022

 

 

 

2,228

 

 

 

1,834

 

 

 

387

 

 

 

262

 

 

 

597

 

 

 

92.5

%

Total Potential EOR

 

 

11,355

 

 

 

1,737

 

 

 

1,190

 

 

 

1,324

 

 

 

455

 

 

 

217

 

 

 

887

 

 

 

93.9

%

Total EOR

 

 

32,149

 

 

 

65,759

 

 

 

3,418

 

 

 

3,158

 

 

 

842

 

 

 

479

 

 

 

1,484

 

 

 

93.0

%

North Burbank Unit. As of December 31, 2015, our North Burbank Unit, which is our largest property and for which we are the operator, accounted for 50%, of our total proved reserves and 92% of our active EOR projects 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 2015 as a result of our CO2 injection and the associated response. Due to the size of our North Burbank Unit, there is insufficient CO2 availability and third party services available to complete the development of our North Burbank Unit within five years, and as a result the development of our North Burbank Unit will be an ongoing project.

We commenced CO2 injection at our North Burbank Unit in June 2013. The CO2 utilized at this location is sourced from an existing nitrogen fertilizer plant in Coffeyville, Kansas as described further below and in “Note 14—Commitments and contingencies” in Item 8. Financial Statements and Supplementary Data of this report. 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. With some response by December, we added proved CO2 EOR reserves of 5.3 MMBoe and removed polymer reserves of 1.5 MMBoe for our North Burbank Unit in late 2013. We continued CO2 injection within Phase I and expanded into Phase II of the CO2 flood during 2014. With additional response in 2014, we added proved CO2 EOR reserves of 25.2 MMBoe and removed the remainder of our polymer reserves of 12.6 MMBoe. Given our record of proven response, in 2015 we added 36.4 MMBoe of proved CO2 EOR reserves related to all remaining phases at the unit during the third quarter of 2015. Development of remaining phases will follow in future years as a sufficient volume of purchased and recycled CO2 becomes available.

Our total investment in our North Burbank Unit during 2015 was $31.7 million compared to an annual budget of $23.1 million,  associated with upgrading and installing surface facilities, standard well maintenance and improvements, and purchasing CO2 for injection. Our budgeted capital expenditure in 2016, for which we have allocated $26.4 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.

Camrick Area Units. Our Camrick Area Units consist of our Camrick Unit, where we began CO2 injection in 2001 and our North Perryton Unit, where we began CO2 injection in 2006. Currently, CO2 injection operations are continuing in the Phase I, II and III areas of our Camrick Unit and within our North Perryton Unit.

Our investment in our Camrick Area Units during 2015 was $3.6 million, compared to an annual budget of $4.4 million, associated with the continued purchase of CO2, infrastructure and remedial well work.

Booker Area Units.  All of the reserves in this Unit are considered EOR. In September 2009, we began CO2 injection into our three Booker Area Units. We have been able to maintain production levels by continuously optimizing wells and facilities, mitigating failures, and reducing overall downtime.

Our total investment in our Booker Area Units during 2015 was $4.3 million, which was equal to our annual budget, for continued purchase of CO2, installation of a variable frequency drive for the original recycle compressor, installation of a gas fired recycle compressor and standard well maintenance.

12


Farnsworth Unit. Our Farnsworth Unit, of which all of the reserves in this Unit are considered EOR reserves, lies to the south of and is analogous to the Camrick Area Units. We acquired a 100% working interest in our Farnsworth Unit in November 2009 and we began CO2 injection in December 2010. The increase in average net daily production from 2014 to 2015 is primarily due to CO2 response and minimal downtime. During 2015, we invested $9.6 million compared to an annual budget of $7.6 million, for continued purchase of CO2, standard well maintenance and battery upgrades. We expect our budgeted capital expenditures for 2016 in this area to be lower than our 2015 expenditures.

Potential EOR Properties. We define these properties primarily as properties that we have assessed as having commercial EOR potential and that we plan to develop once additional CO2 volumes become available. We have not allocated any significant amount of our 2015 or 2016 capital budget to this area.

CO2 Sources and Pipelines

We capture, compress and transport CO2 to our active EOR projects from four separate CO2 sources.

Coffeyville. Our CO2 source for our 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 we completed in 2013. During 2015, we purchased an average of 26 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, and establish the platform to expand our CO2 recovery operations in our 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 2015 we purchased an average of 11 MMcf/d from this source. The Agrium fertilizer plant is currently undergoing a modification to allow additional fertilizer production. As a result of this modification, we expect our CO2 volumes to be reduced in early 2017.  If the available CO2 volume decreases below 5 MMcf/d, we likely will not be able to operate the compression 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. During 2015 we purchased an average of 10 MMcf/d from this source.

Enid. We have a contract to purchase up to approximately 10 MMcf/d of 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 deliver the Enid-sourced CO2 to our active EOR project in southern Oklahoma. During 2015 we purchased an average of approximately one MMcf/d from this Enid CO2 source. Unless modified or replaced, both the CO2 purchase contract and the operations agreement for the compression facility and pipeline expire in 2016.

Our total investment for CO2 purchases and CO2 pipeline and compression facility infrastructure during 2015 was $21.7 million. We have allocated approximately $25.6 million of our capital expenditures budget for 2016 to CO2 purchases as well as maintenance associated with our CO2 pipeline and compression facility infrastructure.

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 SEC regulations. Users of this information should be aware that the process of

13


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, substantially all of which were 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 27 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. Our Corporate Reserve Department currently has a total of six full-time employees, comprised of four degreed engineers and two engineering analysts/technicians.

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:

 

·

The Corporate Reserve Department follows comprehensive SEC-compliant internal policies to determine and report proved reserves including:

 

·

confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests;

 

·

reviewing and using in the estimation process data provided by other departments within the Company such as Accounting; and

 

·

comparing and reconciling internally generated reserves estimates to those prepared by third parties.

 

·

Reserves estimates are prepared by third-party engineering firms based on a minimum of 80% of the total company PV-10 value; internal estimates are prepared by experienced reservoir engineers.

 

·

The Corporate Reserve Department reports directly to our Chief Executive Officer, independently of any of our operating divisions.

 

·

Our reserves are reviewed by senior management, which includes the Chief Executive Officer, the President and Chief Operating Officer, and the Chief Financial Officer, and they are responsible for verifying that the estimate of proved reserves is reasonable, complete, and accurate. Members of senior management may also meet with the key representatives from Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. to discuss their processes and findings. Final approval of the reserves is required by our Chief Executive Officer, President and Chief Operating Officer, and Chief Financial Officer.

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

14


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.

 

 

 

December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Cawley, Gillespie & Associates, Inc.

 

 

42

%

 

 

39

%

 

 

53

%

Ryder Scott Company, L.P.

 

 

48

%

 

 

50

%

 

 

33

%

Internally prepared

 

 

10

%

 

 

11

%

 

 

14

%

 

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 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.”

 

 

 

As of December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Estimated proved reserve volumes:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

113,766

 

 

 

101,247

 

 

 

92,813

 

Natural gas (MMcf)

 

 

178,218

 

 

 

247,756

 

 

 

302,922

 

Natural gas liquids (MBbls)

 

 

12,071

 

 

 

16,853

 

 

 

15,175

 

Oil equivalent (MBoe)

 

 

155,541

 

 

 

159,393

 

 

 

158,475

 

Proved developed reserve percentage

 

 

46

%

 

 

58

%

 

 

64

%

Estimated proved reserve values (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

Future net revenue

 

$

2,120,608

 

 

$

5,943,028

 

 

$

5,312,224

 

PV-10 value

 

$

731,426

 

 

$

2,547,204

 

 

$

2,349,656

 

Standardized measure of discounted future net cash flows

 

$

684,689

 

 

$

1,894,700

 

 

$

1,743,772

 

Oil and natural gas prices: (1)

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

50.28

 

 

$

94.99

 

 

$

96.78

 

Natural gas (per Mcf)

 

$

2.58

 

 

$

4.35

 

 

$

3.67

 

Natural gas liquids (per Bbl)

 

$

15.84

 

 

$

36.10

 

 

$

32.53

 

Estimated reserve life in years (2)

 

 

15.2

 

 

 

14.5

 

 

 

16.3

 

 

(1)

Prices were based upon the average first day of the month prices for each month during the respective year and do not reflect differentials.

(2)

Calculated by dividing net proved reserves by net production volumes for the year indicated.

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

 

 

Net proved reserves as of December 31, 2015

 

 

Oil

(MBbls)

 

 

Natural gas

(MMcf)

 

 

Natural gas

liquids (MBbls)

 

 

Total

(MBoe)

 

 

PV-10 value

(in thousands)

 

Developed—producing

 

36,889

 

 

 

120,904

 

 

 

8,763

 

 

 

65,803

 

 

$

572,442

 

Developed—non-producing

 

3,411

 

 

 

11,419

 

 

 

406

 

 

 

5,721

 

 

 

36,539

 

Undeveloped

 

73,466

 

 

 

45,895

 

 

 

2,902

 

 

 

84,017

 

 

 

122,445

 

Total proved

 

113,766

 

 

 

178,218

 

 

 

12,071

 

 

 

155,541

 

 

$

731,426

 

 

15


Proved Undeveloped Reserves

 

The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2015.

 

 

 

MBoe

 

Proved undeveloped reserves as of January 1, 2015

 

 

66,366

 

Undeveloped reserves transferred to developed (1)

 

 

(4,814

)

Purchases of minerals

 

 

 

Sales of minerals in place

 

 

(994

)

Extensions and discoveries

 

 

3,446

 

Improved recoveries (2)

 

 

36,414

 

Revisions and other

 

 

(16,401

)

Proved undeveloped reserves as of December 31, 2015 (3)

 

 

84,017

 

 

(1)

Approximately $52.0 million of developmental costs incurred during 2015 related to undeveloped reserves that were transferred to developed.

(2)

Primarily due to the addition of reserves for all remaining phases at our North Burbank Unit. These reserves were added after a sustained record of production response from CO2 injection at this unit.

(3)

Includes 2.8 MMBoe of reserves that have been reported for more than five years that relate specifically to our Camrick EOR area. Development of these projects is ongoing. See “Properties—EOR Project Areas” above for additional discussion of our CO2 EOR projects.

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 at December 31, 2015, 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.

 

 

 

Oil

 

 

Natural Gas

 

 

Total

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Operated Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

E&P Areas

 

 

401

 

 

 

341

 

 

 

296

 

 

 

208

 

 

 

697

 

 

 

549

 

EOR Project Areas

 

 

1,125

 

 

 

1,017

 

 

 

25

 

 

 

21

 

 

 

1,150

 

 

 

1,038

 

Total

 

 

1,526

 

 

 

1,358

 

 

 

321

 

 

 

229

 

 

 

1,847

 

 

 

1,587

 

Non-Operated Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

E&P Areas

 

 

1,279

 

 

 

74

 

 

 

965

 

 

 

106

 

 

 

2,244

 

 

 

180

 

EOR Project Areas

 

 

475

 

 

 

69

 

 

 

 

 

 

 

 

 

475

 

 

 

69

 

Total

 

 

1,754

 

 

 

143

 

 

 

965

 

 

 

106

 

 

 

2,719

 

 

 

249

 

Total Wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total E&P Areas

 

 

1,680

 

 

 

415

 

 

 

1,261

 

 

 

314

 

 

 

2,941

 

 

 

729

 

Total EOR Project Areas

 

 

1,600

 

 

 

1,086

 

 

 

25

 

 

 

21

 

 

 

1,625

 

 

 

1,107

 

Total

 

 

3,280

 

 

 

1,501

 

 

 

1,286

 

 

 

335

 

 

 

4,566

 

 

 

1,836

 

16


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, 2015, we had seven operated wells drilling, completing or awaiting completion.

 

 

 

2015

 

 

2014

 

 

2013

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

46

 

 

 

22

 

 

 

174

 

 

 

100

 

 

 

156

 

 

 

65

 

Dry

 

 

1

 

 

 

1

 

 

 

2

 

 

 

2

 

 

 

3

 

 

 

 

Exploratory wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

16

 

 

 

6

 

 

 

26

 

 

 

19

 

 

 

17

 

 

 

13

 

Dry

 

 

1

 

 

 

1

 

 

 

1

 

 

 

1

 

 

 

1

 

 

 

1

 

Total wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

62

 

 

 

28

 

 

 

200

 

 

 

119

 

 

 

173

 

 

 

78

 

Dry

 

 

2

 

 

 

2

 

 

 

3

 

 

 

3

 

 

 

4

 

 

 

1

 

Total

 

 

64

 

 

 

30

 

 

 

203

 

 

 

122

 

 

 

177

 

 

 

79

 

Percent productive

 

 

97

%

 

 

93

%

 

 

99

%

 

 

98

%

 

 

98

%

 

 

99

%

 

Developed and Undeveloped Acreage

The following table sets forth our gross and net interest in developed and undeveloped acreage at December 31, 2015, by state. This does not include acreage in which we hold only royalty interests.

 

 

 

Developed

 

 

Undeveloped

 

 

Total

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Oklahoma

 

 

468,349

 

 

 

255,841

 

 

 

128,771

 

 

 

101,726

 

 

 

597,120

 

 

 

357,567

 

Texas

 

 

78,476

 

 

 

49,664

 

 

 

13,726

 

 

 

12,869

 

 

 

92,202

 

 

 

62,533

 

Other

 

 

10,111

 

 

 

8,101

 

 

 

 

 

 

 

 

 

10,111

 

 

 

8,101

 

Total

 

 

556,936

 

 

 

313,606

 

 

 

142,497

 

 

 

114,595

 

 

 

699,433

 

 

 

428,201

 

 

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, 2015 the expiration periods and net acres that are subject to leases in the undeveloped acreage summarized in the above table.

 

 

 

Acres Expiring

 

Twelve Months Ending

 

Gross

 

 

Net

 

December 31, 2016

 

 

77,347

 

 

 

62,598

 

December 31, 2017

 

 

61,787

 

 

 

48,890

 

December 31, 2018

 

 

2,643

 

 

 

2,307

 

December 31, 2019

 

 

 

 

 

5

 

Other (1)

 

 

720

 

 

 

795

 

Total

 

 

142,497

 

 

 

114,595

 

 

(1)

Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.

17


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.

 

 

 

As of December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

Property acquisition costs

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

 

$

1,192

 

 

$

3,496

 

 

$

69,962

 

Unproved properties

 

 

24,735

 

 

 

84,938

 

 

 

145,853

 

Total acquisition costs

 

 

25,927

 

 

 

88,434

 

 

 

215,815

 

Development costs

 

 

150,261

 

 

 

561,578

 

 

 

376,394

 

Exploration costs (1)

 

 

33,091

 

 

 

90,146

 

 

 

77,507

 

Total

 

$

209,279

 

 

$

740,158

 

 

$

669,716

 

Annual reserve replacement ratio (2)

 

 

429

%

 

 

359

%

 

 

348

%

 

(1)

Includes $0.5 million, $0.2 million, and $37.3 million of EOR costs in 2015, 2014, and 2013 respectively.

(2)

Calculated 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:

 

 

Year ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

 

 

Reserves

replaced

 

 

Percent of

total

 

 

Reserves

replaced

 

 

Percent of

total

 

 

Reserves

replaced

 

 

Percent of

total

 

Purchases of minerals in place

 

 

3

%

 

 

0.6

%

 

 

5

%

 

 

1.2

%

 

 

51

%

 

 

14.6

%

Extensions and discoveries

 

 

69

%

 

 

16.1

%

 

 

233

%

 

 

65.0

%

 

 

257

%

 

 

74.0

%

Improved recoveries

 

 

357

%

 

 

83.3

%

 

 

121

%

 

 

33.8

%

 

 

40

%

 

 

11.4

%

Total

 

 

429

%

 

 

100.0

%

 

 

359

%

 

 

100.0

%

 

 

348

%

 

 

100.0

%

 

18


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.

 

 

 

Year ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Production:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

5,519

 

 

 

5,977

 

 

 

5,006

 

Natural gas (MMcf)

 

 

18,788

 

 

 

20,648

 

 

 

20,250

 

Natural gas liquids (MBbls)

 

 

1,550

 

 

 

1,564

 

 

 

1,361

 

Combined (MBoe)

 

 

10,200

 

 

 

10,982

 

 

 

9,742

 

Average daily production:

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls)

 

 

15,121

 

 

 

16,375

 

 

 

13,715

 

Natural gas (Mcf)

 

 

51,474

 

 

 

56,570

 

 

 

55,479

 

Natural gas liquids (MBbls)

 

 

4,247

 

 

 

4,285

 

 

 

3,729

 

Combined (Boe)

 

 

27,947

 

 

 

30,088

 

 

 

26,691

 

Average prices (excluding derivative settlements):

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

46.27

 

 

$

90.50

 

 

$

95.08

 

Natural gas (per Mcf)

 

$

2.42

 

 

$

4.17

 

 

$

3.48

 

Natural gas liquids (MBbls)

 

$

15.07

 

 

$

34.86

 

 

$

33.19

 

Combined (per Boe)

 

$

31.80

 

 

$

62.06

 

 

$

60.73

 

Average costs per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

$

10.85

 

 

$

12.89

 

 

$

13.62

 

Transportation and processing

 

$

0.84

 

 

$

0.76

 

 

$

0.73

 

Production taxes

 

$

0.98

 

 

$

2.58

 

 

$

3.41

 

Depreciation, depletion, and amortization

 

$

21.23

 

 

$

22.39

 

 

$

19.75

 

General and administrative

 

$

3.83

 

 

$

4.86

 

 

$

5.53

 

 

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 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:

 

 

 

As of December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

PV-10 value

 

$

731,426

 

 

$

2,547,204

 

 

$

2,349,656

 

Present value of future income tax discounted at 10%

 

 

(46,737

)

 

 

(652,504

)

 

 

(605,884

)

Standardized measure of discounted future net cash flows

 

$

684,689

 

 

$

1,894,700

 

 

$

1,743,772

 

 

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

19


consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our 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. The calculation of Consolidated EBITDAX includes pro forma adjustments for property acquisitions and dispositions, and as a result of these adjustments, our Consolidated EBITDAX as calculated for covenant compliance purposes is lower than our adjusted EBITDA for the year ended December 31, 2014 and higher than our adjusted EBITDA for the year ended December 31, 2013.

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, and (11) expenses associated with our cost reduction initiatives, transition, business optimization and other restructuring charges not to exceed $25.0 million in 2015 (as allowed under our Credit Facility) and (12) other significant, unusual non-cash charges. The following table provides a reconciliation of net income to adjusted EBITDA for the specified periods:

 

 

 

Year ended December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

Net (loss) income

 

 

(1,333,844

)

 

 

209,293

 

 

 

55,687

 

Interest expense

 

 

112,400

 

 

 

104,241

 

 

 

96,876

 

Income tax (benefit) expense

 

 

(177,219

)

 

 

124,443

 

 

 

32,849

 

Depreciation, depletion, and amortization

 

 

216,574

 

 

 

245,908

 

 

 

192,426

 

Unrealized (gain) loss on ineffective portion of hedges and

   reclassification adjustments

 

 

 

 

 

 

 

 

(37,134

)

Non-cash change in fair value of non-hedge derivative instruments

 

 

88,317

 

 

 

(228,903

)

 

 

40,748

 

Upfront premiums paid on settled derivative contracts

 

 

 

 

 

(664

)

 

 

 

Interest income

 

 

(192

)

 

 

(117

)

 

 

(254

)

Stock-based compensation expense

 

 

(1,477

)

 

 

3,172

 

 

 

4,933

 

Gain on sale of assets

 

 

(1,584

)

 

 

(2,152

)

 

 

(670

)

Gain on extinguishment of debt

 

 

(31,590

)

 

 

 

 

 

 

Loss on impairment of oil and gas assets

 

 

1,491,129

 

 

 

 

 

 

 

Loss on impairment of other assets

 

 

16,207

 

 

 

 

 

 

3,490

 

Cost reduction initiatives expense

 

 

10,028

 

 

 

 

 

 

 

Adjusted EBITDA

 

$

388,749

 

 

$

455,221

 

 

$

388,951

 

 

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.  In addition, 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.  The likelihood of experiencing competition and shortages of materials may increase with any commodity price recovery.

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

20


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.

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 amount of crude oil and natural gas imports;

 

·

the availability, proximity and cost of adequate pipeline and other transportation facilities;

 

·

the success of efforts to market competitive fuels, such as coal and nuclear energy and the growth and/or success of alternative energy sources such as wind power;

 

·

the effect of Bureau of Indian Affairs and other federal and state regulation of production, refining, transportation and sales;

 

·

the laws of foreign jurisdictions and the laws and regulations affecting foreign markets;

 

·

other matters affecting the availability of a ready market, such as fluctuating supply and demand; and

 

·

general economic conditions in the United States and around the world.

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. To reduce our exposure to potential environmental risk, we typically have our field personnel inspect operated properties prior to completing each acquisition.

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:

 

·

require the acquisition of various permits before drilling commences;

 

·

require the installation of costly emission monitoring and/or pollution control equipment;

 

·

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

 

·

limit or prohibit drilling activities on lands lying within wilderness, wetlands, certain animal habitats and other protected areas;

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·

require remedial measures to address pollution from former operations, such as pit closure and plugging of abandoned wells;

 

·

impose substantial liabilities for pollution resulting from our operations; and

 

·

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

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, 2015, 2014 and 2013, 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 2016 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.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, 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, 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

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previously disposed substances and wastes, remediate contaminated soil or groundwater, or perform remedial plugging or pit closure operations to prevent future contamination.  

Water Discharges

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.  

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 onshore 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.  

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 a draft assessment in June 2015 for peer review and public comment. In its assessment, the EPA indicated it did not find evidence that hydraulic fracturing mechanisms caused widespread, systemic impacts on drinking water resources in the United States. Nonetheless,

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the results of the study or similar governmental reviews could spur initiatives to regulate 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.

In addition, the EPA has adopted rules requiring the annual monitoring and reporting of greenhouse gas emissions from specified oil and gas production sources in the United States. In August 2015, the EPA proposed new 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.  This action was taken despite consensus that industry compliance with EPA's 2012 performance standards has already achieved the targeted methane reductions. The proposed regulations are expected to be finalized in 2016. On January 22, 2016, the Bureau of Land Management issued a pre-publication version of a proposed venting and flaring rule, which is also expected to be finalized in 2016 and, like the forthcoming EPA regulations, will address methane emissions from crude oil and natural gas sources. New regulations 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 addition, in December 2015, a global climate agreement was reached under the United Nations Framework Convention on Climate Change. The agreement, which comes into effect in 2020, commits nearly 200 countries, including the United States, to work towards limiting global warming and agreeing to a monitoring and review process for greenhouse gas emissions. The agreement includes binding and non-binding elements and did not require ratification by the Congress. Nonetheless, the agreement may result in increased political pressure on the United States to ensure continued compliance with enforcement measures under the CAA and may spur further initiatives aimed at reducing greenhouse gas emissions in the future.

Some of our new facilities may be required to obtain CAA permits before  being constructed or operated, and existing facilities may be required to incur capital costs in order to comply with new monitoring and reporting requirements and/or emission limitations. In December 2009, the EPA promulgated a finding that serves as the foundation under the CAA to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the CAA, even without Congressional action. As part of this array of new regulations, in September 2009, the EPA also promulgated a greenhouse gas monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their greenhouse gas emissions, including methane and carbon dioxide, to the EPA. In May 2010, EPA promulgated final rules regulating greenhouse gas emissions under the CAA, triggering application of other provisions of the CAA to major stationary sources of greenhouse gas emissions. In June 2010, EPA promulgated final rules limiting the scope of certain provisions of the CAA as applied to greenhouse gas emission sources. Additionally, in November 2010, EPA promulgated mandatory greenhouse gas emission reporting rules specifically applying to oil and natural gas exploration and production. Some of our operations are subject to these regulations. On April 17, 2012, EPA adopted new CAA regulations imposing new emissions standards for the oil and natural gas sector, including sources not previously regulated. See “Risk factors—Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.” Several of these federal regulations on greenhouse gas emissions have compliance deadlines this year, which  may result in additional permitting and compliance costs and require additional equipment for operational activities that will increase the cost of production.  Any noncompliance with these regulations can result in the imposition of administrative, civil and criminal fines and penalties, further increasing production costs.  The trend from EPA is to aggressively monitor and enforce these programs, imposing fines at each incident to speed compliance.  While we believe we are in substantial compliance with the current requirements

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of the CAA, if we fail to comply in the future, we may become subject to further compliance costs, fines or penalties that could have a material impact on our financial position or results of operations.

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 and the Lesser Prairie Chicken both have habitat in some areas where we operate. On April 10, 2014, the U.S. Fish and Wildlife Service (“FWS”) listed the Lesser Prairie Chicken, which inhabits portions of Colorado, Kansas, Nebraska, New Mexico, Oklahoma and Texas, as “threatened” effective May 12, 2014. On April 10, 2014 the FWS also finalized a final rule under section 4(d) of the ESA which “provides that all of the prohibitions under 50 CFR 17.31 and 17.32 will apply to the lesser prairie-chicken, except... that [actions] incidental to activities conducted by a participant enrolled in, and operating in compliance with, the Lesser Prairie-Chicken Interstate Working Group’s Lesser Prairie-Chicken Range-Wide Conservation Plan (rangewide plan) will not be prohibited.” The rangewide plan is administered by the Western Association of Fish and Wildlife Agencies (“WAFWA”). In turn, the FWS and the WAFWA entered into the Range-Wide Oil and Gas Candidate Conservation Agreement with Assurances (“CCAA”) dated February 28, 2014. The CCAA will be administered by the WAFWA with FWS oversight and is a voluntary agreement intended to address the effects of oil and gas activities on the Lesser Prairie-Chicken and its habitat in the five states. WAFWA is to work with members of the oil and gas industry to enroll properties in the CCAA using Certificates of Inclusion (“CIs”) which are designed “to facilitate the voluntary cooperation of the oil and gas industry in providing conservation benefits” to the Lesser Prairie-Chicken. Participants will also contribute funding (“mitigation fees”) for conservation to offset unavoidable impacts as part of their CIs. The presence of these 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.  In 2014, an industry association filed a lawsuit challenging the actions of FWS in listing the Lesser Prairie Chicken as threatened under the ESA. On September 1, 2015, the United States District Court for the Western District of Texas invalidated the FWS action in listing the Lesser Prairie Chicken as threatened.  The FWS is expected to appeal the decision.

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.  Although federal legislation has been proposed  in Congress directed at reducing greenhouse gas emissions, there is no current expectation that any such legislation will be adopted. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and 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. As discussed above, under the CAA, EPA has proposed new standards of performance limiting methane emissions from oil and natural gas sources that are expected to be finalized in 2016. Depending on EPA’s final 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.

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.

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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:

 

·

the location of wells;

 

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the method of drilling and casing wells;

 

·

the timing of construction or drilling activities;

 

·

the rates of production or “allowables”;

 

·

the use of surface or subsurface waters;

 

·

the surface use and restoration of properties upon which wells are drilled;

 

·

the plugging and abandoning of wells; and

 

·

notice to surface owners and other third parties.

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 and the Natural Gas Policy Act of 1978. 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.

FERC also regulates interstate natural gas transportation rates and service conditions, 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 rule makings 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

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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 FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and instate waters. Although its policy is still in flux, 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.

Natural Gas Pipeline Safety

The Department of Transportation, specifically the Pipeline and Hazardous Materials Safety Administration, regulates transportation of natural and other gas by pipeline and imposes 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.

CO2 Pipeline Safety

The Department of Transportation, or DOT, and specifically the Pipeline and Hazardous Materials Safety Administration, or PHMSA, regulates transportation of hazardous liquids and carbon dioxide by pipeline and imposes 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, updates federal pipeline safety standards, increases penalties for violations of such standards, gives the DOT authority for new damage prevention and incident notification, and directs 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.

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.

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.

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Natural Gas Gathering Regulations

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, 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.

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 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, 2015, we had 427 full-time employees, including 10 geologists and geophysicists, 31 reservoir, production, and drilling engineers and 10 land professionals. Of these, 224 work in our Oklahoma City office and 203 work in our district and field offices. 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 the first quarter of 2016, we terminated 61 employees as part of our workforce reduction which we began implementing in 2015 in response to the industry downturn.

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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.

The report of our independent registered public accounting firm expresses substantial doubt about the Company’s ability to continue as a going concern.

Our auditors, Grant Thornton LLP, have indicated in their report on the Company’s financial statements for the fiscal year ended December 31, 2015, that conditions exist that raise substantial doubt about our ability to continue as a going concern due to our limited ability to repay outstanding debt obligations as well as our noncompliance with financial covenants which could result  in an event of default under our Credit Facility. A “going concern” opinion could impair our ability to finance our operations through the sale of equity, incurring debt, or other financing alternatives. Our ability to continue as a going concern will depend largely upon the availability and terms of future funding, the price of oil and gas, and our ability to continue to develop our oil, natural gas and NGL reserves.  If we are unable to achieve these goals, our business would be jeopardized and we may not be able to continue. If we ceased operations, it is likely that all of our equity investors would lose their investment and could result in limited recovery for our noteholders.

We have a significant amount of indebtedeness.  Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and we may have difficulty paying our debts as they become due.

As of December 31, 2015, our total indebtedness was approximately $1.6 billion which included $367.0 million outstanding on our Credit Facility which has borrowing base of $550.0 million. On February 11, 2016, we borrowed an additional $141.0 million for general corporate purposes, which represented substantially all the remaining undrawn amount that was available under the Credit Facility. Following the funding of this borrowing, the aggregate principal amount of borrowings under the Credit Facility was $548.0 million, in addition to $0.8 million of outstanding letters of credit.

We expect to continue to be highly leveraged in the foreseeable future.  Our high level of indebtedness affects our operations in several ways, including the following:

 

·

the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;

 

·

we must use a substantial portion of our cash flow from operations to pay interest on our Senior Notes and our other indebtedness, which reduces the funds available to us for operations and other purposes;

 

·

we may be at a competitive disadvantage compared to our competitors that may have proportionately less debt;

 

·

our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions, or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;

 

·

our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;

 

·

we may be more vulnerable to economic downturns and adverse developments in our business; and

 

·

we may be vulnerable to interest rate increases, as our borrowings under our Credit Facility are at variable rates.

Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, prospects, and ability to satisfy our debt obligations.  

On March 1, 2016, we elected not to make an interest payment of $16.5 million due March 1, 2016, on our 8.25% Senior Notes maturing 2021, as we continue discussions with bondholders, senior revolving lenders and prospective financing sources in order to find alternatives to improve our long-term capital structure.  The election to defer the interest payment would not have constituted an event of default as defined under the indenture governing the notes or any other indenture relating to our other Senior Notes if the interest payment were to be made within 30 days of its due date. However, as we do not intend to make such interest payment, we expect to be in default under the indenture relating to those Senior Notes upon expiration of the grace period, and the trustee or holders of at least 25% in principal amount of those Senior Notes may declare the principal and any interest immediately due and payable. Our election to defer the interest payment on the Senior Notes also results in a cross default under our Credit Facility, which provides that any default on material indebtedness becomes an Event of Default under the Credit Facility if such default results in the acceleration of such material indebtedness or permits such acceleration with or without the giving of notice, the lapse of time or both.  Due to the

29


event of default under our Credit Facility, we will no longer be able to borrow at the LIBOR rate and our loans under our Credit Facility will bear interest at the default rate.

If the lenders under our Credit Facility or the trustee or holders of our Senior Notes accelerate our indebtedness as a result of defaults, such acceleration would cause a cross-default and potential acceleration of the maturity of substantially all our long-term debt. As such, our long-term debt obligations are classified as current liabilities in our consolidated balance sheet as of December 31, 2015. As a result of this reclassification, our current liabilities exceed our current assets by a significant amount and we are therefore in violation of the current ratio covenant under our Credit Facility for the period ending December 31, 2015.

If we are not successful in refinancing or restructuring our debt or accessing additional liquidity, we will not be able to fund all our commitments to the holders of our other Senior Notes or the lenders under our Credit Facility, and we will be in default under all of these obligations. We are actively working with financial and legal advisors to evaluate alternative sources to refinance all or a portion of our substantial outstanding indebtedness. No assurance can be given that such financing will be available on terms that are acceptable to us or at all.

 

We may not be unable to enter into hedging transactions under our derivative contracts.

Each time we enter into a hedging transaction with a hedge counterparty, we must make a representation under the relevant derivative contract that there is no event of default or potential event of default occurring under that derivative contract.  Any event of default or potential event of default under the debt facilities would trigger an event of default under our derivative contracts. As a result, we may not be able to enter into hedging transactions when we have outstanding events of default under our debt facilities.

As part of our restructuring efforts, we may seek bankruptcy court protection under Chapter 11 of the U.S. Bankruptcy Code, which could adversely impact our operations.

We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring, assets sales and a filing under Chapter 11 of the U.S. Bankruptcy Code. Seeking bankruptcy court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. If a Chapter 11 proceeding were to be commenced, our senior management would be required to spend a significant amount of time and effort focusing on the reorganization of our business instead of on our business operations. Bankruptcy court protection also might make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, a Chapter 11 proceeding may cause some of our customers, suppliers, vendors, service providers and hedge counterparties to lose confidence in our ability to reorganize our businesses successfully and seek to establish alternative commercial relationships or renegotiate the terms of our arrangements.  Additionally, we have a significant amount of secured indebtedness that is senior to our unsecured indebtedness. As a result, we believe that seeking bankruptcy court protection under a Chapter 11 proceeding could result in a limited recovery for our unsecured noteholders and creditors.

We may not be able to generate sufficient cash to service all of our long-term indebtedness, and we may be forced to take other actions to satisfy our obligations under our Credit Facility, which may not be successful.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing commodity prices, economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our long-term indebtedness.  

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to attempt to meet our debt service and other obligations. The indentures governing our Senior Notes and our Credit Facility restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or to sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due.

Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations, cash flows and liquidity. If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result:

30


 

·

debt holders could declare all outstanding principal and interest to be due and payable (which would in turn trigger cross-acceleration or cross-default on our other indebtedness);

 

·

we may be in default under our master (ISDA) derivative contracts and counterparties could demand early termination;

 

·

the lenders under the Credit Facility could terminate their commitments to loan us money, foreclose against the assets securing their borrowings and compel us to apply our available cash to repay our borrowings; and

 

·

we could be forced into bankruptcy or liquidation.

Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a further reduction of our credit rating, which could significantly harm our ability to incur additional indebtedness on acceptable terms.

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

Availability under our Credit Facility is subject to a borrowing base, which was reaffirmed at $550.0 million as of October 29, 2015, and which is set by the banks semi-annually on May 1 and November 1 of each year. 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. If we issue Additional Permitted Debt, as defined in our Credit Facility, the borrowing base will be automatically reduced by an amount equal to 15% - 25% of the aggregate stated principal amount of the debt issued, unless otherwise agreed to by our lenders. If the outstanding borrowings under our Credit Facility 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 30 days or in equal monthly installments over a six-month period; (2) to submit within 30 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 30 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 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.

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

 

·

incur additional indebtedness;

 

·

make investments or loans;

 

·

create liens;

 

·

consummate mergers and similar fundamental changes;

 

·

make restricted payments;

 

·

make investments in unrestricted subsidiaries; and

 

·

enter into transactions with affiliates.

The restrictions contained in the Credit Facility could:

 

·

limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan; and

 

·

adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest.

Also, our 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

31


and natural gas prices, or a prolonged period of oil and natural gas prices at depressed levels, could result in our failing to meet one or more of the financial covenants under our 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 Credit Facility. A default under our 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. If that should occur, we may be unable to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. In addition, in the event of an event of default under the Credit Facility, the lenders could foreclose on the collateral securing the Credit Facility and require repayment of all borrowings outstanding. If the amounts outstanding under the Credit Facility or any of our other indebtedness were to be accelerated, our assets may not be sufficient to repay in full the money owed to the lenders or to our other debt holders. Moreover, any new indebtedness we incur may impose financial restrictions and other covenants on us that may be more restrictive than our existing debt agreements.

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:

 

·

the level of consumer demand for oil and natural gas;

 

·

the domestic and foreign supply of oil and natural gas;

 

·

commodity processing, gathering and transportation availability, and the availability of refining capacity;

 

·

the price and level of foreign imports of oil and natural gas;

 

·

the ability of the members of OPEC to agree to and maintain oil price and production controls;

 

·

domestic and foreign governmental regulations and taxes;

 

·

the supply of CO2;

 

·

the supply of other inputs necessary to our production;

 

·

the price and availability of alternative fuel sources;

 

·

weather conditions;

 

·

financial and commercial market uncertainty;

 

·

political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and

 

·

worldwide economic conditions.

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, 2015, the posted price for West Texas Intermediate light sweet crude oil, commonly referred to as West Texas Intermediate, has ranged from a low of $34.55 per Bbl in December 2015 to a high of $113.39 per Bbl in April 2011. The Henry Hub spot market price of natural gas has ranged from a low of $1.63 per MMBtu in December 2015 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

32


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.  

If commodity prices remain at current levels for an extended period, we may, among other things, be unable to meet our financial obligations, including payments on our credit facility or senior notes, or be unable to make planned capital expenditures, each as explained more fully above.

Price declines that began in late 2014 resulted in write downs of the carrying values of our properties, and we expect additional write downs in the future, which could negatively impact our 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 which 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%, adjusted for derivatives accounted for as cash flow hedges and 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 as adjusted for our derivative positions deemed “cash flow hedge positions.”  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.

During the twelve months ended December 31, 2015, we recorded ceiling test write-downs of $1.5 billion. 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 incur corresponding non-cash 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. While the amount of any future impairment is generally difficult to predict, continued write-downs of oil and natural gas properties may occur until such time as commodity prices recover, and remain at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling test calculation. The average prices used in the ceiling test calculation at March 31, 2016 will be $46.26 per Bbl for oil and $2.39 per MMBtu for natural gas. This decline from the prior quarter will result in a further write-down in the first quarter of 2016, which we expect to be in the range of $175 million to $225 million. Any such further write downs could have a material adverse effect on our financial condition and results of operations.

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.  It requires interpretations of available technical data and various estimates and assumptions, including estimates based upon assumptions relating to economic factors such as commodity prices, production costs, severance and excise taxes, capital expenditures, workovers, remedial costs, and the assumed effect of governmental regulation.  There are numerous uncertainties about when a property may have proved reserves as compared to possible or probable reserves, including with respect to our EOR operations.  Reserve estimates are, therefore, inherently imprecise and, although we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results will vary from our estimates.  Any significant variations in the interpretations or assumptions underlying our estimates or changes of conditions (e.g. economic growth and/or regulation) could cause the estimated quantities and net present value of our reserves to differ materially.  In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and developmental drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.  Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

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. In addition, the effects of derivative instruments are not reflected in these assumed prices. Our December 31, 2015 reserve report used SEC pricing of $2.58 per Mcf for natural gas, $50.28 per Bbl for oil and $15.84 per Bbl for natural gas liquids. These prices are higher than current 2016 prices for oil and natural gas.

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A significant portion of total proved reserves as of December 31, 2015 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2015, approximately 54%, 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, including approximately $379 million during the five years ending in 2020. 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 Project 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. If prices remain at their current levels, we anticipate a significant portion of our long-term EOR-related proved undeveloped reserves may be uneconomic and thus omitted from our estimates of total proved reserves in the near future.

Some of our reserves are subject to EOR methods and the failure of these methods may have a material adverse effect on our financial condition, results of operations and reserves.

The 84.8 MMBoe of reserves on our active EOR Project Areas as of December 31, 2015, were based on EOR methods, including the injection of CO2, and represent approximately 55% of our total proved reserves. Some of these properties have not been injected with CO2 and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or improvements in anticipated production levels.

We do not currently have a supply of CO2 for all of our unproved properties with CO2 EOR potential, and we cannot assure you that we will be able to obtain such a supply on commercially reasonable terms.  In addition, many of our planned EOR projects will require significant investments in pipeline, compression facilities, and other infrastructure, and we may need to raise additional capital to fund these projects.  We cannot assure you that such funding will be available on commercially reasonable terms.  The availability of CO2 supply and financing of CO2 projects could affect the timing of our planned EOR programs and impact our ability to implement such plans.

Our ability to develop our EOR reserves will depend on whether we can successfully implement our planned EOR programs, and our failure to do so could have a material adverse effect on our financial condition, results of operations and reserves.

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.

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

As of December 31, 2015, undeveloped reserves comprised 75% of the total estimated proved reserves of our active EOR projects. As of December 31, 2015, we expect to incur future development costs of $1.0 billion, including $194.9 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 projects are 69% of our total estimated future development and abandonment costs of $1.5 billion as of December 31, 2015. 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.

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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:

 

·

seeking to acquire desirable producing properties or new leases for future development or exploration; and

 

·

seeking to acquire the equipment and expertise necessary to operate and develop our properties.

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.

Significant capital expenditures are required to replace our reserves.

Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, debt financing, private issuances of common stock and proceeds from asset sales. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. 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.

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. In addition, approximately 54% of our total estimated proved reserves (by volume) at December 31, 2015 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and EOR operations. Our December 31, 2015 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 18%, 15%, and 10% 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 resulted and will continue to result in lower than average 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 like we are currently experiencing in the United States. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

 

·

unexpected drilling conditions;

 

·

title problems;

 

·

pressure or lost circulation in formations;

 

·

equipment failures or accidents;

 

·

decline in commodity prices

35


 

·

adverse weather conditions;

 

·

compliance with environmental and other governmental requirements; and

 

·

increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

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.  

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, 2015, 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.

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 operations and facilities are subject to certain federal, state, and local laws and regulations relating to the exploration for, and development, production, and transportation of, oil and gas, as well as environmental and safety matters. Although we believe that we are in substantial compliance with all applicable laws and regulations, and are currently evaluating the extent of applicability and preparing to comply to the extent applicable with proposed and newly adopted greenhouse gas reporting and permitting requirements, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations such as:

 

·

land use restrictions;

 

·

drilling bonds and other financial responsibility requirements;

 

·

spacing of wells;

 

·

additional reporting, permitting or other limitations on emissions of greenhouse gases;

 

·

additional permitting of air pollutant emissions from oil and natural gas systems at the wellhead and other newly regulated facility components;

 

·

unitization and pooling of properties;

 

·

habitat and endangered species protection, reclamation and remediation, and other environmental protection;

 

·

well stimulation processes;

 

·

produced water disposal;

 

·

CO2 pipeline requirements;

 

·

safety precautions;

 

·

operational reporting; and

 

·

taxation.

Under these laws and regulations, we could be liable for:

 

·

personal injuries;

 

·

property and natural resource damages;

 

·

oil spills and releases or discharges of hazardous materials;

 

·

well reclamation costs;

 

·

remediation and clean-up costs and other governmental sanctions, such as fines and penalties;

36


 

·

other environmental damages; and

 

·

additional reporting and permitting or other issues arising from air pollutants, including greenhouse gas emissions.

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. Additionally, regulations promulgated pursuant to the CAA or other mandatory federal legislation requiring monitoring and reporting of air pollutant emissions continue to evolve and may impose new restrictions on these emissions resulting in liability for exceeding permitted air pollutant emission rates or other mandatory caps on greenhouse gas emissions. While we are preparing for compliance with newly adopted requirements, at this time we are unable to predict the ultimate cost of compliance with these requirements as they continue to evolve or their effect on our operations.  

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Congress has previously considered legislation to reduce emissions of greenhouse gases, including carbon dioxide, methane, and nitrous oxide among others, which some studies have suggested may be contributing to warming of the earth’s atmosphere.  However, at present, federal legislation to reduce greenhouse gases appears uncertain.  As a result, regulation of greenhouse gases, will continue to result primarily from regulatory action by EPA or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.

Federal regulation.  The EPA has adopted regulations requiring that sources of greenhouse gas emissions from stationary sources obtain permits under the CAA.  .  On December 15, 2009, as a result of the U.S. Supreme Court’s decision in Massachusetts, et al. v. EPA finding that greenhouse gases fall within the CAA’s definition of “air pollutant,” EPA promulgated its final “Endangerment” rule under Section 202(a) of the Clean Air Act” finding that concentrations of greenhouse gases in the atmosphere “endanger” public health or welfare and triggering the regulation of greenhouse gases under various provisions of the CAA.  

Under this authority, EPA has promulgated separate regulations addressing greenhouse gas emissions from certain industry sectors, including oil and natural gas production.  On October 30, 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in developing policy approaches to greenhouse gas regulation.  This reporting rule became effective on December 29, 2009.  On November 30, 2010, EPA promulgated additional mandatory greenhouse gas reporting rules that apply specifically to oil and natural gas production for implementation in 2011.  

On August 16, 2012, EPA promulgated new CAA regulations addressing volatile organic compounds (VOCs) and other criteria pollutants, “Oil and Natural Gas Sector:  New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews.”  These new rules are intended to broaden the current scope of EPA’s regulation to include standards governing emissions from most operations associated with oil and natural gas production facilities, natural gas transmission and storage facilities.  EPA states that greenhouse gases will be controlled indirectly as a result of these new rules.  Among other things, these new rules require the use of reduced emission completions or “green completions” on all hydraulically fractured gas wells completed or refractured after January 1, 2015. They also set new requirements for emissions from compressors, controllers, dehydrators, storage vessels and other affected production equipment.

In August 2015, the EPA proposed new 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.  This action was taken despite consensus that industry compliance with EPA's 2012 performance standards has already achieved the targeted methane reductions. The proposed regulations are expected to be finalized in 2016. On January 22, 2016, the Bureau of Land Management issued a pre-publication version of a proposed venting and flaring rule, which is also expected to be finalized in 2016 and, like the forthcoming EPA regulations, will address methane emissions from crude oil and natural gas sources. New regulations 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.  

Recent case law.  Beyond legislative and regulatory developments, litigation against energy industry sectors emitting greenhouse gases have arisen based upon common law claims, that may expose us, as a potential source of significant direct and indirect emission of greenhouse gases, to similar litigation risk.

International treaties.  Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012.

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International developments, passage of state or federal climate control legislation or other regulatory initiatives, the adoption of regulations by EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or development of case law allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and financial condition as a result of material increases in operating and production costs and litigation expense due to expenses associated with monitoring, reporting, permitting and controlling greenhouse gas emissions or litigating claims related to emissions of greenhouse gases, as well as reduced demand for fossil fuels generally.

Climate change and government laws and regulations related to climate change could negatively impact our financial condition.

Scientific studies suggest emissions of certain gases, commonly referred to as "greenhouse gases" ("GHGs") and including carbon dioxide and methane, may contribute to warming of the earth's atmosphere and other climatic changes. In response to such studies, Congress has from time to time considered legislation to reduce emissions of GHGs. One bill approved by the House of Representatives in June 2009 (but never enacted into law), known as the American Clean Energy and Security Act of 2009, would have required an 80% reduction in emissions of GHGs.  In addition, many states have taken measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. In response to its endangerment finding, the EPA adopted two sets of rules regarding possible future regulation of GHG emissions under the CAA. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the "tailoring rule") in May 2010, and it became effective in January 2011. The tailoring rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration (“PSD”) and Title V of the CAA. In June 2014, the Supreme Court held that stationary sources could not become subject to Title V permitting solely by reason of their GHG emissions. However, the Court also ruled the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued initial guidance on GHG permitting requirements in response to the Court's decision, and on April 30, 2015 issued a final rule allowing rescission of PSD permits issued under the portions of the Tailoring Rule which were vacated by the Court. In the interim, the EPA issued a narrowly crafted "no action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit.

In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In December 2014, the EPA published a proposed rule to amend the GHG Reporting Program to add reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The rule underwent an extended public comment period, which closed on February 24, 2015.

The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and are, and most likely will continue to be, affected by government laws and regulations related to climate change. We are currently evaluating compliance costs arising from newly adopted mandatory greenhouse gas reporting rules, and potential compliance costs arising from newly promulgated CAA reporting and permit regulations for greenhouse gas emissions, and are evaluating compliance costs arising from the newly promulgated CAA standards for the oil and natural gas sector. These new regulations could be preempted by new federal legislation if enacted. However, we cannot predict with any degree

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of certainty the ultimate effect possible climate change and government laws and regulations related to climate change will have on our operations. While it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect: (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, (v) the cost of utility services, particularly electricity, in connection with the operation of our properties, and (vi) factors arising from new CAA greenhouse gas permitting and, or, possible greenhouse gas legislation, in addition to previously identified factors. These potential effects depend upon, but are not limited to, the following considerations: whether and to what extent legislation is enacted, the nature of the legislation (such as a cap and trade system or a tax on emissions); the greenhouse gas reductions required pursuant to either existing CAA regulatory requirements or new greenhouse gas legislation; the cost and availability of required offsets or emissions reductions; the amount and allocation of possible allowances; costs required to improve facilities and equipment to both monitor and reduce emissions in order to comply with regulatory limits or to mitigate the financial consequences of a greenhouse gas emission limitations; changes to profit or loss arising from increased or decreased demand for oil and natural gas we produce arising directly from legislation or regulation, and indirectly from changes in production costs. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.

Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash flow from oil and natural gas sales, reduce our liquidity or otherwise alter the way we conduct our business.

In recent years the administration of President Obama made budget proposals which, if enacted into law by Congress, would potentially increase and accelerate the payment of federal income taxes by independent producers of oil and natural gas.  Proposals have included, but have not been limited to, repealing the EOR credit, repealing the credit for oil and gas produced from marginal wells, repealing the expensing of intangible drilling costs, repealing the deduction for the cost of qualified tertiary expenses, repealing the exception to the passive loss limitation for working interests in oil and natural gas properties, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and natural gas companies, and increasing the amortization period of geological and geophysical expenses.  In recent years, legislation which would have implemented the proposed changes was introduced but not enacted.  It is unclear whether legislation supporting any of the above described proposals, or designed to accomplish similar objectives, will be introduced or, if introduced, would be enacted into law or, if enacted, how soon resulting changes would become effective.  However, the passage of any legislation designed to implement changes in the U.S. federal income tax laws similar to the changes included in the budget proposals offered by the White House in recent years could eliminate certain tax deductions currently available with respect to oil and gas exploration and development, and any such changes (i) could make it more costly for us to explore for and develop our oil and natural gas resources and (ii) could negatively affect our financial condition and results of operations.

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.

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 considered 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. Such disclosure could make it easier for third parties opposing the hydraulic fracturing process 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 have slowed while EPA studies 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 the Resource Conservation and Recovery Act 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 waste.

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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 costs 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. On February 16, 2016 the OCC issued a Regional Earthquake Response Plan for Western Oklahoma, and on March 7, 2016 the OCC issued a second Regional Earthquake Response Plan for Central Oklahoma. Combined, the two Plans expand the 2015 “area of interest” and 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 18 wells in the OCC “area of interest” and are fully compliant with all regulations relating to the disposal of produced water.  However, 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 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:

 

·

timing and amount of capital expenditures;

 

·

expertise and diligence in adequately performing operations and complying with applicable agreements;

 

·

financial resources;

 

·

inclusion of other participants in drilling wells; and

 

·

use of technology.

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.

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The loss of our Chief Executive Officer or other key personnel could adversely affect our business.

We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our Chief Executive Officer, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing financing and hedging strategies. Our ability to retain our officers and key employees, or hire replacements if we should lose one or more, is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

Oil and natural gas drilling and production operations can be hazardous and may expose us to environmental 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:

 

·

injury or loss of life;

 

·

severe damage to or destruction of property, natural resources and equipment;

 

·

pollution or other environmental damage;

 

·

cleanup responsibilities;

 

·

regulatory investigations and administrative, civil and criminal penalties; and

 

·

injunctions or other proceedings that suspend, limit or prohibit operations.

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.  

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:

 

·

the uncertainties in estimating cleanup costs;

 

·

the discovery of additional contamination or contamination more widespread than previously thought;

 

·

the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;

 

·

changes in interpretation and enforcement of existing environmental laws and regulations; and

 

·

future changes to environmental laws and regulations and their enforcement.

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, some of which we had previously designated as cash flow hedges for accounting purposes. As of December 31, 2015, we had entered into commodity hedges covering 34,950 BBtu of our natural gas and 4,920 MBbls of our oil and natural gas liquids production from 2016 to 2018. Our commodity hedges are comprised of fixed price swaps, purchased and sold puts, enhanced price

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swaps, basis protection swaps and three way collars with financial institutions. The volumes and average notional prices of these hedges are disclosed in “Note 7—Derivative instruments” in Item 8. Financial Statements and Supplementary Data of this report. The fair value of our oil and gas derivative positions outstanding as of December 31, 2015 was a net asset of approximately $163.2 million.

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

 

·

our production is less than expected;

 

·

the counterparty to the derivative instruments defaults on its contractual obligations; or

 

·

there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative instruments.

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 deemed ineffective, 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.

Our working capital could be adversely affected if we enter into derivative instruments that require cash collateral.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties (i.e. margin requirements). Although we currently do not, and do not anticipate that we will in the future, enter into derivative transactions that require an initial deposit of cash collateral, our working capital, and by extension, our growth, could be impacted if we enter into derivative transactions that require cash collateral and if commodity prices move in a manner adverse to us, we may be required to meet margin calls. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

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:

 

·

our credit ratings;

 

·

interest rates;

 

·

the structured and commercial financial markets;

 

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market perceptions of us or the oil and natural gas exploration and production industry; and

 

·

tax burden due to new tax laws.

Assuming a constant debt level of $550.0 million, equal to our borrowing base at December 31, 2015 under our Credit Facility (our only variable interest rate 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 $5.5 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.

The concentration of accounts for our oil and natural gas sales, joint interest billings, or hedging with third parties could expose us to credit risk.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. The concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced any material credit losses on our receivables. Future concentrations of sales of oil and  natural gas to a limited number of customers, combined with decreases in commodity prices could result in adverse effects.

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In addition, our oil and natural gas swaps or other hedging contracts expose us to credit risk in the event of non-performance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically we have not experienced any credit losses. We believe that the guarantee of a fixed price for the volume of oil and natural gas hedged reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk. However, as also discussed along with other risks specific to hedging activities, we may be exposed to greater credit risk in the future.

Competition for experienced technical personnel may negatively impact our operations or financial results.

Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals.  Competition for these professionals remains strong and we are likely to continue to experience increased costs to attract and retain these professionals.  Retention of our current employees is made more critical in light of our recent workforce reduction.  Following the recent drop in oil and natural gas prices, in an effort to reduce costs and better position ourselves for ongoing efficient growth, we committed to a company-wide restructuring that, through year-end 2015, included a workforce reduction of 131 employees in our headquarters office and the release of approximately 82 field personnel.

Increased regulatory requirements regarding CO2 pipeline integrity may require us to incur significant capital and operating expenses to comply.

The ultimate costs of compliance with CO2 pipeline integrity regulations are difficult to predict. The majority of the compliance costs are for pipeline integrity testing and the repairs found to be necessary. We plan to continue our efforts to assess and maintain the integrity of our existing and future pipelines as required by the U.S. DOT 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 CO2  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.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease funds available for servicing our debt obligations and other operating expenses.

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.

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, Texas and Louisiana, 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 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.  

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The adoption of The Dodd-Frank Wall Street Reform and Consumer Protection Act could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.

In July of 2010, Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. Certain companies that use swaps or other derivatives to hedge commercial risk, referred to as end-users, are permitted to continue to use OTC derivatives under newly adopted regulations. We maintain an active price and basis protection hedging program related to the natural gas and oil we produce to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. We have used the OTC market exclusively for our natural gas and oil derivative contracts. The Dodd-Frank Act and the rules and regulations promulgated thereunder should permit us, as an end user, to continue to utilize OTC derivatives. However, we may have increased costs or reduced liquidity in the OTC derivatives market due to the current or future regulations. Such changes could materially reduce our hedging opportunities and negatively affect our revenues and cash flow during periods of low commodity prices.

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs and new operating restrictions, loss of leasehold or delays on our operations, which could adversely affect our results of operations and financial condition.

The federal Endangered Species Act (“ESA”) and analogous state laws regulate a variety of activities that may have an adverse effect on 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 and the Lesser Prairie Chicken both have habitat in some areas where we operate. In addition to subjecting us to potential enforcement actions if our operations result in a “taking” of a protected species or disturbance of habitat, the presence of these 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.

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

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 Farms Case”) 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. 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. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification and responsive briefs were filed in the fourth quarter of 2015, and we expect a hearing on class certification to be held in the second quarter of 2016.  We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among 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 outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated, if the class is certified, they seek damages in excess of $5 million which may increase with the passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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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 allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams 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 this time, a class has not been certified and discovery has not yet commenced.  We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among 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 outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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 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. We have joined in Motions to Dismiss filed by the defendants, which is still pending.  In a case with similar claims, also pending in the United States District Court for the Northern District of Oklahoma, the court determined the Bureau of Indian Affairs violated the National Environmental Protection act by not conducting environmental assessments before granting leases and permits on Osage tribal lands in Osage County, Oklahoma, and therefore found both the lease and the two related drilling permits void ab initio.  At this time, discovery has commenced and is ongoing.  A class has not been certified. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.  We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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 Cleveland, Lincoln, McClain, Okfuskee, Oklahoma, Pontotoc, Pottawatomie and Seminole Counties, 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 our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief.  The plaintiffs have not asked for damages related to actual property damage which may have occurred.  We have 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.  We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the West Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented, and uncertainties with respect to, among 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 outcome of the matter. We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action 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. 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.

 

45


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 25, 2016, we had 1,393,565 shares of common stock outstanding held by 19 record holders.

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 currently restricted in our ability to pay dividends under our 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.  

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, 2015 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.  

 

 

 

Year ended December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

 

2012

 

 

2011

 

Operating results data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Commodity sales

 

$

324,315

 

 

$

681,557

 

 

$

591,674

 

 

$

509,503

 

 

$

530,041

 

Gain (loss) from oil and natural gas hedging activities

 

 

 

 

 

 

 

 

37,134

 

 

 

46,746

 

 

 

(27,452

)

Other revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

4,070

 

Total revenues

 

 

324,315

 

 

 

681,557

 

 

 

628,808

 

 

 

556,249

 

 

 

506,659

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

110,659

 

 

 

141,608

 

 

 

132,690

 

 

 

122,829

 

 

 

117,445

 

Transportation and processing

 

 

8,541

 

 

 

8,295

 

 

 

7,081

 

 

 

8,131

 

 

 

3,975

 

Production tax

 

 

9,953

 

 

 

28,305

 

 

 

33,266

 

 

 

32,003

 

 

 

34,321

 

Depreciation, depletion and amortization

 

 

216,574

 

 

 

245,908

 

 

 

192,426

 

 

 

169,307

 

 

 

146,083

 

Loss on impairment of oil & natural gas assets

 

 

1,491,129

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss on impairment of other assets

 

 

16,207

 

 

 

 

 

 

3,490

 

 

 

2,000

 

 

 

 

General and administrative

 

 

39,089

 

 

 

53,414

 

 

 

53,883

 

 

 

49,812

 

 

 

42,056

 

Cost reduction initiatives and other expenses

 

 

10,028

 

 

 

 

 

 

 

 

 

 

 

 

3,448

 

Total costs and expenses

 

 

1,902,180

 

 

 

477,530

 

 

 

422,836

 

 

 

384,082

 

 

 

347,328

 

Operating (loss) income

 

 

(1,577,865

)

 

 

204,027

 

 

 

205,972

 

 

 

172,167

 

 

 

159,331

 

Non-operating income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(112,400

)

 

 

(104,241

)

 

 

(96,876

)

 

 

(98,402

)

 

 

(96,720

)

Non-hedge derivative gains (losses)

 

 

145,288

 

 

 

231,320

 

 

 

(21,635

)

 

 

49,685

 

 

 

34,408

 

Gain (loss) on extinguishment of debt

 

 

31,590

 

 

 

 

 

 

 

 

 

(21,714

)

 

 

(20,592

)

Other income, net

 

 

2,324

 

 

 

2,630

 

 

 

1,075

 

 

 

504

 

 

 

1,545

 

Net non-operating income (expense)

 

 

66,802

 

 

 

129,709

 

 

 

(117,436

)

 

 

(69,927

)

 

 

(81,359

)

(Loss) income before income taxes

 

 

(1,511,063

)

 

 

333,736

 

 

 

88,536

 

 

 

102,240

 

 

 

77,972

 

Income tax (benefit) expense

 

 

(177,219

)

 

 

124,443

 

 

 

32,849

 

 

 

37,837

 

 

 

35,924

 

Net (loss) income

 

$

(1,333,844

)

 

$

209,293

 

 

$

55,687

 

 

$

64,403

 

 

$

42,048

 

Cash flow data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

19,608

 

 

$

323,911

 

 

$

264,053

 

 

$

192,000

 

 

$

259,616

 

Net cash used in investing activities

 

 

(37,258

)

 

 

(412,222

)

 

 

(515,122

)

 

 

(423,246

)

 

 

(324,998

)

Net cash provided by financing activities

 

 

3,223

 

 

 

71,208

 

 

 

269,845

 

 

 

226,476

 

 

 

44,860

 

46


 

 

 

 

As of December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

 

2012

 

 

2011

 

Financial position data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

17,065

 

 

$

31,492

 

 

$

48,595

 

 

$

29,819

 

 

$

34,589

 

Total assets

 

 

1,204,739

 

 

 

2,831,816

 

 

 

2,397,882

 

 

 

2,007,552

 

 

 

1,669,733

 

Total debt

 

 

1,607,127

 

 

 

1,633,802

 

 

 

1,562,862

 

 

 

1,293,402

 

 

 

1,034,573

 

(Accumulated deficit) retained earnings

 

 

(1,051,678

)

 

 

282,166

 

 

 

72,873

 

 

 

17,186

 

 

 

(47,217

)

Accumulated other comprehensive income, net of

   income taxes

 

 

 

 

 

 

 

 

 

 

 

23,223

 

 

 

51,846

 

Total stockholders’ (deficit) equity

 

 

(620,357

)

 

 

711,858

 

 

 

497,264

 

 

 

462,857

 

 

 

424,013

 

 

 

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 pure play 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, Woodford and Hunton formations. In addition, we have significant holdings in the Mississippi Lime play and a leadership position in CO2 EOR where we are now the third largest CO2 EOR operator in the United States based on the number of active projects. This position is 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, 2015, we had estimated proved reserves of 155.5 MMBoe with a PV-10 value of approximately $731 million using SEC pricing as of the same date. These estimated proved reserves included 84.8 MMBoe of active EOR reserves. Our reserves were 46% proved developed, 73% crude oil, 19% natural gas and 8% natural gas liquids.

Generally, our producing properties have declining production rates.  Our December 31, 2015 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 18%, 15%, and 10% 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.

Financial and Operating Performance

Our financial and operating performance includes the following highlights:

 

·

We incurred a net loss of $1,334 million primarily driven by the large ceiling-test impairment we recorded during the year.

 

·

We recorded ceiling test impairments of our oil and natural gas properties during the second, third and fourth quarters for a total of $1,491 million in 2015 as a result of depressed commodity prices.

 

·

Due to a reduction in oil and natural gas capital expenditures from $740 million in the prior year to $209 million in 2015, we experienced a year-over-year and fourth quarter-over-fourth quarter decline in net production of 7% and 18%, respectively. Our net production for 2015 was 10,200 MBoe.

 

·

Our commodity sales in 2015 were $324 million or 52% lower than the prior year primarily due to a 49% decrease in our average sales price per Boe and to a lesser extent, due to the production decline mentioned above.

47


 

·

Our lease operating and general and administrative expenses of $110.7 million and $39.1 million, respectively, were 22% and 27% lower than the prior year as a result of our cost reduction initiatives in response to industry conditions.

 

·

We received $233.6 million from settlement of our commodity derivative contracts in 2015 compared to $2.4 million in the prior year. Our total non-hedge derivative gain was $145.3 million in 2015 compared to $231.3 million in the prior year.

 

·

Our cost reduction initiatives included a reduction in our workforce of 213 employees in 2015. Related to these initiatives, we recorded charges of $7.7 million for one-time severance and termination benefits and $2.3 million legal and professional services.

 

·

We recorded 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.

 

·

We repurchased $42.0 million in principal value of our Senior Notes for $10.0 million in cash and recorded a gain of $31.6 million on the early extinguishment. The Senior Notes were repurchased to benefit from their low trading price at the time and to reduce future interest costs.

2016 Outlook

The oil and gas industry is cyclical and commodity prices are volatile. Three crucial drivers of global crude oil prices are: OPEC crude oil supply, non-OPEC crude oil supply and global crude oil demand. 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 tepid global economic growth especially in Europe, coupled with slower growth in China. Crude oil prices began softening in third quarter 2014, and fell quickly in November 2014 following OPEC’s decision not to reduce production quotas. During 2015, prices fell to multi-year lows and the lowest levels since the 2008 financial crisis. Thus far, there has been minimal price recovery in 2016. Prices have fallen on numerous occasions into the $20’s, their lowest level since 2003. NYMEX crude oil futures continue to be weak. The outlook for crude oil prices during 2016 depends primarily on supply and demand dynamics and global security concerns in crude oil-producing nations. Production levels will be a primary determinant for 2016. If, during 2016, OPEC maintains its position against cutting production, prices may remain low or move lower. Furthermore, record crude oil inventories exert downward pressure on prices. On the demand side, recent projections have reduced anticipated global crude oil demand growth for 2016 and Chinese economic indicators continue to soften which supports the current oversupply situation and a soft pricing environment. If prices remain at lower levels, producers are expected to reduce investment which will, over time, reduce production, helping to balance supply and demand in the crude oil market over the longer term.

The United States domestic natural gas market continues to be oversupplied. Prices remained weak in 2015, falling to multi-year lows. Domestic production growth outstripped demand growth in 2015 driven by drilling efficiency and a backlog of drilled but uncompleted wells that came online with completion of new pipeline infrastructure. Although the pace of drilling has slowed, it is possible that there may not be much improvement in the domestic natural gas supply and demand balance and that oversupply will persist, which could lead to continued price softness in 2016.

Low Price Environment Initiatives

Management's plans and related capital projections for 2015 were reflective of lower commodity prices. In response to the decrease in crude oil prices, in early 2015, we began implementation of a company-wide effort to decrease our capital, operating and administrative costs. Our cost reduction initiatives included a reduction in our workforce in 2015 of 213 employees, of which 131 were located in the Oklahoma City headquarters office and 82 were located at various field offices. In connection with our workforce reduction, we recorded charges of $7.7 million related to one-time severance and termination benefits in 2015. During 2016, we have reduced our workforce by an additional 61 employees and estimate the cost of one-time severance and special termination benefits related to these 2016 terminations to be approximately $3.1 million.

As part of our cost reduction initiatives, we engaged third party legal and professional services for which we incurred expenses of approximately $2.3 million in 2015. We are allowed to exclude up to $25.0 million of expenses incurred in connection with our cost reduction initiatives, including costs related to our workforce reduction, from our EBITDA-based covenant under our Credit Facility.

We have aggressively pursued reductions in our drilling and completion costs, lease operating expenses and general and administrative expenses. Our cost reduction efforts included targeting price concessions from third party vendors, delaying completions of wells drilled early in the year into the second half of the year and other operational efficiencies. As a result our efforts, lease operating and general and administrative expenses and were 22% and 27%, respectively, lower in 2015 compared to the prior

48


year. Furthermore our average per well drilling and completion costs in 2015 are approximately lower by 30-40% from compared to the prior year.

We significantly reduced our 2015 capital expenditure to less than one-third the amount spent in 2014. Faced with a lack of recovery in prices in early 2016, we have trimmed our 2016 capital budget to $110.6 million, approximately half of our spending in 2015.

Price Uncertainty and the Full-Cost Ceiling Impairment

The current oil price environment is characterized by a high degree of volatility and uncertainty. During January 2016, daily changes in crude oil prices were highly correlated with daily changes in global equity indexes. The increased co-movement and higher volatility likely reflect increased uncertainty about future global economic growth. Based on NYMEX forward prices as of March 24, 2016, the average WTI crude price for the remainder of 2016 and for 2017 is expected to be $41.91/barrel and $44.82/barrel, respectively. Based on the implied volatility in early March 2016 from WTI futures contracts for June 2016 delivery, the U.S. Energy Information Administration (“EIA”) estimates an implied volatility of 50%, suggesting lower and upper limits of the 95% confidence interval for the market's expectations of monthly average WTI prices in June 2016 at $24/barrel and $58/barrel, respectively. The 95% confidence interval for market expectations widens over time, with lower and upper limits of $20/barrel and $81/barrel for prices in December 2016.

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, as well as by aggressively pursuing cost reductions in a market downturn. 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.  Based on NYMEX forward prices as of March 24, 2016, we have 4.4 million barrels of crude oil production hedged in 2016 at an average of $68.63 per barrel and 14,000 BBtu of natural gas production hedged at an average of $4.19/MMBtu. The prices we receive for our oil and natural gas production affect our:

cash flow available for capital expenditures;

ability to borrow and raise additional capital;

ability to service debt;

quantity of oil and natural gas we can produce;

quantity of oil and natural gas reserves; and

operating results for oil and natural gas activities.

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. At year-end 2014, those prices were $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas, and at year-end 2015, they have fallen to $50.28 per Bbl and $2.58 per MMBtu, respectively. As a result of the decline in average prices, we recorded a ceiling test write-down of $1.5 billion during 2015. Since the prices used in the cost ceiling are based on a trailing 12-month period, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the price change on the financial statements over several reporting periods. While the amount of any future impairment is generally difficult to predict, the average prices used in the ceiling test calculation at March 31, 2016 will be $46.26 per Bbl for oil and $2.39 per MMBtu for natural gas. This decline from the prior quarter will result in a further write-down in the first quarter of 2016, which we expect to be in the range of $175 million to $225 million. Continued write-downs of oil and natural gas properties may occur until such time as commodity prices recover, and remain at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling test calculation. 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.

2016 Capital Program

We have reduced our 2016 capital budget to $110.6 million or approximately half of our capital spending in 2015. We have allocated $50.7 million of the budget to drilling activities which will predominantly focus on drilling in the high-return area within our

49


STACK acreage. While we began the year with three drilling rigs, we have reduced down to one drilling rig as of March 2016 which we expect to operate in our STACK play until the third quarter of 2016. Our 2016 drilling plans includes drilling 13 wells within our STACK play, of which nine wells will be in completed in 2016 and four wells completed the following year, and completing five wells which were previously drilled in 2015. A portion of our drilling budget has been allocated for us to participate in wells drilled by other operators for which we own a joint interest. We have also directed $44.8 million of our 2016 capital budget to our EOR project areas primarily to expand a limited number of new patterns at our North Burbank Unit, to purchase CO2 and for maintenance.

Our 2016 capital budget is predicated upon successful restructuring of our outstanding indebtedness, which is discussed in “Liquidity and Capital Resources.” We will continue to monitor our capital spending in 2016 closely and may adjust our spending accordingly based on the outcome of our debt restructuring activities, actual and projected cash flows, our liquidity and our capital requirements.

Results of Operations

Overview

Total production, commodity sales, and cash flow increased from 2013 to 2014 but decreased from 2014 to 2015. Commodity sales decreased from 2014 to 2015 primarily as a result of depressed prices coupled to a lesser extent by a decline in production. Production decreased from 2014 to 2015 due to divestitures, natural decline and shutting-in of marginal wells, all of which were not fully offset by new development as we pared back our capital expenditure in 2015. We recorded a net loss of $1.3 billion in 2015 largely driven by a ceiling test impairment of $1.5 billion on our oil and natural gas properties recorded as a result of depressed pricing. The reduction in commodity sales in 2015 was partially mitigated by our hedging program where we received $233.6 million from our derivatives that matured during the year.

Commodity sales increased from 2013 to 2014 primarily as a result of increased oil and natural gas production, higher natural gas and NGL prices and a continuing shift in our commodity sales mix towards liquids. This increase in 2014 from 2013 was combined with a $253.0 million increase in our non-hedge derivative gains, which was primarily due to the decline in of oil and natural gas prices that occurred in late 2014.

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

change

 

 

2013

 

 

(Decrease)

 

 

change

 

Production (MBoe)

 

 

10,200

 

 

 

10,982

 

 

 

(782

)

 

 

(7.1

)%

 

 

9,742

 

 

 

1,240

 

 

 

12.7

%

Commodity sales (in thousands)

 

$

324,315

 

 

$

681,557

 

 

$

(357,242

)

 

 

(52.4

)%

 

$

591,674

 

 

$

89,883

 

 

 

15.2

%

Net (loss) income (in thousands)

 

$

(1,333,844

)

 

$

209,293

 

 

$

(1,543,137

)

 

 

(737.3

)%

 

$

55,687

 

 

$

153,606

 

 

 

275.8

%

Cash flow from operations (in thousands)

 

$

19,608

 

 

$

323,911

 

 

$

(304,303

)

 

 

(93.9

)%

 

$

264,053

 

 

$

59,858

 

 

 

22.7

%

 

Production

 

Production volumes by area were as follows (MBoe):

 

 

 

Year Ended

 

 

 

 

 

 

Year Ended

 

 

 

 

 

 

 

December 31,

 

 

Percentage

 

 

December 31,

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

change

 

 

2013

 

 

change

 

E&P Areas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mississippi Lime

 

 

2,121

 

 

 

1,959

 

 

 

8.3

%

 

 

1,247

 

 

 

57.1

%

STACK - Meramec

 

 

143

 

 

 

42

 

 

 

240.5

%

 

 

 

 

*

 

STACK - Osage

 

 

540

 

 

 

499

 

 

 

8.2

%

 

 

101

 

 

 

394.1

%

STACK - Oswego

 

 

417

 

 

 

336

 

 

 

24.1

%

 

 

 

 

*

 

STACK - Woodford

 

 

527

 

 

 

416

 

 

 

26.7

%

 

 

69

 

 

 

488.4

%

Panhandle Marmaton

 

 

600

 

 

 

1,051

 

 

 

(42.9

)%

 

 

324

 

 

 

224.4

%

Legacy Production Areas

 

 

2,434

 

 

 

3,521

 

 

 

(30.9

)%

 

 

5,065

 

 

 

(30.5

)%

Total E&P Areas

 

 

6,782

 

 

 

7,824

 

 

 

(13.3

)%

 

 

6,806

 

 

 

15.0

%

EOR Project Areas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Active EOR Projects

 

 

2,228

 

 

 

1,834

 

 

 

21.5

%

 

 

1,514

 

 

 

21.1

%

Potential EOR Projects

 

 

1,190

 

 

 

1,324

 

 

 

(10.1

)%

 

 

1,422

 

 

 

(6.9

)%

Total EOR Project Areas

 

 

3,418

 

 

 

3,158

 

 

 

8.2

%

 

 

2,936

 

 

 

7.6

%

Total

 

 

10,200

 

 

 

10,982

 

 

 

(7.1

)%

 

 

9,742

 

 

 

12.7

%

50


 

Production decreased in 2015 compared to 2014 due to a production decline in our E&P Areas partially offset by higher production in our EOR Project Areas. The year-over-year decrease in our E&P 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 in our Legacy Production Areas 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 due to our drilling and development activities in our STACK play and outside-operated production in our Mississippi Lime play. The year-over-year increases in our EOR Project Areas are primarily due to production response in our North Burbank Unit and Farnsworth Unit offset partially by decreases in potential EOR Project Areas as a result of the temporary shut-in of marginal wells and normal production declines.

 

Production increased in 2014 compared to 2013 in both our E&P Areas and EOR Project Areas. The increase in production in our E&P Areas is primarily due to our drilling and development activities in our Mississippi Lime, Panhandle Marmaton and STACK plays as well as our acquisition of oil and natural gas properties from Cabot Oil and Gas Corporation in late 2013. These increases were partially offset by decreased production in our Legacy Production Areas which was a result of divestitures in 2014, discussed above, and natural well decline as we invested resources in our other plays. Production in our EOR Project Areas increased primarily due to response from our CO2 injection activities in our Farnsworth Area and North Burbank Units. We commenced CO2 injection at our North Burbank Unit in June 2013 where we observed an initial response in late 2013 followed by a more significant response developing in early 2014.

 

Revenues

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

 

 

 

Year Ended

 

 

 

 

 

 

 

 

 

 

Year Ended

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

change

 

 

2013

 

 

(Decrease)

 

 

change

 

Commodity sales (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

$

255,389

 

 

$

540,940

 

 

 

(285,551

)

 

 

(52.8

)%

 

$

475,976

 

 

$

64,964

 

 

 

13.6

%

Natural gas

 

 

45,560

 

 

 

86,100

 

 

 

(40,540

)

 

 

(47.1

)%

 

 

70,526

 

 

 

15,574

 

 

 

22.1

%

Natural gas liquids

 

 

23,366

 

 

 

54,517

 

 

 

(31,151

)

 

 

(57.1

)%

 

 

45,172

 

 

 

9,345

 

 

 

20.7

%

Total

 

$

324,315

 

 

$

681,557

 

 

$

(357,242

)

 

 

(52.4

)%

 

$

591,674

 

 

$

89,883

 

 

 

15.2

%

Production

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbls)

 

 

5,519

 

 

 

5,977

 

 

 

(458

)

 

 

(7.7

)%

 

 

5,006

 

 

 

971

 

 

 

19.4

%

Natural gas (MMcf)

 

 

18,788

 

 

 

20,648

 

 

 

(1,860

)

 

 

(9.0

)%

 

 

20,250

 

 

 

398

 

 

 

2.0

%

Natural gas liquids (MBbls)

 

 

1,550

 

 

 

1,564

 

 

 

(14

)

 

 

(0.9

)%

 

 

1,361

 

 

 

203

 

 

 

14.9

%

MBoe

 

 

10,200

 

 

 

10,982

 

 

 

(782

)

 

 

(7.1

)%

 

 

9,742

 

 

 

1,240

 

 

 

12.7

%

Average sales prices (excluding derivative settlements)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil per Bbl

 

$

46.27

 

 

$

90.50

 

 

$

(44.23

)

 

 

(48.9

)%

 

$

95.08

 

 

 

(4.58

)

 

 

(4.8

)%

Natural gas per Mcf

 

$

2.42

 

 

$

4.17

 

 

$

(1.75

)

 

 

(42.0

)%

 

$

3.48

 

 

 

0.69

 

 

 

19.8

%

Natural gas liquids per Bbl

 

$

15.07

 

 

$

34.86

 

 

$

(19.79

)

 

 

(56.8

)%

 

$

33.19

 

 

 

1.67

 

 

 

5.0

%

Average sales price per Boe

 

$

31.80

 

 

$

62.06

 

 

$

(30.26

)

 

 

(48.8

)%

 

$

60.73

 

 

 

1.33

 

 

 

2.2

%

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 were most pronounced in our Panhandle Marmaton and Legacy Production Areas while the production decline in natural gas was predominantly in our Legacy Production Areas. As discussed above, these decreases were largely a result of asset divestitures, decreased development, shutting-in marginal wells and natural well declines.

Commodity sales increased from 2013 to 2014 largely due to production increases in our Mississippi Lime, Panhandle Marmaton and STACK plays partially offset by production decreases in our Legacy Production Areas. Although there was an observed price increase on a barrel of oil equivalent basis, the unfavorable impact from the price decline on oil more than offset the gains from price increases in natural gas and natural gas liquids. The oil price decrease in 2014 reflects the downward trajectory of oil prices that began around October 2014.

51


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:

 

 

 

Year ended December 31,

 

 

 

2015 vs. 2014

 

 

2014 vs. 2013

 

(dollars in thousands)

 

Sales

change

 

 

Percentage

change

in sales

 

 

Sales

change

 

 

Percentage

change

in sales

 

Change in oil sales due to:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prices

 

$

(244,100

)

 

 

(45.1

)%

 

$

(27,360

)

 

 

(5.8

)%

Production

 

 

(41,451

)

 

 

(7.7

)%

 

 

92,324

 

 

 

19.4

%

Total change in oil sales

 

$

(285,551

)

 

 

(52.8

)%

 

$

64,964

 

 

 

13.6

%

Change in natural gas sales due to:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prices

 

$

(32,784

)

 

 

(38.1

)%

 

$

14,188

 

 

 

20.1

%

Production

 

 

(7,756

)

 

 

(9.0

)%

 

 

1,386

 

 

 

2.0

%

Total change in natural gas sales

 

$

(40,540

)

 

 

(47.1

)%

 

$

15,574

 

 

 

22.1

%

Change in natural gas liquids sales due to:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Prices

 

$

(30,663

)

 

 

(56.2

)%

 

$

2,607

 

 

 

5.8

%

Production

 

 

(488

)

 

 

(0.9

)%

 

$

6,738

 

 

 

14.9

%

Total change in natural gas liquid sales

 

$

(31,151

)

 

 

(57.1

)%

 

$

9,345

 

 

 

20.7

%

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, costless collars, put options, and basis protection swaps. These derivative instruments allow us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. We also enter into crude oil derivative contracts for a portion of our natural gas liquids production.

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:

 

 

 

Year ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Oil and natural gas liquids (per Bbl):

 

 

 

 

 

 

 

 

 

 

 

 

Before derivative settlements

 

$

39.43

 

 

$

78.96

 

 

$

81.85

 

After derivative settlements

 

$

68.13

 

 

$

80.21

 

 

$

83.32

 

Post-settlement to pre-settlement price

 

 

172.8

%

 

 

101.6

%

 

 

101.8

%

Natural gas (per Mcf):

 

 

 

 

 

 

 

 

 

 

 

 

Before derivative settlements

 

$

2.42

 

 

$

4.17

 

 

$

3.48

 

After derivative settlements

 

$

4.05

 

 

$

3.83

 

 

$

3.97

 

Post-settlement to pre-settlement price

 

 

167.6

%

 

 

91.8

%

 

 

114.1

%

 

52


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.

 

 

 

As of December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

Derivative assets (liabilities):

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas swaps

 

$

41,328

 

 

$

32,939

 

 

$

(2,249

)

Oil swaps

 

 

 

 

 

23,465

 

 

 

(2,695

)

Oil collars

 

 

6,500

 

 

 

1,175

 

 

 

2,772

 

Oil enhanced swaps

 

 

45,516

 

 

 

100,724

 

 

 

776

 

Oil purchased and sold puts

 

 

71,052

 

 

 

93,268

 

 

 

74

 

Natural gas basis differential swaps

 

 

(1,158

)

 

 

(17

)

 

 

1,643

 

Net derivative asset

 

$

163,238

 

 

$

251,554

 

 

$

321

 

 

The fluctuation in non-hedge derivative gains (losses) 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:

 

 

 

Year ended

 

 

 

 

 

 

Year ended

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

December 31,

 

 

Increase /

 

(in thousands)

 

2015

 

 

2014

 

 

(Decrease)

 

 

2013

 

 

(Decrease)

 

Non-hedge derivative gains (losses)

 

$

145,288

 

 

$

231,320

 

 

$

(86,032

)

 

$

(21,635

)

 

$

252,955

 

 

 

 

Year ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

(in thousands)

 

Non-cash

fair value

adjustment

 

 

Cash

receipts

(payments)

 

 

Non-cash

fair value

adjustment

 

 

Cash

receipts

(payments)

 

 

Non-cash

fair value

adjustment

 

 

Cash

receipts

(payments)

 

Gain (loss) from oil hedging activities

 

$

 

 

$

 

 

$

 

 

$

 

 

$

37,134

 

 

$

 

Non-hedge derivative gains (losses):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil swaps, collars, and puts

 

$

(95,565

)

 

$

202,889

 

 

$

197,097

 

 

$

9,433

 

 

$

(29,586

)

 

$

9,330

 

Natural gas swaps

 

 

8,389

 

 

 

30,999

 

 

 

33,466

 

 

 

(6,437

)

 

 

(14,404

)

 

 

10,340

 

Natural gas basis differential contracts

 

 

(1,141

)

 

 

(283

)

 

 

(1,660

)

 

 

(579

)

 

 

3,242

 

 

 

(557

)

Non-hedge derivative gains (losses)

 

$

(88,317

)

 

$

233,605

 

 

$

228,903

 

 

$

2,417

 

 

$

(40,748

)

 

$

19,113

 

Total gains (losses) from derivative activities

 

$

(88,317

)

 

$

233,605

 

 

$

228,903

 

 

$

2,417

 

 

$

(3,614

)

 

$

19,113

 

 

Gain from oil hedging activities, which is a component of total revenues in our consolidated statements of operations, consists of the reclassification of hedge gains on discontinued oil hedges from accumulated other comprehensive income into net income. Since 2014, we no longer 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 gains (losses) in our consolidated statements of operations.

On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels 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 Credit Facility. The proceeds are included in the cash receipts related to the gains (losses) from derivative activities in the table above.

During the third quarter of 2015, we entered into offset positions on 1,100,000 barrels of outstanding swaps, scheduled to mature between September to December 2015, thereby locking-in the difference between the contract price of our prior swaps and the contract price of the offset swaps, which we received when the contracts settled. The locked-in proceeds are included in the receipts related to the gains (losses) from derivative activities in the table above.

53


Lease Operating Expenses 

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

change

 

 

2013

 

 

(Decrease)

 

 

change

 

Lease operating expenses (in thousands, except

   per Boe data)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

E&P Areas

 

$

48,050

 

 

$

68,720

 

 

$

(20,670

)

 

 

(30.1

)%

 

$

71,116

 

 

$

(2,396

)

 

 

(3.4

)%

EOR Project Areas

 

 

62,609

 

 

 

72,888

 

 

 

(10,279

)

 

 

(14.1

)%

 

 

61,574

 

 

 

11,314

 

 

 

18.4

%

Total lease operating expenses

 

$

110,659

 

 

$

141,608

 

 

$

(30,949

)

 

 

(21.9

)%

 

$

132,690

 

 

$

8,918

 

 

 

6.7

%

Lease operating expenses per Boe

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

E&P Areas

 

$

7.08

 

 

$

8.78

 

 

$

(1.70

)

 

 

(19.4

)%

 

$

10.45

 

 

$

(1.67

)

 

 

(16.0

)%

EOR Project Areas

 

 

18.32

 

 

 

23.08

 

 

 

(4.76

)

 

 

(20.6

)%

 

 

20.97

 

 

 

2.11

 

 

 

10.1

%

Lease operating expenses per Boe

 

$

10.85

 

 

$

12.89

 

 

$

(2.04

)

 

 

(15.8

)%

 

$

13.62

 

 

$

(0.73

)

 

 

(5.4

)%

 

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 for both our E&P Areas and EOR Project Areas decreased from 2014 to 2015 on an absolute dollar and on a Boe basis. 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 during the current year also contributed to the decrease in total expense. During 2014, we divested certain non-core assets with higher operating costs. These divestitures were largely completed by mid-July 2014, and have therefore contributed to a decrease in lease operating expense when comparing the 2015 to the prior year period.

Our E&P Areas lease operating expenses decreased slightly during 2014 compared to 2013, primarily as a result of the divestiture of certain non-core assets with higher operating costs partially offset by the incremental cost of oil field goods and services associated with new wells added during 2014. Our lease operating expenses on a Boe basis decreased significantly in 2014 compared to 2013 primarily as a result of the increase in overall production volumes between periods as well as the impact of our divestiture of our non-core higher operating cost properties.

Our EOR Project Areas lease operating expenses increased during 2014 compared to 2013, due primarily to additional costs associated with expansion of our EOR floods at our North Burbank and Farnsworth Units. While production for our North Burbank Unit increased compared to 2013, its production in 2014 was relatively low because production was still ramping up, resulting in higher per-barrel operating costs.

Transportation and Processing Expenses

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

change

 

 

2013

 

 

(Decrease)

 

 

change

 

Transportation and processing expenses (in thousands)

 

$

8,541

 

 

$

8,295

 

 

$

246

 

 

 

3.0

%

 

$

7,081

 

 

$

1,214

 

 

 

17.1

%

Transportation and processing expenses per BOE

 

$

0.84

 

 

$

0.76

 

 

$

0.08

 

 

 

10.5

%

 

$

0.73

 

 

$

0.03

 

 

 

4.1

%

54


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 in 2015 compared to 2014. Expense was higher in 2014 compared to 2013 due to the 15% increase in natural gas liquids volumes processed, primarily driven by new wells that came online in 2014. A certain number of these new wells were outside-operated wells that had substantially higher per unit processing costs compared.

Production Taxes (which include ad valorem taxes) 

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

change

 

 

2013

 

 

(Decrease)

 

 

change

 

Production taxes (in thousands)

 

$

9,953

 

 

$

28,305

 

 

$

(18,352

)

 

 

(64.8

)%

 

$

33,266

 

 

$

(4,961

)

 

 

(14.9

)%

Production taxes per Boe

 

0.98

 

 

$

2.58

 

 

$

(1.60

)

 

 

(62.0

)%

 

$

3.41

 

 

$

(0.83

)

 

 

(24.3

)%

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.

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 Legacy Production Areas, which generally had higher tax rates, and reduced tax rates for horizontal drilling and our EOR projects.

The 2014 decrease in production taxes from 2013 was primarily due to our strategic divestitures of non-core properties within our Legacy Production Areas, which generally had higher tax rates, combined with reduced tax rates for horizontal drilling along with EOR and high cost gas exemption tax credits, partially offset by the 13% increase in sales volumes combined with the 2% increase in averaged realized prices.

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

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

Year ended

 

 

 

 

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

December 31,

 

 

Increase /

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

change

 

 

2013

 

 

(Decrease)

 

 

change

 

DD&A (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas properties

 

$

204,692

 

 

$

231,761

 

 

$

(27,069

)

 

 

(11.7

)%

 

$

179,734

 

 

$

52,027

 

 

 

28.9

%

Property and equipment

 

 

8,222

 

 

 

10,179

 

 

 

(1,957

)

 

 

(19.2

)%

 

 

8,747

 

 

 

1,432

 

 

 

16.4

%

Accretion of asset retirement obligations

 

 

3,660

 

 

 

3,968

 

 

 

(308

)

 

 

(7.8

)%

 

 

3,945

 

 

 

23

 

 

 

0.6

%

Total DD&A

 

$

216,574

 

 

$

245,908

 

 

$

(29,334

)

 

 

(11.9

)%

 

$

192,426

 

 

$

53,482

 

 

 

27.8

%

DD&A per Boe:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas properties

 

$

20.07

 

 

$

21.10

 

 

$

(1.03

)

 

 

(4.9

)%

 

$

18.45

 

 

$

2.65

 

 

 

14.4

%

Other fixed assets

 

 

1.16

 

 

 

1.29

 

 

 

(0.13

)

 

 

(10.1

)%

 

 

1.30

 

 

 

(0.01

)

 

 

(0.8

)%

Total DD&A per Boe

 

$

21.23

 

 

$

22.39

 

 

$

(1.16

)

 

 

(5.2

)%

 

$

19.75

 

 

$

2.64

 

 

 

13.4

%

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 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 primarily as a result of the ceiling test write-offs that occurred during the second and third quarters of 2015, which subsequently lowered the carrying value of our amortization base. DD&A on oil and natural gas properties increased $52.0 million from 2013 to 2014, of which $29.1 million was due to a higher rate per equivalent unit of production and $22.9 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions. As a result of the ceiling test writeoffs we recorded in 2015, which reduced the carrying value of our oil and natural gas properties, we expect DD&A in 2016 to be lower than 2015.

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

55


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

 

 

 

Year ended

 

 

 

 

 

 

Year ended

 

 

 

 

 

 

 

December 31,

 

 

Increase /

 

 

December 31,

 

 

Increase /

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

2013

 

 

(Decrease)

 

Asset impairments (in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss on impairment of oil and natural gas assets

 

$

1,491,129

 

 

$

 

 

$

1,491,129

 

 

$

 

 

$

 

Loss on impairment of other assets

 

 

16,207

 

 

 

 

 

 

16,207

 

 

 

3,490

 

 

 

(3,490

)

Property impairments. Due to the substantial decline of commodity prices beginning in late 2014, which remain low throughout 2015 the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties at the end of each of the last three quarters resulting in ceiling test write-downs of $1.5 billion recorded in 2015. 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. At year-end 2014, those prices were $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas, and at year-end 2015, they have fallen to $50.28 per Bbl and $2.58 per MMBtu, respectively. We did not record any ceiling test impairments for 2014 and 2013.

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 $151.3 million were recorded in 2015 compared to $63.4 million in 2014. The impairments in 2015 and 2014 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 primarily in our Panhandle Marmaton, which resulted in certain undeveloped properties not expected to be developed before lease expiration. The second factor 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 during the third quarter of 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 in 2015 by $221.7 million and hence increased the ceiling test write-down by the same amount.

Impairment of other assets. 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. We own four stacked drilling rigs of which one was last utilized in January 2015 while the remaining three have been stacked for three to four years. As a result of the recent deterioration in commodity prices and reduced drilling activity, the value of such equipment has 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. We had previously recorded $3.5 million and $1.5 million of impairment related to these rigs during the years ended December 31, 2013 and 2012, respectively. 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 adjustment on our equipment inventory reflects the decrease in market prices.

General and Administrative expenses (“G&A”)  

 

 

 

Year ended

December 31,

 

 

Increase /

 

 

Percentage

 

 

Year ended

December 31,

 

 

Increase /

 

 

Percentage

 

 

 

2015

 

 

2014

 

 

(Decrease)

 

 

change

 

 

2013

 

 

(Decrease)

 

 

change

 

G&A and cost reduction initiatives (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross G&A expenses

 

$

49,734

 

 

$

77,376

 

 

$

(27,642

)

 

 

(35.7

)%

 

$

73,318

 

 

$

4,058

 

 

 

5.5

%

Capitalized exploration and development costs

 

 

(10,645

)

 

 

(23,962

)

 

 

13,317

 

 

 

(55.6

)%

 

 

(19,435

)

 

 

(4,527

)

 

 

23.3

%

Net G&A expenses

 

$

39,089

 

 

$

53,414

 

 

$

(14,325

)

 

 

(26.8

)%

 

$

53,883

 

 

$

(469

)

 

 

(0.9

)%

Cost reduction initiatives

 

 

10,028

 

 

 

 

 

 

10,028

 

 

*

 

 

 

 

 

 

 

 

*

 

Net G&A and cost reduction initiatives expense

 

$

49,117

 

 

$

53,414

 

 

$

(4,297

)

 

 

(8.0

)%

 

$

53,883

 

 

$

(469

)

 

 

(0.9

)%

Average G&A expense per Boe

 

$

3.83

 

 

$

4.86

 

 

$

(1.03

)

 

 

(21.2

)%

 

$

5.53

 

 

$

(0.67

)

 

 

(12.1

)%

Average G&A and cost reduction initiatives expense per Boe

 

$

4.82

 

 

$

4.86

 

 

$

(0.04

)

 

 

(0.8

)%

 

$

5.53

 

 

$

(0.67

)

 

 

(12.1

)%

 

56


Gross G&A expenses decreased from 2014 to 2015, 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 reduction. Expense for equity based awards was lower as a result of forfeitures and a decrease in the fair value of our liability awards due to depressed industry conditions. Other than compensation and benefits, we had reductions across most of our other G&A categories in 2015 in line with our initiatives to reduce costs in the current environment.  Gross G&A expenses in 2014 increased from 2013 primarily due to increased compensation and benefits costs related to the competitive nature of our market and our growing operations, along with other expenses and general inflation. Stock-based compensation (credit) expense included in G&A was $(1.8) million, $3.7 million and $5.4 million for 2015, 2014 and 2013, respectively.

Capitalized exploration and development costs decreased from 2014 to 2015 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. Capitalized exploration and development costs increased between 2013 to 2014 primarily due to a higher proportion of compensation costs subject to capitalization. A larger proportion of our compensation costs was capitalized in 2014 compared to the prior period as a result of our shift in focus from acquiring developed properties to exploring and developing leasehold acreage in resource plays with repeatable drilling opportunities.

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. Included in our expenses for cost reduction initiatives for 2015 are $7.7 million for one-time severance and termination benefits in connection with our reduction in force that was implemented during the year. The remaining cost reduction expense is a result of third party legal and professional services we have engaged to assist in these initiatives. As discussed below in “—Liquidity and Capital Resources,” we are allowed to exclude up to $25.0 million of expenses incurred in connection with our cost reduction initiatives, including costs related to our workforce reduction, from our EBITDA-based covenant under our Credit Facility.

Our G&A expenses on a Boe basis decreased from 2014 to 2015 primarily due to the overall decrease in general and administrative expenses described above. Our G&A expenses on a Boe basis decreased from 2013 to 2014 primarily due to the increase in overall production volumes between periods and an increase in the proportion of general and administrative expenses capitalized in connection with our increased 2014 development and exploration activities.

Other Income and Expenses

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

 

 

 

Year ended December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

9.875% Senior Notes due 2020

 

$

30,900

 

 

$

30,776

 

 

$

30,660

 

8.25% Senior Notes due 2021

 

 

33,717

 

 

 

33,687

 

 

 

33,630

 

7.625% Senior Notes due 2022

 

 

42,756

 

 

 

42,167

 

 

 

42,081

 

Credit Facility

 

 

9,608

 

 

 

5,785

 

 

 

1,646

 

Bank fees and other interest

 

 

5,089

 

 

 

5,317

 

 

 

4,854

 

Capitalized interest

 

 

(9,670

)

 

 

(13,491

)

 

 

(15,995

)

Total interest expense

 

$

112,400

 

 

$

104,241

 

 

$

96,876

 

Average long-term borrowings

 

$

1,688,859

 

 

$

1,543,346

 

 

$

1,370,790

 

 

Total interest expense increased from 2013 to 2014 and from 2014 to 2015 primarily due to increased levels of borrowing on our Credit Facility and reduced capitalized interest. Capitalized interest was lower in 2015 compared to 2014 as a result of a lower carrying amount of unevaluated non-producing leasehold subsequent to the leasehold impairments we recorded during the year. Capitalized interest was lower in 2014 compared to 2013 as we ceased capitalizing interest on our CO2 delivery pipelines and facilities upon completing construction of those assets.

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.

57


Income Taxes

 

 

 

Year ended December 31,

 

(dollars in thousands)

 

2015

 

 

2014

 

 

2013

 

Current income tax expense

 

$

174

 

 

$

552

 

 

$

1,115

 

Deferred income tax expense

 

 

(177,393

)

 

 

123,891

 

 

 

31,734

 

Total income tax expense

 

$

(177,219

)

 

$

124,443

 

 

$

32,849

 

Effective tax rate

 

 

11.7

%

 

 

37.3

%

 

 

37.1

%

Total net deferred tax liability

 

$

 

 

$

(177,487

)

 

$

(53,595

)

 

Our federal net operating loss carryforwards were approximately $441.0 million as of December 31, 2015, which will expire between 2028 and 2035 if not utilized in earlier periods. As of December 31, 2015, our state net operating loss carryforwards were approximately $530.0 million, which will expire between 2016 and 2035 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, 2015, we have $411.1 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, 2015, we recorded approximately $401 million of our total valuation allowance including $126 million recorded as a discrete item associated with our federal and state operating loss carryforwards for the year ended December 31, 2014. 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 “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, and 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. We do not have a Section 382 limitation on our ability to utilize our U.S. loss carryforwards as of December 31, 2015. In 2016, however, certain restructuring activities being pursued could impact the ultimate realization of our net operating losses and our tax basis. Future equity transactions involving the Company or 5% of our shareholders (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes resulting in a Section 382 limitation in 2016 on the annual utilization of our loss carryforwards. Filing for protection under Chapter 11 of the U.S. Bankruptcy Code or a Section 382 limitation might cause our tax attributes to be reduced and/or subject to annual utilization limits. A significant portion of our NOL may be offset by tax gains or cancellation of debt.

Liquidity and Capital Resources

Our cash balance as of February 29 and March 30, 2016, was approximately $202.9 million and $176.0 million, respectively. We have historically funded our operations primarily through cash flows from operating activities, borrowings under our Credit Facility, receipts from commodity price derivatives, proceeds from asset sales and private issuances of equity. Our primary uses of funds are expenditures for exploration and development, leasehold and property acquisitions, other capital expenditures, and debt service requirements.

However, our future 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 influence market conditions, which often result in significant volatility in commodity prices. Oil and natural gas prices declined severely during fiscal year 2015 and have declined even further in early 2016 to date. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices are having a material and adverse effect on our liquidity position.

We mitigate the impact of volatility in commodity prices, in part through the use of derivative instruments which help stabilize our cash flow. Although commodity prices are expected to remain low for the remainder of 2016, our robust commodity price hedging program will help us generate cash flows from operations to fund a portion of our expenses and operations in 2016. Based on the NYMEX strip price at March 24, 2016, we have 4.4 million barrels of crude oil production hedged at $68.63/barrel and 14,000 BBtu of natural gas production hedged at $4.19/MMBtu for fiscal 2016.

Our debt includes our Senior Notes, which, as of December 31, 2015, had an aggregate principal amount of $1,208 million. We also maintain a senior secured revolving credit facility, which currently has a borrowing base of $550.0 million and of which approximately $367.0 million was borrowed as of December 31, 2015, that is collateralized by a substantial portion of our oil and natural gas properties, and, as amended, is originally scheduled to mature on November 1, 2017 (our “Credit Facility”). The banks establish a borrowing base, which is redetermined on a periodic basis, by making an estimate of the collateral value of our oil and

58


natural gas properties. When 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 at future redeterminations, thus reducing funds available under the borrowing base.

Despite our ability to generate day-to-day operating cash flows with the aid of our commodity derivatives, our liquidity is severely constrained by the impact of low commodity prices on our ability to borrow funds. As noted above, borrowings under our Credit Facility are, among other things, limited to a borrowing base which was most recently set, effective October 29, 2015, at $550 million. However, as a result of depressed market prices in early 2016, we anticipate that the lender-determined pricing that will be utilized to estimate our borrowing base under our Credit Facility will be lower than the pricing utilized in our previous redetermination. This will result in a significantly lower borrowing base at our next borrowing base redetermination, which we anticipate to occur around May 1, 2016. In the event of a reduction in our borrowing base below the amount of outstanding borrowings, the amount of outstanding borrowings under our Credit Facility in excess of the newly determined borrowing base would constitute a deficiency which we would have to repay in a single amount or in six equal monthly installments. Based on current estimates of our cash flows from operations, cash flows from derivative settlements and cash flows from potential asset sales, we may not have sufficient liquidity to repay any such deficiency upon a reduced borrowing base.

Based on current market conditions and depressed commodity prices, if we are unable to restructure our debt and adequately address liquidity concerns, we do not expect to be in compliance with the Consolidated Net Secured Debt to Consolidated EBITDAX and the Interest Coverage Ratio covenants for the quarter ending September 30, 2016.

On February 11, 2016, we borrowed an additional $141.0 million under our Credit Facility for general corporate purposes, which represented substantially all the remaining undrawn amount that was available under the Credit Facility. Following the funding of this borrowing, the aggregate principal amount of borrowings under the Credit Facility was $548.0 million, in addition to $0.8 million of outstanding letters of credit.

As a result of our limited ability to repay the expected borrowing base deficiency as well as our anticipated noncompliance of the aforementioned financial covenants, both of which will constitute an event of default under our Credit Facility, absent a material improvement in commodity prices or a refinancing or restructuring of our debt obligations or other improvement in liquidity, we believe forecasted cash and expected available credit capacity will not be sufficient to meet all commitments as they come due for the next twelve months, especially in regards to any acceleration of indebtedness. As a result, there is substantial doubt regarding our ability to continue as a going concern. This doubt, which has been expressed in the audit opinion of our annual financial statements, constitutes an event of default under the Credit Facility since the covenants under the facility require us to timely deliver our annual financial statements to our lenders without a going concern explanatory paragraph.

We are evaluating various alternatives with respect to our Credit Facility but there is no certainty that we will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver. Absent success in these pursuits, a resultant breach under the Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Credit Facility. If the lenders under the Credit Facility were to accelerate the indebtedness under the Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all indebtedness under our Senior Notes. Furthermore, our obligations relating to our capital leases, real-estate mortgage notes and installment notes generally contain cross default provisions. Such a cross-default or cross-acceleration has a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs under our Credit Facility, or if our Senior Notes or other indebtedness cross-defaults, and the lenders under the affected debt agreements accelerate the maturity of our outstanding debt, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

Our $1,208 million in outstanding principal value of our Senior Notes is originally scheduled to mature within the next seven years. During 2013, 2014 and 2015, our cash interest obligation on these notes was approximately $104.6 million annually while we expect the interest obligation for fiscal 2016 to be approximately $101.2 million. The interest obligations under our Senior Notes have placed considerable pressure on our liquidity and financial flexibility during the current industry downturn. On March 1, 2016, we elected not to make an interest payment of $16.5 million, due March 1, 2016, on our 8.25% Senior Notes maturing 2021. We elected to defer payment as we continue our discussions with bondholders, lenders under our Credit Facility and prospective financing sources in order to find alternatives to improve our long-term capital structure. The election to defer the interest payment would not have constituted an event of default as defined under the indenture governing the Senior Notes or any other indenture relating to our other Senior Notes if payment were to be made within 30 days of the due date. However, as we do not intend to make the interest payment within the 30-day grace period, we expect to be in default upon expiration of the grace period, and the trustee or holders of at least 25% in principal amount of the outstanding Senior Notes may declare the principal and any interest immediately due and payable. Our election to defer the interest payment on our Senior Notes upon expiration of the 30-day grace period will also result in a cross-default

59


under our Credit Facility which provides that any default on material indebtedness becomes an Event of Default under the Credit Facility if such default results in the acceleration of such material indebtedness or permits such acceleration with or without the giving of notice, the lapse of time or both. On March 2, 2016, our lenders notified us that our election to defer the interest payment on March 1, 2016, was event of default and that our lenders have reserved all rights under the Credit Agreement. Subsequently on March 7, 2016, our lenders notified us that as a result such default, we will no longer be able to borrow at the LIBOR rate and outstanding amounts under our Credit Facility will bear interest at the default rate, which includes an additional 200 basis points. We have responded to our lenders asserting that we do not believe that a default had occurred prior to the expiration of the 30-day grace period.

If the lenders under our Credit Facility or the trustee or holders of our Senior Notes accelerate our indebtedness as a result of defaults, such acceleration would cause a cross-default and potential acceleration of the maturity of substantially all our long-term debt. As such, our long-term debt obligations are classified as current liabilities in our consolidated balance sheet as of December 31, 2015. As a result of this reclassification, our current liabilities exceed our current assets by a significant amount and we are therefore in violation of the current ratio covenant under our Credit Facility for the period ending December 31, 2015. We have asked the lenders under our Credit Facility and certain holders of our Senior Notes for forbearance from exercising certain rights and remedies arising from defaults for a specified period of time.

We have been in discussions with our financial advisors for the past several months and have retained Evercore and Latham & Watkins LLP to advise management and our board of directors regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms or within a period needed to meet certain obligation, if at all. We are also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure you that any of these efforts will yield sufficient funds to meet our working capital or other liquidity needs, including payments of interest and principal on our debt in the future.

Absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure. Other than the classification of long-term debt to current liabilities, the accompanying consolidated financial statements in this report does not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities.

As of December 31, 2015, there were seven counterparties to our open derivative contracts, which had a net fair value of $163.2 million. All seven counterparties are financial institutions within the lender group under our Credit Facility. Our derivative contracts with these counterparties are governed by master agreements which 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 the event of an early termination of our derivative contracts as a result of a default, we may not receive the proceeds from such termination. It is possible that the counterparty financial institutions to our derivative contracts will utilize their right of offset with respect to the Credit Facility to retain such proceeds. Any potential loss of anticipated proceeds from our derivative settlements in 2016 will severely limit our cash from operations and liquidity. Furthermore, if we are in default on our indebtedness or have a bankruptcy filing, we will no longer be able to represent that we comply with the credit default or bankruptcy covenants under our derivative master agreements and thus may not be able to enter into new hedging transactions. On March 4, 2016, we received notification from one of our derivative counterparties reserving all rights under the master agreement governing our derivative transaction with said counterparty. The notice was issued subsequent to our election to defer the $16.5 million payment on March 1, 2016, which according to the counterparty represents an event of default under the agreement.

Sources and Uses of Cash

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

 

 

 

Year ended December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

Cash flows provided by operating activities

 

$

19,608

 

 

$

323,911

 

 

$

264,053

 

Cash flows used in investing activities

 

 

(37,258

)

 

 

(412,222

)

 

 

(515,122

)

Cash flows provided by financing activities

 

 

3,223

 

 

 

71,208

 

 

 

269,845

 

Net (decrease) increase in cash during the period

 

$

(14,427

)

 

$

(17,103

)

 

$

18,776

 

 

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.

60


Our cash flows from operating activities were lower in 2015 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. Cash flows from operating activities were higher in 2014 than they were in 2013 primarily due to the 15% increase in commodity sales driven by an increase in production as well as lower production taxes. These increases were partially offset by higher lease operating and interest charges as well as changes in working capital.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the years ended December 31, 2015, 2014, and 2013, cash flows provided by operating activities were approximately 6%, 47% and 41%, respectively, of cash used for the acquisition and development of our properties. Due to the decline in cash flows from operations in 2015, our cash capital expenditures in 2015 were also funded by cash receipts from settlements of our commodity derivatives, asset sales and borrowings. 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 proceeds of $291.4 million primarily from the sale of non-core properties as discussed below in Alternative capital resources. During 2014, we also paid $20.6 million in premiums for put options associated with our crude oil commodity derivatives settling in 2016. During 2013, cash flows used in investing activities included proceeds of $111.2 million from asset dispositions, including approximately $61.4 million from the sale of certain non-strategic properties located in Creek, Love, and Carter counties, Oklahoma, and $17.8 million from the sale of certain non-strategic properties located in Texas County, Oklahoma.  We received net derivative settlements totaling $233.6 million, $2.4 million, and $19.1 million during 2015, 2014 and 2013, respectively

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 Credit Facility as well as $10.0 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 Credit Facility. In addition, principal payments under our capital lease obligations, discussed below, were $2.3 million during 2014. In 2013, we had proceeds from and repayments of debt of $297.8 million and $52.1 million, respectively, most of which were attributable to our Credit Facility. A portion of the borrowings from our Credit Facility in 2013 were utilized to finance the acquisition of oil and natural gas properties from Cabot Oil and Gas Corporation. We also entered into $24.5 million of capital leases during the year from the sale and subsequent leaseback of existing compressors owned by us.

Capital Expenditures

Our actual costs incurred, including costs that we have accrued, for 2015 and our budgeted 2016 capital expenditures for oil and natural gas properties are summarized in the following table:

 

 

 

2015 Capital Expenditures

 

 

 

 

 

(in thousands)

 

E&P Areas

 

 

EOR Project Areas

 

 

Total

 

 

Budgeted

2016 capital

expenditures

(1)(2)

 

Acquisitions

 

$

25,927

 

 

$

 

 

$

25,927

 

 

$

7,427

 

Drilling

 

 

115,181

 

 

 

 

 

 

115,181

 

 

 

50,710

 

Enhancements

 

 

11,177

 

 

 

21,594

 

 

 

32,771

 

 

 

25,711

 

Pipeline and field infrastructure

 

 

 

 

 

20,003

 

 

 

20,003

 

 

 

12,476

 

CO2 purchases

 

 

 

 

 

15,397

 

 

 

15,397

 

 

 

13,116

 

Total

 

$

152,285

 

 

$

56,994

 

 

$

209,279

 

 

$

109,440

 

 

(1)

Includes $44.8 million allocated to our EOR project areas as follows: enhancements of $19.2 million, pipeline and field infrastructure of $12.5 million and CO2 purchases of $13.1 million.

(2)

Budget categories presented include allocations of capitalized interest and general and administrative expenses. In addition to the amounts in this table, we have budgeted $1.2 million for other plant, property and equipment.

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $2.4 million for property and equipment during 2015.

 

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During 2015, we continued our increased focus on the development of our E&P Area assets, primarily in the STACK and Mississippi Lime plays, which is consistent with our strategy of driving growth through development of our core operations located in the Mid-Continent region. Our oil and natural gas property capital expenditure budget for 2016 is set at $109.4 million, of which $64.7 million, or 58%, is allocated to our E&P Area assets.

We continually evaluate our capital needs and compare them to our capital resources. Our 2016 capital budget is predicated upon successful restructuring of our outstanding indebtedness, which is discussed above. Our actual expenditures during 2016 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 2016 closely and may adjust our spending accordingly based on the outcome of our debt restructuring activities, actual and projected cash flows, our liquidity and our capital requirements

Indebtedness

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

 

 

 

December 31,

 

(in thousands)

 

2015

 

 

2014

 

9.875% Senior Notes due 2020, net of discount of $4,185 and $4,861, respectively

 

$

293,815

 

 

$

295,139

 

8.25% Senior Notes due 2021

 

 

384,045

 

 

 

400,000

 

7.625 % Senior Notes due 2022, including premium of $4,939 and $4,869 respectively

 

 

530,849

 

 

 

554,869

 

Credit Facility

 

 

367,000

 

 

 

347,000

 

Real estate mortgage notes

 

 

10,182

 

 

 

10,705

 

Installment notes

 

 

1,799

 

 

 

4,252

 

Capital lease obligations

 

 

19,437

 

 

 

21,837

 

 

 

$

1,607,127

 

 

$

1,633,802

 

 

Please see “Note 6—Debt” in Item 8. Financial Statements and Supplementary Data of this report for a discussion of the material terms governing our Senior Notes and Credit Facility. For information on the future maturities of our long term debt, see the table below under “Contractual obligations.”

Credit Facility

We maintain a senior secured revolving Credit Facility, which is collateralized by our oil and natural gas properties, and originally scheduled to mature on November 1, 2017. As of December 31, 2015, we have $367.0 million of outstanding borrowings under our Credit Facility.

Availability under our Credit Facility is subject to a borrowing base which is 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 and in the event of early termination of our derivative contracts. 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 previously 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.

If the outstanding borrowings under our Credit Facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within ten 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 thirty days or in equal monthly installments over a six-month period, (2) to submit within thirty days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within thirty days.

Our initial borrowing base in 2015, which was effective as of November 5, 2014, was $650.0 million. Our first semiannual borrowing base redetermination for 2015 was determined in conjunction with an amendment to our Credit Facility (the “Fifteenth Amendment”), effective on April 1, 2015. Primarily due to reduced oil and gas pricing used to determine the value of our reserves, our borrowing base was decreased from $650.0 million to $550.0 million effective on April 1, 2015. Our semiannual borrowing base redetermination effective on October 29, 2015, reaffirmed our borrowing base at $550.0 million. As discussed above, due to further declines in commodity prices, we expect our next borrowing base redetermination, scheduled for May 1, 2016, to result in a significant reduction to the borrowing base.

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Our Credit Facility requires us to maintain a current ratio, as defined in our Credit Facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Facility, we consider the current ratio calculated under our Credit Facility to be a useful measure of our liquidity because it includes the funds available to us under our Credit Facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. Our current ratio, as computed using GAAP and as computed for loan compliance, is disclosed in the following table. The table also reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance.

 

 

 

December 31,

 

(in thousands)

 

2015

 

 

2014

 

Current assets per GAAP

 

$

255,831

 

 

$

339,898

 

Plus—Availability under Credit Facility

 

 

182,172

 

 

 

302,080

 

Less—Short-term derivative instruments

 

 

(143,737

)

 

 

(179,921

)

Less—Deferred tax asset on derivative instruments and asset retirement obligations

 

 

 

 

 

 

Current assets as adjusted

 

$

294,266

 

 

$

462,057

 

Current liabilities per GAAP

 

$

1,778,262

 

 

$

328,366

 

Less—Short term derivative instruments

 

 

 

 

 

(77

)

Less—Short-term asset retirement obligations

 

 

(2,178

)

 

 

(4,147

)

Less—Deferred tax liability on derivative instruments and asset retirement obligations

 

 

(53,962

)

 

 

(65,799

)

Current liabilities as adjusted

 

$

1,722,122

 

 

$

258,343

 

Current ratio per GAAP

 

 

0.14

 

 

 

1.04

 

Current ratio for loan compliance

 

 

0.17

 

 

 

1.79

 

 

As discussed previously, due to the potential acceleration of our debt as a result of defaults or cross defaults on our various debt facilities, we have reclassified all long-term debt on our balance sheet to current liabilities. As a result, the current ratio as calculated under our Credit Facility is less than 1.0 to 1.0, which is an event of default under our Credit Facility.

 

As of December 31, 2015, the availability under our Credit Facility was $182.2 million, which was not limited by the Consolidated Net Secured Debt to Consolidated EBITDAX covenant.

The Fifteenth Amendment, which was effective April 1, 2015, replaced the Consolidated Net Debt to Consolidated EBITDAX covenant under our Credit Facility with a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.00 to 1.00. The amendment revises the definition of Consolidated EBITDAX to exclude up to $25.0 million in expenses incurred subsequent to January 1, 2015, in connection with our cost savings initiatives, transition, business optimization and other restructuring charges. These charges, which are reflected as “Cost reduction initiatives” on our consolidated statement of operations are discussed above under “General and administrative expenses.” Under the Fifteenth Amendment, we are also allowed to incur an additional $300.0 million in Additional Permitted Debt, as defined in the amendment to now include both secured and unsecured debt.

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.

Asset sales and sources of liquidity

 

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. 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. Our capital expenditures for 2015 were funded, in part, by approximately $42.6 million of proceeds generated from asset divestitures.

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Proceeds from the property sales discussed above provide, and proceeds from any future divestitures will provide, us with an additional source of liquidity to pay down borrowings under our Credit Facility, fund capital expenditures and for general corporate purposes. In the future, our sources of liquidity may include asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.

Contractual obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2015:

 

(in thousands)

 

Less than

1 year

 

 

1-3 years

 

 

3-5 years

 

 

More than

5 years

 

 

Total

 

Debt:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Senior Notes, including estimated interest

 

$

101,212

 

 

$

202,424

 

 

$

493,067

 

 

$

1,006,155

 

 

$

1,802,858

 

Credit Facility, including estimated interest and

   commitment fees

 

 

9,998

 

 

 

375,327

 

 

 

 

 

 

 

 

 

385,325

 

Other long-term notes, including estimated interest

 

 

2,497

 

 

 

2,628

 

 

 

2,188

 

 

 

8,786

 

 

 

16,099

 

Capital lease obligations, including estimated interest

 

 

3,181

 

 

 

6,362

 

 

 

12,028

 

 

 

 

 

 

21,571

 

Abandonment obligations

 

 

2,178

 

 

 

4,357

 

 

 

4,357

 

 

 

37,720

 

 

 

48,612

 

CO2 purchase obligations

 

 

2,193

 

 

 

2,579

 

 

 

2,579

 

 

 

3,066

 

 

 

10,417

 

Operating lease obligations

 

 

1,095

 

 

 

2,188

 

 

 

2,143

 

 

 

1,018

 

 

 

6,444

 

Other commitments

 

 

4,009

 

 

 

92

 

 

 

 

 

 

 

 

 

4,101

 

Total

 

$

126,363

 

 

$

595,957

 

 

$

516,362

 

 

$

1,056,745

 

 

$

2,295,427

 

 

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 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 2015, we purchased approximately 10 MMcf/d of CO2 under this contract, and we expect to purchase an average of approximately 2.5 MMcf/d in 2016. Purchases under this contract were $1.1 million, $1.3 million, and $1.3 million during 2015, 2014, and 2013, respectively.

We have rights under three 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. The first of these contracts, with the plant in Enid, Oklahoma, is scheduled to expire in 2016 and we expect to purchase 1.5 MMcf/d of CO2 in 2016, subject to availability. During 2015, we purchased approximately 1 MMcf/d of CO2 under this contract. Total purchases, which include transportation charges, during 2015, 2014, and 2013 were $0.5 million, $1.1 million, and $0.6 million, respectively. The second contract, with the plant in Borger, Texas, expires in February 2021. During 2015, we purchased an average of approximately 11 MMcf/d and expect our purchases to average approximately 9 MMcf/d of CO2 in 2016. Purchases under this contract were $0.4 million, $1.1 million, and $1.3 million during 2015, 2014, and 2013, respectively. Pricing under both of these contracts is dependent on certain variable factors, including the price of oil. Our third contract, with the plant in Coffeyville, Kansas, expires in 2033 but provides the option for renewal. Pricing under the contract is fixed for the first five contract 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 purchase rate under this contract with six months’ notice. During 2015, we purchased 26 MMcf/d from this source and expect to purchase 25 MMcf/d in 2016. Purchases under this contract totaled $1.0 million, $1.4 million, and $0.6 million during 2015, 2014, and 2013, 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, 2015, 2014, and 2013 was $8.8 million, $11.1 million, and $9.0 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 at our EOR facilities, which expire in 2021. Amounts related to our operating lease obligations are disclosed in the table above.

Other commitments consist of contracts in place as of December 31, 2015, that are not currently recorded on our consolidated balance sheets. These purchases are generally expected to be finalized within the next several months and are included in our capital expenditures budget for 2016. The contracts are primarily for drilling rig services and information technology services. In addition, we have included our obligation under an interim financing agreement for the manufacture of a CO2 recycle compressor for which we intend to enter into an operating lease upon completion and delivery of the item around April 2016.

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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.

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 crude oil collars, enhanced swaps, and purchased and sold puts 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 incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our Credit Facility. We believe the credit risks associated with all of these institutions are acceptable.

In the event that we enter into derivative contracts that require payment of a premium, we may sometimes defer payment of the premium until the settlement date of the contract. The payable for deferred premiums is included within the fair value of the derivative contract.

Since we have elected to not designate any of our derivative contracts as hedges since 2010, we mark our contracts to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line 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.

 

·

Full cost accounting. We use the full cost method of accounting for our oil and natural gas properties. Under this method, all costs incurred in the exploration and development of oil and natural gas properties are capitalized into a cost center. These costs include drilling and equipping productive wells, dry hole costs, seismic costs and delay rentals. Capitalized costs also include salaries, employee benefits, consulting services and other expenses that directly relate to our exploration and development activities.

 

·

Proved oil and natural gas reserves quantities. Proved oil and natural gas reserves are the quantities of crude 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. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance.  

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 90% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2015. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

 

·

Depreciation, depletion and amortization. The quantities of proved oil and natural gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-

65


 

production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based on the relative energy content.

 

·

Full cost ceiling limitation.  Under the full cost method, the net capitalized costs of oil and natural gas properties recorded on our consolidated balance sheets cannot exceed the estimated future net revenues discounted at 10% plus the cost of unproved properties not being amortized. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues exclude escalations based upon future conditions. If commodity prices remain at their current depressed levels, the average prices used in the ceiling calculation will decline and will likely cause potential write-downs of our oil and natural gas properties. Furthermore, if we have downward revisions to our estimated reserve quantities, it is possible that write-downs could occur in the future as well.

 

·

Costs not subject to amortization.  Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling, and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

 

·

Future development and abandonment costs.  Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

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, 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.

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

66


monitoring the joint standard-setting efforts of the Financial Accounting Standards Board and International Accounting Standards Board. There are a number of pending accounting standards being targeted for completion in 2016 and beyond, including, but not limited to, standards relating to accounting for leases, financial instruments and share based payments. Because these pending standards have not yet been finalized, at this time we are not able to determine the potential future impact these standards will have, if any, on our financial position, results of operations or cash flows.

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, 2015, our gross revenues from commodity sales would change approximately $7.1 million for each $1.00 change in oil and NGL prices and $1.9 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, including commodity price swaps, costless collars, put options, 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 gains (losses) 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 we reviewed when deciding to enter into the original derivative position.

67


Our outstanding oil derivative instruments as of December 31, 2015, are summarized below:

 

 

 

 

 

 

 

Weighted average fixed price per Bbl

 

Period and type of contract

 

Volume

MBbls

 

 

Swaps

 

 

Sold puts

 

 

Purchased

puts

 

 

Sold calls

 

 

Average deferred

premium

 

January - March 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars

 

 

60

 

 

$

 

 

$

84.00

 

 

$

92.00

 

 

$

101.01

 

 

$

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

40.00

 

 

$

52.50

 

 

$

72.50

 

 

$

2.95

 

Enhanced swaps (2)

 

 

960

 

 

$

92.98

 

 

$

80.50

 

 

$

 

 

$

 

 

$

 

Purchased puts (2)

 

 

960

 

 

$

 

 

$

 

 

$

60.00

 

 

$

 

 

$

 

April - June 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars

 

 

60

 

 

$

 

 

$

84.00

 

 

$

92.00

 

 

$

101.01

 

 

$

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

40.00

 

 

$

52.50

 

 

$

72.50

 

 

$

2.95

 

Enhanced swaps (2)

 

 

960

 

 

$

92.98

 

 

$

80.50

 

 

$

 

 

$

 

 

$

 

Purchased puts (2)

 

 

960

 

 

$

 

 

$

 

 

$

60.00

 

 

$

 

 

$

 

July - September 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars

 

 

60

 

 

$

 

 

$

84.00

 

 

$

92.00

 

 

$

101.01

 

 

$

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

40.00

 

 

$

52.50

 

 

$

72.50

 

 

$

2.95

 

Enhanced swaps (2)

 

 

900

 

 

$

92.91

 

 

$

80.53

 

 

$

 

 

$

 

 

$

 

Purchased puts (2)

 

 

900

 

 

$

 

 

$

 

 

$

60.00

 

 

$

 

 

$

 

October - December 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars

 

 

60

 

 

$

 

 

$

84.00

 

 

$

92.00

 

 

$

101.01

 

 

$

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

40.00

 

 

$

52.50

 

 

$

72.50

 

 

$

2.95

 

Enhanced swaps (2)

 

 

900

 

 

$

92.91

 

 

$

80.53

 

 

$

 

 

$

 

 

$

 

Purchased puts (2)

 

 

900

 

 

$

 

 

$

 

 

$

60.00

 

 

$

 

 

$

 

January - March 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

42.50

 

 

$

55.00

 

 

$

80.00

 

 

$

2.78

 

April - June 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

42.50

 

 

$

55.00

 

 

$

80.00

 

 

$

2.78

 

July - September 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

42.50

 

 

$

55.00

 

 

$

80.00

 

 

$

2.78

 

October - December 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars (1)

 

 

120

 

 

$

 

 

$

42.50

 

 

$

55.00

 

 

$

80.00

 

 

$

2.78

 

 

(1)

These contracts include deferred premiums that are payable upon settlement.

(2)

Total premiums of $20.6 million for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $41.45 for 2016 as of December 31, 2015, the average realized price, and concurrently the floor price, of our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42 per barrel. In the event that prices increase above $60.00 per barrel upon settlement, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

68


Our outstanding natural gas derivative instruments as of December 31, 2015, are summarized below:

 

Period and type of contract

 

Volume

BBtu

 

 

Weighted

average

fixed price

per MMBtu

 

January - March 2016

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

3,950

 

 

$

4.30

 

Natural gas basis protection swaps

 

 

2,100

 

 

$

0.36

 

April - June 2016

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

3,300

 

 

$

4.10

 

Natural gas basis protection swaps

 

 

2,100

 

 

$

0.36

 

July - September 2016

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

3,300

 

 

$

4.13

 

Natural gas basis protection swaps

 

 

2,100

 

 

$

0.36

 

October - December 2016

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

3,450

 

 

$

4.19

 

Natural gas basis protection swaps

 

 

2,100

 

 

$

0.36

 

January - March 2017

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

3,730

 

 

$

3.72

 

April - June 2017

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

2,790

 

 

$

3.52

 

July - September 2017

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

3,300

 

 

$

3.58

 

October - December 2017

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

2,880

 

 

$

3.71

 

January - March 2018

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

2,390

 

 

$

3.98

 

April - June 2018

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

2,010

 

 

$

3.68

 

July - September 2018

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

1,960

 

 

$

3.74

 

October - December 2018

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

1,890

 

 

$

3.90

 

 

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 covering 495,000 barrels of oil and 12,280 BBtu of natural gas, in order to maintain compliance with the hedging limits imposed by covenants under our Credit Facility. As a result, we received net proceeds of $15.4 million.

Interest rates 

All of the outstanding borrowings under our Credit Facility as of December 31, 2015 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Facility as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the greater of (1) the Prime Rate, as defined in our Credit Facility, (2) the Federal Funds Effective Rate, as defined in the Credit Facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our Credit Facility, plus 1.00%, plus a margin that varies depending on our utilization percentage. Eurodollar loans bear interest at a fluctuating rate that is computed at the Adjusted LIBO Rate, as defined in our Credit Facility, times a Statutory Reserve Rate multiplier, as defined in our Credit Facility, plus a margin that varies depending on our utilization percentage. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $550.0 million, equal to our borrowing base at December 31, 2015, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.5 million.

 

 

 

69


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to financial statements  

 

 

 

 

70


Report of independent registered public accounting firm

Board of Directors

Chaparral Energy, Inc.

 

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2015. 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 as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company incurred a net loss of approximately $1,334 million during the year ended December 31, 2015, and as of that date, the Company’s current liabilities exceeded its current assets by approximately $1,522 million and its total liabilities exceeded its total assets by approximately $620 million. Also discussed in Note 2, subsequent to December 31, 2015, the Company is in default on its debt obligations.  These conditions, along with other matters as set forth in Note 2, raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

 

/s/ Grant Thornton LLP

 

Oklahoma City, Oklahoma

March 30, 2016

 

 

71


Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

 

 

 

December 31,

 

(dollars in thousands, except per share data)

 

2015

 

 

2014

 

Assets

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

17,065

 

 

$

31,492

 

Accounts receivable, net

 

 

79,000

 

 

 

98,444

 

Inventories, net

 

 

12,329

 

 

 

25,557

 

Prepaid expenses

 

 

3,700

 

 

 

4,484

 

Derivative instruments

 

 

143,737

 

 

 

179,921

 

Total current assets

 

 

255,831

 

 

 

339,898

 

Property and equipment—at cost, net

 

 

48,962

 

 

 

66,561

 

Oil and natural gas properties, using the full cost method:

 

 

 

 

 

 

 

 

Proved

 

 

4,128,193

 

 

 

3,735,817

 

Unevaluated (excluded from the amortization base)

 

 

66,905

 

 

 

288,425

 

Accumulated depreciation, depletion, amortization and impairment

 

 

(3,396,261

)

 

 

(1,701,851

)

Total oil and natural gas properties

 

 

798,837

 

 

 

2,322,391

 

Derivative instruments

 

 

19,501

 

 

 

71,710

 

Deferred income taxes

 

 

53,914

 

 

 

 

Other assets

 

 

27,694

 

 

 

31,256

 

Total assets

 

$

1,204,739

 

 

$

2,831,816

 

 

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

72


Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets—continued

 

 

 

December 31,

 

(dollars in thousands, except per share data)

 

2015

 

 

2014

 

Liabilities and stockholders’ equity (deficit)

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

Accounts payable and accrued liabilities

 

$

66,222

 

 

$

191,957

 

Accrued payroll and benefits payable

 

 

15,305

 

 

 

21,654

 

Accrued interest payable

 

 

23,303

 

 

 

24,106

 

Revenue distribution payable

 

 

12,391

 

 

 

24,467

 

Long-term debt and capital leases, classified as current

 

 

1,607,127

 

 

 

5,377

 

Derivative instruments

 

 

 

 

 

77

 

Deferred income taxes

 

 

53,914

 

 

 

60,728

 

Total current liabilities

 

 

1,778,262

 

 

 

328,366

 

Long-term debt and capital leases, less current maturities

 

 

 

 

 

1,628,425

 

Stock-based compensation

 

 

400

 

 

 

3,131

 

Asset retirement obligations

 

 

46,434

 

 

 

43,277

 

Deferred income taxes

 

 

 

 

 

116,759

 

Commitments and contingencies (Note 14)

 

 

 

 

 

 

 

 

Stockholders’ (deficit) equity:

 

 

 

 

 

 

 

 

Preferred stock, 600,000 shares authorized, none issued and outstanding

 

 

 

 

 

 

Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 345,289

   and 364,896 shares issued and outstanding at December 31, 2015 and 2014,

   respectively

 

 

4

 

 

 

4

 

Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859

   shares issued and outstanding

 

 

3

 

 

 

3

 

Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882

   shares issued and outstanding

 

 

2

 

 

 

2

 

Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276

   shares issued and outstanding

 

 

5

 

 

 

5

 

Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding

 

 

 

 

 

 

Class G Common stock, $0.01 par value, 3 shares authorized and 2 shares issued

   and outstanding

 

 

 

 

 

 

Additional paid in capital

 

 

431,307

 

 

 

429,678

 

(Accumulated deficit) retained earnings

 

 

(1,051,678

)

 

 

282,166

 

Total stockholders' (deficit) equity

 

 

(620,357

)

 

 

711,858

 

Total liabilities and stockholders' (deficit) equity

 

$

1,204,739

 

 

$

2,831,816

 

 

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

 

73


Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

 

 

 

Year ended December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

Commodity sales

 

$

324,315

 

 

$

681,557

 

 

$

591,674

 

Gain from oil hedging activities

 

 

 

 

 

 

 

 

37,134

 

Total revenues

 

 

324,315

 

 

 

681,557

 

 

 

628,808

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating

 

 

110,659

 

 

 

141,608

 

 

 

132,690

 

Transportation and processing

 

 

8,541

 

 

 

8,295

 

 

 

7,081

 

Production taxes

 

 

9,953

 

 

 

28,305

 

 

 

33,266

 

Depreciation, depletion and amortization

 

 

216,574

 

 

 

245,908

 

 

 

192,426

 

Loss on impairment of oil and gas assets

 

 

1,491,129

 

 

 

 

 

 

 

Loss on impairment of other assets

 

 

16,207

 

 

 

 

 

 

3,490

 

General and administrative

 

 

39,089

 

 

 

53,414

 

 

 

53,883

 

Cost reduction initiatives

 

 

10,028

 

 

 

 

 

 

 

Total costs and expenses

 

 

1,902,180

 

 

 

477,530

 

 

 

422,836

 

Operating (loss) income

 

 

(1,577,865

)

 

 

204,027

 

 

 

205,972

 

Non-operating income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

 

(112,400

)

 

 

(104,241

)

 

 

(96,876

)

Gain on extinguishment of debt

 

 

31,590

 

 

 

 

 

 

 

Non-hedge derivative gains (losses)

 

 

145,288

 

 

 

231,320

 

 

 

(21,635

)

Other income, net

 

 

2,324

 

 

 

2,630

 

 

 

1,075

 

Net non-operating income (expense)

 

 

66,802

 

 

 

129,709

 

 

 

(117,436

)

(Loss) income before income taxes

 

 

(1,511,063

)

 

 

333,736

 

 

 

88,536

 

Income tax (benefit) expense

 

 

(177,219

)

 

 

124,443

 

 

 

32,849

 

Net (loss) income

 

$

(1,333,844

)

 

$

209,293

 

 

$

55,687

 

 

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

 

 

 

74


Chaparral Energy, Inc. and subsidiaries

Consolidated statements of comprehensive income (loss)

 

 

 

Year ended December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

Net (loss) income

 

$

(1,333,844

)

 

$

209,293

 

 

$

55,687

 

Other comprehensive loss

 

 

 

 

 

 

 

 

 

 

 

 

Reclassification adjustment for hedge gains included in gain from oil

   hedging activities in the consolidated statements of operations

 

 

 

 

 

 

 

 

(37,134

)

Income tax benefit related to other comprehensive loss

 

 

 

 

 

 

 

 

13,911

 

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

(23,223

)

Comprehensive (loss) income

 

$

(1,333,844

)

 

$

209,293

 

 

$

32,464

 

 

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

 

 

 

75


Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity (deficit)

 

 

 

Common stock

 

 

Additional

paid in

capital

 

 

Retained

earnings

(accumulated

deficit)

 

 

Accumulated

other

comprehensive

income (loss)

 

 

Total

 

(dollars in thousands)

 

Shares

 

 

Amount

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at January 1, 2013

 

 

1,420,034

 

 

$

14

 

 

$

422,434

 

 

$

17,186

 

 

$

23,223

 

 

$

462,857

 

Restricted stock issuances

 

 

8,056

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock forfeited

 

 

(4,905

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock repurchased

 

 

(1,025

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 

 

 

 

 

 

 

 

1,943

 

 

 

 

 

 

 

 

 

1,943

 

Net income

 

 

 

 

 

 

 

 

 

 

 

55,687

 

 

 

 

 

 

55,687

 

Other comprehensive loss, net of tax

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(23,223

)

 

 

(23,223

)

Balance at December 31, 2013

 

 

1,422,160

 

 

 

14

 

 

 

424,377

 

 

 

72,873

 

 

 

 

 

 

497,264

 

Restricted stock issuances

 

 

15,278

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock forfeited

 

 

(11,497

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock repurchased

 

 

(2,025

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 

 

 

 

 

 

 

 

5,301

 

 

 

 

 

 

 

 

 

5,301

 

Net income

 

 

 

 

 

 

 

 

 

 

 

209,293

 

 

 

 

 

 

209,293

 

Balance at December 31, 2014

 

 

1,423,916

 

 

 

14

 

 

 

429,678

 

 

 

282,166

 

 

 

 

 

 

711,858

 

Restricted stock issuances

 

 

1,209

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock forfeited

 

 

(15,091

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted stock repurchased

 

 

(5,725

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Stock-based compensation

 

 

 

 

 

 

 

 

1,629

 

 

 

 

 

 

 

 

 

1,629

 

Net loss

 

 

 

 

 

 

 

 

 

 

 

(1,333,844

)

 

 

 

 

 

(1,333,844

)

Balance at December 31, 2015

 

 

1,404,309

 

 

$

14

 

 

$

431,307

 

 

$

(1,051,678

)

 

$

 

 

$

(620,357

)

 

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

 

 

 

76


Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

 

 

 

Year ended December 31,

 

(in thousands)

 

2015

 

 

2014

 

 

2013

 

Cash flows from operating activities

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(1,333,844

)

 

$

209,293

 

 

$

55,687

 

Adjustments to reconcile net income to net cash provided by

   operating activities

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation, depletion, and amortization

 

 

216,574

 

 

 

245,908

 

 

 

192,426

 

Loss on impairment of assets

 

 

1,507,336

 

 

 

 

 

 

3,490

 

Deferred income taxes

 

 

(177,487

)

 

 

123,891

 

 

 

31,734

 

Gain on hedge reclassification adjustments

 

 

 

 

 

 

 

 

(37,134

)

Non-hedge derivative (gains) losses

 

 

(145,288

)

 

 

(231,320

)

 

 

21,635

 

Gain on sale of assets

 

 

(1,584

)

 

 

(2,152

)

 

 

(670

)

Gain on extinguishment of debt

 

 

(31,590

)

 

 

 

 

 

 

Other

 

 

6,057

 

 

 

4,294

 

 

 

4,418

 

Change in assets and liabilities

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable

 

 

15,720

 

 

 

4,692

 

 

 

(21,216

)

Inventories

 

 

(1,968

)

 

 

(5,516

)

 

 

(5,923

)

Prepaid expenses and other assets

 

 

481

 

 

 

(750

)

 

 

(1,299

)

Accounts payable and accrued liabilities

 

 

(17,200

)

 

 

(24,652

)

 

 

9,977

 

Revenue distribution payable

 

 

(12,075

)

 

 

(671

)

 

 

6,986

 

Stock-based compensation

 

 

(5,524

)

 

 

894

 

 

 

3,942

 

Net cash provided by operating activities

 

 

19,608

 

 

 

323,911

 

 

 

264,053

 

Cash flows from investing activities

 

 

 

 

 

 

 

 

 

 

 

 

Expenditures for property, plant, and equipment

 

 

(313,481

)

 

 

(685,459

)

 

 

(491,022

)

Acquisition of a business

 

 

 

 

 

 

 

 

(153,858

)

Proceeds from asset dispositions

 

 

42,618

 

 

 

291,429

 

 

 

111,246

 

Settlement of non-hedge derivative instruments

 

 

233,605

 

 

 

2,417

 

 

 

19,113

 

Derivative premiums paid and other

 

 

 

 

 

(20,609

)

 

 

(601

)

Net cash used in investing activities

 

 

(37,258

)

 

 

(412,222

)

 

 

(515,122

)

Cash flows from financing activities

 

 

 

 

 

 

 

 

 

 

 

 

Proceeds from long-term debt

 

 

120,000

 

 

 

302,115

 

 

 

297,797

 

Repayment of long-term debt

 

 

(102,978

)

 

 

(228,594

)

 

 

(52,100

)

Repurchase of Senior Notes

 

 

(9,995

)

 

 

 

 

 

 

Proceeds from sale and leaseback of assets

 

 

 

 

 

 

 

 

24,500

 

Principal payments under capital lease obligations

 

 

(2,400

)

 

 

(2,313

)

 

 

(352

)

Payment of other financing fees

 

 

(1,404

)

 

 

 

 

 

 

Net cash provided by financing activities

 

 

3,223

 

 

 

71,208

 

 

 

269,845

 

Net (decrease) increase in cash and cash equivalents

 

 

(14,427

)

 

 

(17,103

)

 

 

18,776

 

Cash and cash equivalents at beginning of period

 

 

31,492

 

 

 

48,595

 

 

 

29,819

 

Cash and cash equivalents at end of period

 

$

17,065

 

 

$

31,492

 

 

$

48,595

 

 

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

 

 

 

77


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.

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; 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, 2015, cash with a recorded balance totaling $13,507 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts. We are not party to any valid blocked account agreements with respect to any material amount of cash.

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. 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.

78


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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:

 

 

 

2015

 

 

2014

 

Joint interests

 

$

14,149

 

 

$

30,648

 

Accrued commodity sales

 

 

21,645

 

 

 

45,667

 

Derivative settlements

 

 

40,380

 

 

 

19,678

 

Other

 

 

3,329

 

 

 

2,738

 

Allowance for doubtful accounts

 

 

(503

)

 

 

(287

)

 

 

$

79,000

 

 

$

98,444

 

 

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. Equipment inventory is carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. We recorded a lower of cost or market adjustment of $10,192 on our equipment inventory for the year ended December 31, 2015. The adjustment was recorded to reflect lower market prices resulting from a decline in demand for such equipment as drilling activity decreased in the low commodity price environment. The adjustment is reflected in “Loss on impairment of other assets” in our consolidated statements of operations. We did not record any significant inventory adjustments in the prior year periods. Inventories consisted of the following at December 31:

 

 

 

2015

 

 

2014

 

Equipment inventory

 

$

11,470

 

 

$

24,169

 

Commodities

 

 

1,698

 

 

 

2,575

 

Inventory valuation allowance

 

 

(839

)

 

 

(1,187

)

 

 

$

12,329

 

 

$

25,557

 

 

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:

 

Furniture and fixtures

 

10 years

Automobiles and trucks

 

5 years

Machinery and equipment

 

10 — 20 years

Office and computer equipment

 

5 — 10 years

Building and improvements

 

10 — 40 years

 

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 acquisition, 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, lease bonus payments, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, and other internal costs directly attributable to these activities.

79


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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. As of December 31, 2015, unevaluated oil and natural gas properties include $60,031 of capital costs incurred for undeveloped acreage and $6,874 for wells and facilities in progress pending determination. As of December 31, 2014, work in progress costs included $190,356 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination. Our work-in-progress balance at December 31, 2015 no longer includes amounts related to the construction of CO2 delivery pipelines and facilities as those have been reclassified to the full-cost amortization base during the third quarter of 2015 in conjunction with our recognition of proved reserves from the development of all remaining phases at our North Burbank Unit.

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, 2015, 2014, and 2013 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 Securities Exchange Commission (“SEC”).

Due to the substantial decline of commodity prices that began in late 2014 and continued through 2015, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, resulting in a ceiling test write-down during the year ended December 31, 2015 of $1,491,129. Further write-downs may occur if prices remain at current levels or continue to decline subsequent to December 31, 2015. 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, nil and $3,490 related to certain of our drilling rigs during the years ended December 31, 2015, 2014 and 2013, respectively. The drilling rigs were previously classified as held for sale but were reclassified to property and equipment in late 2013 when the ultimate disposal became uncertain. One of the rigs was last deployed in January 2015 while the remaining three have been stacked for two to three years. As a result of the recent deterioration in commodity prices and drilling activity, the value of such equipment has 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 during 2015. These losses are reflected in “Loss on impairment of other assets” in our consolidated statements of operations.

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 realized. See “Note 10—Income taxes” for further discussion of our valuation allowance.

80


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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, 2015 and 2014, 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 2008 through 2015 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. Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in “Non-hedge derivative gains (losses)” 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.

Effective April 1, 2010, we elected to discontinue hedge accounting prospectively. The effective portion of changes in the fair value of derivatives qualifying and designated as cash flow hedges was recognized in accumulated other comprehensive income (loss) (“AOCI”) prior to April 1, 2010, and was reclassified into income as the hedged transactions occurred. As of December 31, 2013, all amounts related to de-designated cash flow hedges had been reclassified into earnings.

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, our drilling rigs which we have impaired and valuation of assets and liabilities acquired in our Cabot Acquisition. See “Note 8 —Fair value measurements” for additional information regarding our fair value measurements.

Valuation of business combinations

In connection with a purchase business combination, the acquiring company must record assets acquired and liabilities assumed based on fair values as of the acquisition date. We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions are related to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we utilize estimates of oil and natural gas reserves. We make

81


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

future price assumptions to apply to the estimated reserves quantities acquired and estimate future operating and development costs to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using market-based weighted average cost of capital rates determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rates are subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of the unproved reserves were reduced by additional risk-weighting.

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.

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, 2015 and 2014, 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, 2015 and, 2014 our aggregate imbalance due to under production was approximately 0 MMcf and 2,005 MMcf, respectively. As of December 31, 2015 and 2014, our aggregate imbalance due to over production was approximately 1,253 MMcf and 1,276 MMcf, respectively, and a liability for gas imbalances of $1,303 and $1,110, 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.

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

82


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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.

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, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.

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 —Stock-based compensation” for additional information relating to stock-based compensation.

Cost reduction initiatives

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. Included in our $10,028 of expenses for cost reduction initiatives for the year ended December 31, 2015, is $7,757 for one-time severance and termination benefits in connection with our reduction in force that we began implementing in February 2015. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.

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.

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 FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted only for fiscal years beginning after December 31, 2016, and interim periods thereafter. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

83


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

In August 2014, the FASB issued authoritative guidance that requires entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and requires additional disclosures if certain criteria are met. This guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.

In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs were not affected by the amendment. This guidance, which was effective and adopted by us in the first quarter of 2016, only affects the presentation of our consolidated balance sheets and does not have a material impact on our consolidated financial statements.

In July 2015, the FASB issued authoritative guidance that amends and simplifies the ways businesses value inventory so that businesses that use the first-in, first-out (FIFO) or average cost method will measure inventory at the lower of its cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.

In November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. Current GAAP requires the deferred taxes for each jurisdiction (or tax-paying component of a jurisdiction) to be presented as a net current asset or liability and net noncurrent asset or liability. This requires a jurisdiction-by-jurisdiction analysis based on the classification of the assets and liabilities to which the underlying temporary differences relate, or, in the case of loss or credit carryforwards, based on the period in which the attribute is expected to be realized. Any valuation allowance is then required to be allocated on a pro rata basis, by jurisdiction, between current and noncurrent deferred tax assets. 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.  The guidance is effective for public business entities in fiscal periods beginning after December 15, 2016, and interim periods thereafter. We do not expect this guidance to have a significant impact on our consolidated financial statements, other than balance sheet reclassifications.

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 are currently evaluating the effect the new guidance will have on our financial statements and 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.  All other 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.  Early adoption is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations.

 

Note 2: Going concern and liquidity

Oil and natural gas prices have declined severely since mid 2014 and continue to be depressed in 2016. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices are having a material and adverse effect on our liquidity position. As of December 31, 2015, the total outstanding principal amount of our debt obligations was $1,607,127. For additional detail on each of our debt obligations, see “Note 6—Debt” herein.  On February 11, 2016, we

84


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

borrowed $141,000 under our Credit Facility which represented substantially the entire remaining undrawn amount that was available. Additionally, our cash balance at March 30, 2016 was approximately $176,000.

Our borrowing base under our Credit Facility is subject to its next semi-annual redetermination on May 1, 2016. As a result of depressed market prices in early 2016, we anticipate that the lender-determined pricing that will be utilized to estimate our borrowing base under our Credit Facility will be lower than the pricing utilized in our previous redetermination. Thus, we believe that our borrowing base may be decreased significantly. Since our Credit Facility is fully drawn, any decrease in our borrowing base as a result of the redetermination will result in a deficiency and we would have to repay any outstanding indebtedness in excess of the reduced borrowing base at our election within 30 days or in six monthly installments thereafter.

Based on current market conditions and depressed commodity prices, if we are unable to restructure our debt and adequately address liquidity concerns, we do not expect to be in compliance with the Consolidated Net Secured Debt to EBITDAX (as defined in “Note 6 – Debt”) and Interest Coverage Ratio covenants for the quarter ending September 30, 2016. A failure to meet our financial covenants is an event of default under our Credit Facility which may result in the total outstanding amount on the facility being immediately due.

The consolidated financial statements included in this Annual Report on Form 10-K have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. We incurred a net loss of approximately $1,333,844 during the year ended December 31, 2015, and as of that date, our current liabilities exceeded current assets by approximately $1,522,431 and our equity was a deficit of $620,357. Due to the uncertainty associated with our ability to repay our outstanding debt obligations as they become due, especially in the event of any acceleration of indebtedness, there is substantial doubt about our ability to continue as a going concern. We have reclassified all our long-term debt to current liabilities as of December 31, 2015, due to the defaults and cross defaults on these facilities discussed below, which could result in an acceleration of outstanding amounts. Other than this reclassification, the consolidated financial statements do not reflect any adjustments that might result from the outcome of the uncertainties as discussed herein.

We have substantial interest payment obligations related to our debt over the next twelve months. On March 1, 2016, we elected not to make an interest payment of $16,500, due March 1, 2016, on our 8.25% Senior Notes maturing 2021. Our election to defer our interest payment would not have constituted an event of default as defined under the indenture governing our Senior Notes or any other indenture relating to our other senior notes if the interest payment was made within 30 days of its due date. However, since we do not intend to make the interest payment within 30-day grace period, we expect to be in default effective March 31, 2016, and the trustee or holders of at least 25% in principal amount of our outstanding Senior Notes may declare the principal and any interest immediately due and payable. Our decision to forego the interest payment on our Senior Notes upon expiration of the 30-day grace period will also result in a cross-default under our Credit Facility.

Our Credit Facility requires that our annual financial statements include a report from our independent registered public accounting firm with an opinion that does not contain an explanatory paragraph as to going concern. In consideration of the uncertainties mentioned above, the report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. Consequently, as of the filing date, we are in default under our Credit Facility. We are also in breach of the current ratio covenant under the Credit Facility as a result of our reclassification of all long term debt to current liabilities, as discussed above. We are currently in discussions with our lenders under our Credit Facility.  If the lenders under our Credit Facility accelerate our indebtedness under the Credit Facility as a result of defaults, such acceleration would cause a cross-default and potential acceleration of the maturity of certain of our other outstanding debt obligations including our Senior Notes, our capital lease obligations as well as our real estate mortgage notes and our installment notes. These defaults create additional uncertainty associated with our ability to repay our outstanding debt obligations as they become due.

If we are unable to reach an agreement with our creditors prior to any of the above described accelerations, we could be required to file for protection under Chapter 11 of the U.S. Bankruptcy Code. We are currently pursuing and evaluating several alternatives including (i) debt- for-debt exchanges or debt-for-equity exchanges, (ii) potentially seeking relief under Chapter 11 of the U.S. Bankruptcy Code, (iii) obtaining waivers or amendments from our lenders, (iv) minimizing our planned capital investments, (v) effectively managing our working capital, (vi) improving our cash flows from operations and (vii) dispositions of non-core assets. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet certain obligations.

85


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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 Credit Facility. Our derivative contracts with these counterparties are governed by master agreements which 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 the event of an early termination of our derivative contracts as a result of a default, we may not receive the proceeds from such termination. It is possible that the counterparty financial institutions to our derivative contracts will utilize their right of offset with respect to the Credit Facility to retain such proceeds. Any potential loss of anticipated proceeds from our derivative settlements in 2016 will severely limit our cash from operations and liquidity. Furthermore, if we are in default on our indebtedness or have a bankruptcy filing, we will no longer be able to represent that we comply with the credit default or bankruptcy covenants under our derivative master agreements and thus may not be able to enter into new hedging transactions. On March 4, 2016, we received notification from one of our derivative counterparties reserving all rights under the master agreement governing our derivative transaction with said counterparty. The notice was issued subsequent to our election to defer the Senior Note interest payment on March 1, 2016, which according to the counterparty represents an event of default.

 

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

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

 

 

 

Year ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Net cash provided by operating activities included:

 

 

 

 

 

 

 

 

 

 

 

 

Cash payments for interest

 

$

116,379

 

 

$

112,196

 

 

$

107,122

 

Interest capitalized

 

 

(9,670

)

 

 

(13,491

)

 

 

(15,995

)

Cash payments for interest, net of amounts capitalized

 

$

106,709

 

 

$

98,705

 

 

$

91,127

 

Cash payments for income taxes

 

$

640

 

 

 

591

 

 

 

641

 

Non-cash investing activities included:

 

 

 

 

 

 

 

 

 

 

 

 

Asset retirement obligation additions and revisions

 

$

4,000

 

 

$

7,461

 

 

$

9,036

 

Change in accrued oil and gas capital expenditures

 

$

(105,312

)

 

$

43,971

 

 

$

27,875

 

 

 

Note 4: Acquisitions and divestitures

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

86


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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.

2013 Acquisition and divestitures

Cabot Acquisition. In late 2013, we acquired additional oil and natural gas properties consisting of approximately 131,000 (66,000 net) acres in the Panhandle Marmaton play from Cabot Oil & Gas Corporation for approximately $153,858, net of pre-closing purchase price adjustments and subject to post closing adjustments (the “Cabot Acquisition”). The Cabot Acquisition expanded our presence in the Panhandle Marmaton play, adding oil and natural gas reserves and production to our existing asset base in this area.

Our acquisition qualified as a business combination for accounting purposes and, as such, we estimated the fair value of the acquired properties as of the December 18, 2013 acquisition date, which was the date on which we obtained control of the properties. The fair value of the assets and liabilities acquired was estimated using assumptions that represent Level 3 inputs. See “Note 8—Fair value measurements” for additional discussion of the measurement inputs.  

We estimated the consideration paid for these properties approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or bargain purchase gain was recognized in conjunction with the purchase. Acquisition-related costs of $951 have been expensed as incurred in general and administrative expense in the accompanying consolidated statements of operations for the year ended December 31, 2013.

The following table summarizes the consideration paid to acquire the properties and the amounts of the assets acquired and liabilities assumed as of December 18, 2013.

 

Consideration paid

 

 

 

 

Cash, net of purchase price adjustments

 

$

153,858

 

Fair value of identifiable assets acquired and liabilities assumed

 

 

 

 

Oil and natural gas properties

 

 

 

 

Proved

 

$

67,275

 

Unevaluated

 

 

87,663

 

Asset retirement obligations

 

 

(1,080

)

Fair value of net identifiable assets acquired

 

$

153,858

 

 

The following unaudited pro forma combined results of operations for the year ended December 31, 2013 is presented as though we completed the Cabot Acquisition as of January 1, 2012. The pro forma combined results of operations for the year ended December 31, 2013 has been prepared by adjusting the historical results of the acquired properties and estimates of the effect of the transaction on the combined results. These supplemental pro forma results of operations are provided for illustrative purposes only and do not purport to be indicative of the actual results that would have been achieved had the transaction been in effect for the periods presented or that may be achieved by us in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information below includes adjustments for depletion, depreciation, amortization and accretion expense, interest expense, acquisition costs, and related income tax effects.

 

 

 

Year ended

December 31,

 

 

 

2013

 

Revenues

 

$

690,564

 

Operating expenses

 

$

448,751

 

Net income

 

$

76,552

 

 

Divestitures. During 2013, we sold various oil and natural gas properties for total cash proceeds of approximately $109,710. These included properties in Creek, Love and Carter counties, Oklahoma, that were sold for approximately $61,440 and properties in Texas County, Oklahoma, that were sold for approximately $17,800. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.

 

87


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Note 5: Property and equipment

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

 

 

 

2015

 

 

2014

 

Furniture and fixtures

 

$

2,518

 

 

$

2,488

 

Automobiles and trucks

 

 

10,689

 

 

 

13,721

 

Machinery and equipment

 

 

55,963

 

 

 

57,922

 

Office and computer equipment

 

 

19,993

 

 

 

18,305

 

Building and improvements

 

 

25,534

 

 

 

29,322

 

 

 

 

114,697

 

 

 

121,758

 

Less accumulated depreciation and amortization

 

 

75,041

 

 

 

64,310

 

 

 

 

39,656

 

 

 

57,448

 

Land

 

 

9,306

 

 

 

9,113

 

 

 

$

48,962

 

 

$

66,561

 

 

 

 

 

Note 6: Debt

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

 

 

 

December 31,

 

 

 

2015

 

 

2014

 

9.875% Senior Notes due 2020, net of discount of $4,185 and $4,861, respectively

 

$

293,815

 

 

$

295,139

 

8.25% Senior Notes due 2021

 

 

384,045

 

 

 

400,000

 

7.625% Senior Notes due 2022, including premium of $4,939 and $4,869, respectively

 

 

530,849

 

 

 

554,869

 

Credit Facility

 

 

367,000

 

 

 

347,000

 

Real estate mortgage notes, principal and interest payable monthly, bearing interest at

   rates ranging from 3.16% to 5.46%, due August 2021 through December 2028;

   collateralized by real property

 

 

10,182

 

 

 

10,705

 

Installment notes payable, principal and interest payable monthly, bearing interest at rates

   ranging from 2.85% to 5.95%, due January 2016 through February 2018; collateralized

   by automobiles, machinery and equipment

 

 

1,799

 

 

 

4,252

 

Capital lease obligations

 

 

19,437

 

 

 

21,837

 

Total debt, net

 

 

1,607,127

 

 

 

1,633,802

 

Less current portion (1)

 

 

1,607,127

 

 

 

5,377

 

Total long-term debt, net

 

$

 

 

$

1,628,425

 

 

(1) As a result of defaults on our debt as of the filing date of this report, our long-term debt was classified as current at December 31, 2015.

 

Absent any acceleration of our debt resulting from defaults, the maturities of debt and capital leases, and excluding premiums or discounts on our Senior Notes, would be as follows as of December 31, 2015:

 

2016

 

$

4,409

 

2017

 

 

370,600

 

2018

 

 

3,302

 

2019

 

 

12,328

 

2020

 

 

298,687

 

2021 and thereafter

 

 

917,047

 

 

 

$

1,606,373

 

 

88


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Senior Notes

The Senior Notes, which, as of December 31, 2015, include our 9.875% senior notes due 2020, our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) are our senior unsecured obligations, 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 are 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 is payable semi-annually, and the principal is 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 $945, $(268), and $(387) during the years ended December 31, 2015, 2014 and 2013, respectively.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:

 

·

incur or guarantee additional debt and issue certain types of preferred stock;

 

·

pay dividends on capital stock or redeem, repurchase, or retire capital stock or subordinated debt;

 

·

make investments;

 

·

incur liens on assets;

 

·

create restrictions on the ability of our restricted subsidiaries to pay dividends or make other payments to us;

 

·

engage in transactions with affiliates;

 

·

sell assets, including capital stock of our subsidiaries;

 

·

consolidate, merge or transfer assets; and

 

·

enter into other lines of business.

If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Chaparral Biofuels, LLC.

As discussed in “Note 2—Going concern and liquidity,” we deferred an interest payment due on our Senior Notes on March 1, 2016, and do not intend to make the payment prior to the expiration of the 30-day grace period. As such, we will be in default under the indenture governing our Senior Notes as of March 31, 2016.

Credit Facility

In April 2010, we entered into an Eighth Restated Credit Agreement, which is collateralized by our oil and natural gas properties and, as amended, is originally scheduled to mature on November 1, 2017. Availability under our Credit Facility is subject to a borrowing base which is 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 and in the event of early termination of our derivative contracts. 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 our Credit Facility for 2015 was $650,000. Our first semiannual borrowing base redetermination for the current year was finalized in conjunction with an amendment to our Credit Facility (the “Fifteenth Amendment”), effective on

89


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

April 1, 2015, and reduced the borrowing base to $550,000. Our next semiannual borrowing base redetermination, which was effective on October 29, 2015, reaffirmed our borrowing base at $550,000.

Amounts borrowed under our 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, 2015 was subject to the Eurodollar rate. In the event of a default under the Credit Facility, subsequent interest on outstanding amounts will be charged by our lenders based on the ABR plus an additional 2.00% and plus the applicable margin.

The Eurodollar rate is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our Credit Facility, plus a margin that varies depending on our utilization percentage. During 2015, the applicable margin varied from 2.00% to 2.25%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than 3 months or every 3 months.

Interest on loans subject to the ABR is computed as the greater of (1) the Prime Rate, as defined in our Credit Facility, (2) the Federal Funds Effective Rate, as defined in our Credit Facility, plus 0.50%, or (3) the Adjusted LIBO Rate, as defined in our Credit Facility, plus 1.00%, plus a margin that varies depending on our utilization percentage. We did not have loans subject to the ABR during 2015.

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 have the right to make prepayments of the borrowings at any time without penalty or premium.

Our Credit Facility contains restrictive covenants that may limit our ability, among other things, to:

 

·

incur additional indebtedness;

 

·

create or incur additional liens on our oil and natural gas properties;

 

·

pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;

 

·

make investments in or loans to others;

 

·

change our line of business;

 

·

enter into operating leases;

 

·

merge or consolidate with another person, or lease or sell all or substantially all of our assets;

 

·

sell, farm-out or otherwise transfer property containing proved reserves;

 

·

enter into transactions with affiliates;

 

·

issue preferred stock;

 

·

enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;

 

·

enter into or terminate certain swap agreements;

 

·

amend our organizational documents; and

 

·

amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.

Our Credit Facility, as amended, also has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our Credit Facility, of not less than 1.0 to 1.0. In connection with the Fifteenth Amendment, effective April 1, 2015, the Consolidated Net Debt to Consolidated EBITDAX covenant previously required by our Credit Facility was replaced by a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no

90


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.0 to 1.0.

Additionally, our Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under our Credit Facility. An acceleration of our indebtedness under our Credit Facility could in turn result in an event of default under the indentures for our Senior Notes, which in turn could result in the acceleration of the Senior Notes.

Under the Fifteenth Amendment, we are allowed to incur an additional $300,000 in Additional Permitted Debt, as revised and defined in the amendment to now include both secured and unsecured debt. We incurred $1,404 in fees associated with the Fifteenth Amendment.

If the outstanding borrowings under our Credit Facility 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 30 days or in equal monthly installments over a six -month period, (2) to submit within 30 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base 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 30 days.

Recent events related to our liquidity as discussed in “Note 2—Going concern and liquidity” have or will result in events of default under our Credit Facility.  

Debt issuance costs

The costs that we incur to issue debt include underwriting and other professional fees. These costs are initially capitalized and are included in “Other assets” in the consolidated balance sheets. The balance of unamortized issuance costs was $18,359 and $20,937 as of December 31, 2015 and 2014, respectively. These costs are amortized as a charge to interest expense using the effective interest method. We recorded amortization of $1,921, $2,335 and $2,197 for the years ended, December 31, 2015, 2014 and 2013, respectively.

Per new guidance issued in early 2015, debt issuance costs, excluding those associated with line-of-credit arrangements, will no longer be recorded in “Other assets” in the consolidated balance sheets but will be recorded as a direct deduction from the carrying value of the Senior Notes. This change in presentation will begin in 2016. See “Note 1—Nature of operations and summary of significant accounting policies” for further discussion.

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.

Senior Note repurchases

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. The senior notes and notional amounts repurchased are as follows:

91


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

 

·

9.875% senior notes due 2020 – $2,000; 

 

·

8.25% senior notes due 2021 – $15,955;

 

·

7.625% senior notes due 2022 – $24,090.

 

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, enhanced price swaps, collars, put options, 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 that are not costless but instead require payment of a premium such as purchased puts, collars and three-way collars. The cash 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.

For commodity price swaps, we 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.

We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. 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. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection. A put spread may also be constructed by entering into separate sold put and purchased put contracts.

On a purchased put option, if the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor in an environment where prices have declined. 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.

We use basis protection swaps 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 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.

92


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

As discussed in “Note 2 – Going concern and liquidity” certain events relating to our liquidity may impact our compliance under the master agreements that govern our derivative transactions.

The following table summarizes our crude oil derivatives outstanding as of December 31, 2015:

 

 

 

 

 

 

 

Weighted average fixed price per Bbl

 

Period and type of contract

 

Volume

MBbls

 

 

Swaps

 

 

Sold puts

 

 

Purchased

puts

 

 

Sold calls

 

 

Average

deferred

premium

 

2016

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars

 

 

240

 

 

$

 

 

$

84.00

 

 

$

92.00

 

 

$

101.01

 

 

$

 

Three-way collars (1)

 

 

480

 

 

$

 

 

$

40.00

 

 

$

52.50

 

 

$

72.50

 

 

$

2.95

 

Enhanced swaps (2)

 

 

3,720

 

 

$

92.94

 

 

$

80.52

 

 

$

 

 

$

 

 

$

 

Purchased puts (2)

 

 

3,720

 

 

$

 

 

$

 

 

$

60.00

 

 

$

 

 

$

 

2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three-way collars (1)

 

 

480

 

 

$

 

 

$

42.50

 

 

$

55.00

 

 

$

80.00

 

 

$

2.78

 

 

(1)

These contracts include deferred premiums that are payable upon settlement.

(2)

Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $41.45 for 2016 as of December 31, 2015, the average realized price, and concurrently the floor price, of our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42 per barrel. In the event that prices increase above $60.00 per barrel upon settlement, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

The following tables summarize our natural gas derivative instruments outstanding as of December 31, 2015:

 

Period and type of contract

 

Volume

BBtu

 

 

Weighted

average

fixed price

per MMBtu

 

2016

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

14,000

 

 

$

4.19

 

Natural gas basis protection swaps

 

 

8,400

 

 

$

0.36

 

2017

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

12,700

 

 

$

3.64

 

2018

 

 

 

 

 

 

 

 

Natural gas swaps

 

 

8,250

 

 

$

3.83

 

 

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 495,000 barrels of oil and 12,280 BBtu of natural gas, in order to maintain compliance with the hedging limits imposed by covenants under our 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.

93


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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.

 

 

 

As of December 31, 2015

 

 

As of December 31, 2014

 

 

 

Assets

 

 

Liabilities

 

 

Net value

 

 

Assets

 

 

Liabilities

 

 

Net value

 

Natural gas swaps

 

$

41,328

 

 

$

 

 

$

41,328

 

 

$

32,939

 

 

$

 

 

$

32,939

 

Oil swaps

 

 

 

 

 

 

 

 

 

 

 

23,465

 

 

 

 

 

 

23,465

 

Oil three-way collars

 

 

6,500

 

 

 

 

 

 

6,500

 

 

 

1,175

 

 

 

 

 

 

1,175

 

Oil enhanced swaps

 

 

45,516

 

 

 

 

 

 

45,516

 

 

 

100,724

 

 

 

 

 

 

100,724

 

Oil purchased and sold puts

 

 

71,052

 

 

 

 

 

 

71,052

 

 

 

93,268

 

 

 

 

 

 

93,268

 

Natural gas basis differential swaps

 

 

 

 

 

(1,158

)

 

 

(1,158

)

 

 

292

 

 

 

(309

)

 

 

(17

)

Total derivative instruments

 

 

164,396

 

 

 

(1,158

)

 

 

163,238

 

 

 

251,863

 

 

 

(309

)

 

 

251,554

 

Less:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Netting adjustments (1)

 

 

1,158

 

 

 

(1,158

)

 

 

 

 

 

232

 

 

 

(232

)

 

 

 

Derivative instruments - current

 

 

143,737

 

 

 

 

 

 

143,737

 

 

 

179,921

 

 

 

(77

)

 

 

179,844

 

Derivative instruments - long-term

 

$

19,501

 

 

$

 

 

$

19,501

 

 

$

71,710

 

 

$

 

 

$

71,710

 

 

(1)

Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.

Derivative settlements outstanding were as follows at December 31:

 

 

 

2015

 

 

2014

 

Derivative settlements receivable included in accounts receivable

 

$

40,380

 

 

$

19,678

 

 

Effect of derivative instruments on the consolidated statements of operations

We discontinued hedge accounting effective April 1, 2010, and have since no longer applied 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 gains (losses)” in the consolidated statements of operations. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through AOCI and upon settlement, were reclassified from AOCI into gain from oil hedging activities which was a component of total revenues in the consolidated statements of operations. After December 31, 2013, there were no longer any deferred gains in AOCI as all the previously deferred gains (losses) had been reclassified into earnings upon the sale of the hedged production.

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

 

 

 

2015

 

 

2014

 

 

2013

 

Change in fair value of commodity price swaps

 

$

(15,077

)

 

$

59,627

 

 

$

(20,717

)

Change in fair value of collars

 

 

5,325

 

 

 

(1,597

)

 

 

(23,459

)

Change in fair value of enhanced swaps and put options

 

 

(77,424

)

 

 

172,533

 

 

 

186

 

Change in fair value of natural gas basis differential contracts

 

 

(1,141

)

 

 

(1,660

)

 

 

3,242

 

Receipts from (payments on) settlement of commodity price swaps

 

 

56,734

 

 

 

(6,607

)

 

 

5,122

 

(Payments on) receipts from settlement of collars

 

 

(24

)

 

 

7,382

 

 

 

14,548

 

Receipts from settlement of enhanced swaps and put options

 

 

177,178

 

 

 

2,221

 

 

 

 

Payments on settlement of natural gas basis differential contracts

 

 

(283

)

 

 

(579

)

 

 

(557

)

Non-hedge derivative gains (losses)

 

$

145,288

 

 

$

231,320

 

 

$

(21,635

)

 

 

94


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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 have no Level 1 assets or liabilities as of December 31, 2015 or December 31, 2014. Our derivative contracts classified as Level 2 as of December 31, 2015 and December 31, 2014 consisted of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate.

As of December 31, 2015 and December 31, 2014, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, sold puts 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:  

 

 

 

As of December 31, 2015

 

 

As of December 31, 2014

 

 

 

Derivative

assets

 

 

Derivative

liabilities

 

 

Net assets

(liabilities)

 

 

Derivative

assets

 

 

Derivative

liabilities

 

 

Net assets

(liabilities)

 

Significant other observable inputs (Level 2)

 

$

41,328

 

 

$

(1,158

)

 

$

40,170

 

 

$

56,696

 

 

$

(309

)

 

$

56,387

 

Significant unobservable inputs (Level 3)

 

 

123,068

 

 

 

 

 

 

123,068

 

 

 

195,167

 

 

 

 

 

 

195,167

 

Netting adjustments (1)

 

 

(1,158

)

 

 

1,158

 

 

 

 

 

 

(232

)

 

 

232

 

 

 

 

 

 

$

163,238

 

 

$

 

 

$

163,238

 

 

$

251,631

 

 

$

(77

)

 

$

251,554

 

 

(1)

Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy at December 31, 2015 and 2014 were:

 

Net derivative assets

 

2015

 

 

2014

 

Beginning balance

 

$

195,167

 

 

$

3,622

 

Realized and unrealized gains (losses) included in non-hedge derivative gains (losses)

 

 

105,055

 

 

 

180,539

 

Purchases

 

 

 

 

 

20,609

 

Settlements received

 

 

(177,154

)

 

 

(9,603

)

Ending balance

 

$

123,068

 

 

$

195,167

 

Gains relating to instruments still held at the reporting date included in non-hedge

   derivative gains (losses) for the period

 

$

61,260

 

 

$

169,442

 

 

Nonrecurring fair value measurements

Allocation of purchase price in business combinations. The estimated fair values of proved oil and gas properties and asset retirement obligations assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk-adjusted discount rates. The estimated fair values of unevaluated oil and gas properties was based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of these assumptions, they are considered

95


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Level 3 inputs under the fair value hierarchy. See “Note 4—Acquisitions and divestitures” for additional information regarding our acquisitions.

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, 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 15.09% and 7.60%, 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 on four of our stacked drilling rigs during the second quarter of 2015. The estimated fair value related to the impairment assessment for our four drilling rigs no longer in service was primarily based on third party estimates and, therefore, is classified within Level 3 of the fair value hierarchy. During the years ended December 31, 2015 and 2013, we recognized impairment losses of $6,015 and $3,490, respectively, related to our four stacked drilling rigs and drill pipe. No impairment was recognized on our drilling rigs for the year ended December 31, 2014.

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, 2015 and 2014 were as follows:

 

 

 

December 31, 2015

 

 

December 31, 2014

 

Level 2

 

Carrying

value

 

 

Estimated

fair value

 

 

Carrying

value

 

 

Estimated

fair value

 

9.875% Senior Notes due 2020

 

$

293,815

 

 

$

75,750

 

 

$

295,139

 

 

$

269,091

 

8.25% Senior Notes due 2021

 

 

384,045

 

 

 

96,956

 

 

 

400,000

 

 

 

270,000

 

7.625% Senior Notes due 2022

 

 

530,849

 

 

 

120,478

 

 

 

554,869

 

 

 

379,775

 

Credit Facility

 

 

367,000

 

 

 

367,000

 

 

 

347,000

 

 

 

347,000

 

Other secured debt

 

 

11,981

 

 

 

11,981

 

 

 

14,957

 

 

 

14,957

 

 

 

$

1,587,690

 

 

$

672,165

 

 

$

1,611,965

 

 

$

1,280,823

 

 

The fair value of our Senior Notes was estimated based on quoted market prices. The carrying value of our credit facility approximates fair value because it has a variable interest rate and incorporates a measure of our credit risk. 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 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,

96


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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 credit facility can be offset against amounts owed to such counterparty lender under our credit facility. As of December 31, 2015, the counterparties to our open derivative contracts consisted of seven financial institutions, of which seven were subject to our rights of offset under our credit facility.

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 credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our credit facility.

 

 

 

Offset in the consolidated balance sheets

 

 

Gross amounts not offset in the consolidated balance sheets

 

 

 

Gross assets (liabilities)

 

 

Offsetting assets (liabilities)

 

 

Net assets (liabilities)

 

 

Derivatives (1)

 

 

Amounts outstanding

under credit facility

 

 

Net amount

 

As of December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets

 

$

164,396

 

 

$

(1,158

)

 

$

163,238

 

 

$

 

 

$

(103,618

)

 

$

59,620

 

Derivative liabilities

 

 

(1,158

)

 

 

1,158

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

$

163,238

 

 

$

 

 

$

163,238

 

 

$

 

 

$

(103,618

)

 

$

59,620

 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets

 

$

251,863

 

 

$

(232

)

 

$

251,631

 

 

$

 

 

$

(118,430

)

 

$

133,201

 

Derivative liabilities

 

 

(309

)

 

 

232

 

 

 

(77

)

 

$

 

 

 

 

 

 

(77

)

 

 

$

251,554

 

 

$

 

 

$

251,554

 

 

$

 

 

$

(118,430

)

 

$

133,124

 

 

 

(1)

Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our credit facility. Payment on our derivative contracts could be accelerated in the event of a default on our credit facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $1,158 at December 31, 2015.

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:

 

 

 

2015

 

 

2014

 

 

2013

 

Valero Energy Corporation

 

 

20.7

%

 

 

23.7

%

 

 

20.1

%

Coffeyville Resources LLC

 

 

14.5

%

 

 

14.0

%

 

 

19.1

%

Phillips 66 Company

 

 

11.8

%

 

*

 

 

*

 

 

* Less than 10%

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

 

97


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:

 

 

 

For the year ended December 31,

 

 

 

2015

 

 

2014

 

Beginning balance

 

$

47,424

 

 

$

55,179

 

Liabilities incurred in current period

 

 

1,861

 

 

 

5,011

 

Liabilities settled or disposed in current period

 

 

(6,472

)

 

 

(19,184

)

Revisions in estimated cash flows

 

 

2,139

 

 

 

2,450

 

Accretion expense

 

 

3,660

 

 

 

3,968

 

Asset retirement obligations at end of period

 

 

48,612

 

 

 

47,424

 

Less current portion included in accounts payable and accrued liabilities

 

 

2,178

 

 

 

4,147

 

Asset retirement obligations, long-term

 

$

46,434

 

 

$

43,277

 

 

Liabilities incurred and assumed include obligations related to new wells drilled and wells acquired during the period. Liabilities settled or disposed for the year ended December 31, 2015 increased significantly primarily due to the divestiture of certain non-strategic oil and natural gas properties sold during 2015 combined with increased plugging and abandoning activity.

We have funds held in escrow that are legally restricted for certain of our asset retirement obligations. The balance of this escrow account was $1,567 and $1,568 at December 31, 2015 and 2014, 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:  

 

 

 

2015

 

 

2014

 

 

2013

 

Current income taxes

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

$

(21

)

 

$

(22

)

 

$

(29

)

State

 

 

195

 

 

 

574

 

 

 

1,144

 

Total current income taxes

 

 

174

 

 

 

552

 

 

 

1,115

 

Deferred income taxes

 

 

 

 

 

 

 

 

 

 

 

 

Federal

 

 

(161,879

)

 

 

115,699

 

 

 

30,327

 

State

 

 

(15,514

)

 

 

8,192

 

 

 

1,407

 

Total deferred income taxes

 

 

(177,393

)

 

 

123,891

 

 

 

31,734

 

Income tax (benefit) expense

 

$

(177,219

)

 

$

124,443

 

 

$

32,849

 

 

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:

 

 

 

2015

 

 

2014

 

 

2013

 

Federal statutory rate

 

 

35.0

%

 

 

35.0

%

 

 

35.0

%

State income taxes, net of federal benefit

 

 

3.1

%

 

 

2.6

%

 

 

3.8

%

Statutory depletion

 

 

 

 

 

(0.2

)%

 

 

(0.7

)%

Valuation allowance

 

 

(26.5

)%

 

 

 

 

 

(1.7

)%

Other, net

 

 

0.1

%

 

 

(0.1

)%

 

 

0.7

%

Effective tax rate

 

 

11.7

%

 

 

37.3

%

 

 

37.1

%

 

98


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:

 

 

 

2015

 

 

2014

 

Deferred tax assets related to

 

 

 

 

 

 

 

 

Asset retirement obligations

 

$

14,669

 

 

$

12,988

 

Accrued expenses, allowance and other

 

 

11,564

 

 

 

15,057

 

Property and equipment

 

 

259,096

 

 

 

 

Inventories

 

 

372

 

 

 

 

Net operating loss carryforwards

 

 

 

 

 

 

 

 

Federal

 

 

154,265

 

 

 

121,556

 

State

 

 

21,466

 

 

 

15,052

 

Statutory depletion carryforwards

 

 

3,962

 

 

 

3,833

 

Alternative minimum tax credit carryforwards

 

 

308

 

 

 

308

 

 

 

 

465,702

 

 

 

168,794

 

Less valuation allowance

 

 

(411,147

)

 

 

(10,499

)

Deferred tax asset

 

 

54,555

 

 

 

158,295

 

Deferred tax liabilities related to

 

 

 

 

 

 

 

 

Derivative instruments

 

 

(54,555

)

 

 

(88,910

)

Property and equipment

 

 

 

 

 

(245,629

)

Inventories

 

 

 

 

 

(1,243

)

Deferred tax liability

 

 

(54,555

)

 

 

(335,782

)

Net deferred tax liability

 

 

 

 

 

(177,487

)

Less net current deferred tax liability

 

 

(53,914

)

 

 

(60,728

)

Long-term deferred tax asset (liability)

 

$

53,914

 

 

$

(116,759

)

 

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.

A significant item of objective negative evidence considered was our cumulative historical three year pre-tax loss and our net deferred tax asset position at December 31, 2015, driven primarily by the full cost ceiling impairments recognized during the third quarter and fourth quarter of 2015, which limits the ability to consider other subjective evidence such as the Company’s anticipated 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 additional valuation allowance totaling approximately $225,000 (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 September 30, 2015. The valuation allowance was further increased by $176,000 to $411,147 against our net deferred tax assets as of December 31, 2015, reducing our net deferred tax assets to zero.

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 $441,000 at December 31, 2015, which will expire between 2028 and 2035 if not utilized in earlier periods. At December 31, 2015, we have state net operating loss carryforwards of approximately $530,000, which will expire between 2016 and 2035 if not utilized in earlier periods. In addition,

99


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

at December 31, 2015 we had federal percentage depletion carryforwards of approximately $11,000, which are not subject to expiration.

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.

We do not have a Section 382 limitation on our ability to utilize our U.S. loss carryforwards as of December 31, 2015. In 2016, however, certain restructuring activities being pursued could impact the ultimate realization of our net operating losses and our tax basis. Future equity transactions involving the Company or 5% of our shareholders (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes resulting in a Section 382 limitation in 2016 on the annual utilization of our loss carryforwards. Filing for protection under Chapter 11 of the U.S. Bankruptcy Code or a Section 382 limitation might cause our tax attributes to be reduced and/or subject to annual utilization limits. A significant portion of our NOL may be offset by tax gains or cancellation of debt.

 

 

Note 11: Stock-based 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.

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.

Although the Phantom Plan and RSU Plan both remain in effect, we do not expect to make any further awards under those plans.

100


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

A summary of our phantom stock and RSU activity during the three years ended December 31, 2015 is presented in the following table:

 

 

 

Phantom Plan

 

 

RSU Plan

 

 

 

Weighted

average

grant date

fair value

 

 

Phantom

shares

 

 

Vest

date

fair

value

 

 

Weighted

average

grant date

fair value

 

 

Restricted Stock Units

 

 

Vest

date

fair

value

 

 

 

(per share)

 

 

 

 

 

 

 

 

 

 

(per share)

 

 

 

 

 

 

 

 

 

Unvested and outstanding at January 1, 2013

 

$

16.87

 

 

 

84,764

 

 

 

 

 

 

$

17.12

 

 

 

151,909

 

 

 

 

 

Granted

 

$

 

 

 

 

 

 

 

 

 

$

12.45

 

 

 

291,253

 

 

 

 

 

Vested

 

$

16.20

 

 

 

(21,260

)

 

$

273

 

 

$

17.12

 

 

 

(50,246

)

 

$

626

 

Forfeited

 

$

17.57

 

 

 

(10,342

)

 

 

 

 

 

$

14.27

 

 

 

(67,619

)

 

 

 

 

Unvested and outstanding at December 31, 2013

 

$

17.01

 

 

 

53,162

 

 

 

 

 

 

$

13.53

 

 

 

325,297

 

 

 

 

 

Granted

 

$

 

 

 

 

 

 

 

 

 

$

8.52

 

 

 

504,752

 

 

 

 

 

Vested

 

$

12.61

 

 

 

(22,041

)

 

$

212

 

 

$

13.96

 

 

 

(118,400

)

 

$

1,094

 

Forfeited

 

$

19.95

 

 

 

(7,942

)

 

 

 

 

 

$

9.85

 

 

 

(142,489

)

 

 

 

 

Unvested and outstanding at December 31, 2014

 

$

20.18

 

 

 

23,179

 

 

 

 

 

 

$

9.91

 

 

 

569,160

 

 

 

 

 

Granted

 

$

 

 

 

 

 

 

 

 

 

$

14.88

 

 

 

59,571

 

 

 

 

 

Vested

 

$

24.48

 

 

 

(6,456

)

 

$

25

 

 

$

10.73

 

 

 

(216,941

)

 

$

855

 

Forfeited

 

$

18.33

 

 

 

(6,104

)

 

 

 

 

 

$

9.56

 

 

 

(141,904

)

 

 

 

 

Unvested and outstanding at December 31, 2015

 

$

18.62

 

 

 

10,619

 

 

 

 

 

 

$

10.53

 

 

 

269,886

 

 

 

 

 

 

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, 2015 is $0.00. The weighted average period until all remaining phantom shares and RSUs vest is 0.7 years.

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. We awarded $3,297 of cash incentive awards in 2015, and recorded compensation expense of $610 for the year ended December 31, 2015.

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.

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

101


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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:

 

Return on investment target

 

Shares vested

175%

 

per share

 

 

33

%

 

of shares multiplied by the Vesting Fraction

200%

 

per share

 

 

33

%

 

of shares multiplied by the Vesting Fraction

250%

 

per share

 

 

34

%

 

of shares multiplied by the Vesting Fraction

 

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.

A combined income and market valuation methodology was used to estimate the fair value of our common equity per share. The fair value of the Time Vested awards granted during 2015, 2014, and 2013 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%, 20%, and 17%, respectively. A control discount was not applied to the valuation pursuant to guidance released by the AICPA in 2013 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.

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:

 

 

 

2015

 

 

2014

 

 

2013

 

Risk free interest rate

 

 

0.71

%

 

to

 

 

1.44

%

 

 

0.25

%

 

to

 

 

1.48

%

 

 

0.16

%

 

to

 

 

2.46

%

Expected volatility

 

 

71

%

 

to

 

 

81

%

 

 

52

%

 

to

 

 

56

%

 

 

38

%

 

to

 

 

39

%

Expected life

 

 

 

 

 

 

 

3 years

 

 

 

 

 

 

 

 

4 years

 

 

 

 

 

 

 

 

5 years

 

Expected dividends

 

 

 

 

 

 

 

$

 

 

 

 

 

 

 

 

$

 

 

 

 

 

 

 

 

$

 

 

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.

102


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

A summary of our Time and Performance award activity during the three years ended December 31, 2015 is presented in the following table:

 

 

 

Time Vested

 

 

Performance Vested

 

 

 

Weighted

average

grant date

fair value

 

 

Restricted

shares

 

 

Vest

date

fair

value

 

 

Weighted

average

grant date

fair value

 

 

Restricted

shares

 

 

 

($ per share)

 

 

 

 

 

 

 

 

 

 

($ per share)

 

 

 

 

 

Unvested and outstanding at January 1, 2013

 

$

651.97

 

 

 

9,481

 

 

 

 

 

 

$

298.15

 

 

 

55,824

 

Granted

 

$

626.02

 

 

 

2,839

 

 

 

 

 

 

$

181.59

 

 

 

5,217

 

Vested

 

$

662.55

 

 

 

(2,509

)

 

$

1,556

 

 

$

 

 

 

 

Forfeited

 

$

618.87

 

 

 

(1,734

)

 

 

 

 

 

$

340.23

 

 

 

(3,171

)

Modified

 

$

626.00

 

 

 

11,169

 

 

 

 

 

 

$

324.47

 

 

 

(11,169

)

Unvested and outstanding at December 31, 2013

 

$

634.67

 

 

 

19,246

 

 

 

 

 

 

$

307.45

 

 

 

46,701

 

Granted

 

$

818.50

 

 

 

5,245

 

 

 

 

 

 

$

204.90

 

 

 

10,033

 

Vested

 

$

643.55

 

 

 

(4,951

)

 

$

4,118

 

 

$

 

 

 

 

Forfeited

 

$

631.54

 

 

 

(3,045

)

 

 

 

 

 

$

264.54

 

 

 

(8,452

)

Modified

 

$

969.00

 

 

 

9,339

 

 

 

 

 

 

$

296.69

 

 

 

(9,339

)

Unvested and outstanding at December 31, 2014

 

$

791.52

 

 

 

25,834

 

 

 

 

 

 

$

292.92

 

 

 

38,943

 

Granted

 

$

533.80

 

 

 

610

 

 

 

 

 

 

$

113.90

 

 

 

599

 

Vested

 

$

775.17

 

 

 

(8,468

)

 

$

4,497

 

 

$

 

 

 

 

Forfeited

 

$

774.21

 

 

 

(3,997

)

 

 

 

 

 

$

323.53

 

 

 

(11,094

)

Unvested and outstanding at December 31, 2015

 

$

795.13

 

 

 

13,979

 

 

 

 

 

 

$

278.97

 

 

 

28,448

 

 

During 2015, 2014, and 2013, respectively, we repurchased and canceled 5,725, 2,025, and 1,025 vested shares and we expect to repurchase approximately 2,355 restricted shares vesting during the next twelve months. Based on an estimated fair value of $18.70 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $261 as of December 31, 2015.

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:

 

 

 

2015

 

 

2014

 

 

2013

 

Stock-based compensation cost

 

$

(2,169

)

 

$

6,235

 

 

$

7,819

 

Less: stock-based compensation cost capitalized

 

 

229

 

 

 

(2,346

)

 

 

(2,345

)

Stock-based compensation (credit) expense

 

$

(1,940

)

 

$

3,889

 

 

$

5,474

 

Recognized tax (expense) benefit associated with stock-based compensation

 

$

(229

)

 

$

1,452

 

 

$

2,031

 

 

Expense during 2015 was a credit as a result forfeitures and the reduction in fair value of our liability-based awards due to depressed commodity prices. Payments for stock-based compensation were $3,991, $2,995, and $1,533 during 2015, 2014, and 2013, respectively. As of December 31, 2015 and 2014, accrued payroll and benefits payable included $81 and $4,830, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized stock-based compensation cost of approximately $4,281 as of December 31, 2015 is expected to be recognized over a weighted-average period of 1.7 years.

 

 

103


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Note 12: Stockholders’ equity

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.

All remaining shares of class B through G common stock will automatically convert to class A common stock upon consummation of an initial public offering of shares of class A common stock resulting in proceeds to us of at least $250,000, which is underwritten on a firm commitment basis by a nationally recognized investment banking firm, and which results in the initial listing or quotation of the class A common stock on any national securities exchange (a “Qualified IPO”).

Holders of class B and C common stock have the right, in aggregate, to designate three directors. Holders of class E common stock have the right to designate two directors.

The class B, E, F and G common stock carry the following additional voting and consent rights:

 

·

So long as the class B holders own 80% or more of the common stock they owned as of April 12, 2010, the closing date of our initial Stockholders Agreement (the “Original Date”), and without such holder’s prior consent, we may neither initiate nor consummate a sale of the Company, whether in the form of a stock sale, asset sale, merger or any other form whatsoever (a “Company Sale”), or a liquidation or dissolution of the Company, on or prior to the sixth anniversary of the Original Date.

 

·

In certain circumstances, we are prohibited from incurring debt, consummating sales or acquisitions of assets, taking certain operational actions or engaging in other specified transactions without the prior consent of the holders of the class E common stock.

 

·

Upon the triggering of a Company Sale or a Demand IPO (each as summarized below) by holders of class E common stock, the voting and other rights related to the class F common stock will permit holders of class E common stock to cause any actions necessary to be taken by our board of directors or stockholders to consummate such Company Sale or Demand IPO.

 

·

Upon the triggering of a Demand IPO by a majority in interest of our existing stockholders, the voting and other rights related to the class G common stock will permit the majority of the holders of class G common stock to cause any actions necessary to be taken by the Company’s board of directors or stockholders to consummate such Demand IPO.

The rights and preferences of a holder of class B, C, E, F and G common stock terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.

Stockholders Agreement

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.

104


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

Our Stockholders Agreement, as amended, also provides for the following stockholder-specific rights or restrictions:

 

·

Prior to a Qualified IPO, Altoma Energy GP (“Altoma”) will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO, (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer Investments, L.L.C. (“Fischer”) votes for such approval.

 

·

Other than pursuant to the exercise of preemptive rights, Healthcare of Ontario Pension Plan Trust Fund may not acquire more than 25% of our outstanding common stock.

 

·

CCMP may sell up to 20% of its common stock owned on the Original Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Stockholders Agreement (the “ROFO provisions”).

 

·

Fischer may sell up to 20% of its common stock owned immediately prior to the Original Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

 

·

Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, and then to Fischer and CCMP in accordance with the procedures set forth in the Stockholders Agreement.

 

·

Either (i) CCMP or (ii) a majority in interest of Fischer and Altoma may demand that we engage in a Qualified IPO (a “Demand IPO”), if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock pursuant to the Stock Purchase Agreement and (b) certain other conditions are met.

 

·

At any time after the four year anniversary of the Original Date, CCMP may demand a Demand IPO.

 

·

At any time after the sixth anniversary of the Original Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale, subject to a right of first offer to purchase the Company provided to Fischer.

With the exception of registration rights, the rights and preferences of a stockholder under the amended and restated Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.

105


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, 2015, 2014 and 2013:

 

 

 

Common Stock

 

 

 

Class A

 

 

Class B

 

 

Class C

 

 

Class D

 

 

Class E

 

 

Class F

 

 

Class G

 

 

Total

 

Shares issued at January 1, 2013

 

 

67,991

 

 

 

357,882

 

 

 

209,882

 

 

 

279,999

 

 

 

504,276

 

 

 

1

 

 

 

3

 

 

 

1,420,034

 

Restricted stock issuance

 

 

8,056

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

8,056

 

Restricted stock repurchased

 

 

(1,025

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,025

)

Restricted stock forfeited

 

 

(4,905

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(4,905

)

Shares issued at December 31, 2013

 

 

70,117

 

 

 

357,882

 

 

 

209,882

 

 

 

279,999

 

 

 

504,276

 

 

 

1

 

 

 

3

 

 

 

1,422,160

 

Stock transfers (1)

 

 

293,023

 

 

 

(13,023

)

 

 

 

 

 

(279,999

)

 

 

 

 

 

 

 

 

(1

)

 

 

 

Restricted stock issuance

 

 

15,278

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

15,278

 

Restricted stock repurchased

 

 

(2,025

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(2,025

)

Restricted stock forfeited

 

 

(11,497

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(11,497

)

Shares issued at December 31, 2014

 

 

364,896

 

 

 

344,859

 

 

 

209,882

 

 

 

 

 

 

504,276

 

 

 

1

 

 

 

2

 

 

 

1,423,916

 

Restricted stock issuance

 

 

1,209

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,209

 

Restricted stock repurchased

 

 

(5,725

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(5,725

)

Restricted stock forfeited

 

 

(15,091

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(15,091

)

Shares issued at December 31, 2015

 

 

345,289

 

 

 

344,859

 

 

 

209,882

 

 

 

 

 

 

504,276

 

 

 

1

 

 

 

2

 

 

 

1,404,309

 

 

(1)

In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) on January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.

 

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 2015, 2014 and 2013. At December 31, 2015, 2014, and 2013, there were 395, 625, and 585 employees, respectively, participating in the plan. Our contribution expense was $2,363, $3,592, and $3,621 for the years ended December 31, 2015, 2014 and 2013, respectively.

 

 

Note 14: Commitments and contingencies

Letters of Credit. Standby letters of credit (“Letters”) available under our credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had an outstanding amount of $828 and $920 as of December 31, 2015 and 2014, respectively. 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, 2015, 2014, or 2013.

Commitments. We have four long-term contracts with four different suppliers to purchase CO2. Pricing under one of these contracts is fixed. Pricing under two of the contracts varies with the price of oil. The fourth contract provides fixed pricing through 2018 but becomes dependent upon the price of oil in subsequent years. 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, 2015, we were purchasing approximately 49 MMcf/d of CO2, from all sources combined and we expect to purchase approximately 38 MMcf/d in 2016. Purchases under these contracts were $3,000, $4,890, and $3,849 during 2015, 2014, and 2013, respectively.

106


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 contracts are as follows:

 

2016

 

$

2,193

 

2017

 

 

1,290

 

2018

 

 

1,289

 

2019

 

 

1,290

 

2020

 

 

1,289

 

2021 and thereafter

 

 

3,066

 

 

 

$

10,417

 

 

 

In addition to our CO2 commitments, we have other commitments totaling $4,101, substantially all of which are due in one year. These commitments are primarily related to contracts on our drilling rigs.

 

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, 2015, 2014, and 2013 was $8,753, $11,088, and $8,967, 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 September 2015, we entered into an interim financing agreement with U.S. Bank for an additional CO2 recycle compressor for our EOR facilities. If we do not enter into a lease once the compressor has been manufactured, which we expect to be completed around April 2016, we will owe U.S. Bank most of the cost incurred by U.S. Bank for the compressor.

As of December 31, 2015, total remaining payments associated with our operating leases were:

 

2016

 

$

1,095

 

2017

 

 

1,095

 

2018

 

 

1,093

 

2019

 

 

1,088

 

2020

 

 

1,055

 

2021 and thereafter

 

 

1,018

 

 

 

$

6,444

 

 

Other Contingencies. We have entered into change of control severance agreements under which our officers are entitled to receive certain severance benefits. The severance payment will be paid in equal monthly installments over a period of months as calculated under the terms of the agreement and will be equal to a set multiplier times the sum of (A) the officer’s base salary as in effect immediately prior to their termination date, plus (B) the officer’s bonus for the full year in which the termination date occurred. As of December 31, 2015, the maximum amount payable under these agreements in the event of a change in control that results in our officers being terminated is $14,532.

Litigation and Claims

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 Farms Case”) 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. 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. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification and responsive briefs were filed in the fourth quarter of 2015, and we expect a hearing on class certification to be held in the second quarter of 2016.  We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the

107


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among 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 outcome of the matter. Plaintiffs in the Naylor Farms Case 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. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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 allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams 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 this time, a class has not been certified and discovery has not yet commenced.  We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among 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 outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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 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. We have joined in Motions to Dismiss filed by the defendants, which is still pending.  In a case with similar claims, also pending in the United States District Court for the Northern District of Oklahoma, the court determined the Bureau of Indian Affairs violated the National Environmental Protection act by not conducting environmental assessments before granting leases and permits on Osage tribal lands in Osage County, Oklahoma, and therefore found both the lease and the two related drilling permits void ab initio.  At this time, discovery has commenced and is ongoing.  A class has not been certified. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.  We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

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 Cleveland, Lincoln, McClain, Okfuskee, Oklahoma, Pontotoc, Pottawatomie and Seminole Counties, 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 our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief.  The plaintiffs have not asked for damages related to actual property damage which may have occurred.  We have 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.  We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the West Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented, and uncertainties with respect to, among 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 outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action 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. 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.

108


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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:  

 

 

 

2015

 

 

2014

 

 

2013

 

Property acquisition costs

 

 

 

 

 

 

 

 

 

 

 

 

Proved properties

 

$

1,192

 

 

$

3,496

 

 

$

69,962

 

Unproved properties

 

 

24,735

 

 

 

84,938

 

 

 

145,853

 

Total acquisition costs

 

 

25,927

 

 

 

88,434

 

 

 

215,815

 

Development costs

 

 

150,261

 

 

 

561,578

 

 

 

376,394

 

Exploration costs (1)

 

 

33,091

 

 

 

90,146

 

 

 

77,507

 

Total

 

$

209,279

 

 

$

740,158

 

 

$

669,716

 

 

(1)

Includes $515, $152, and $37,344 of EOR costs in 2015, 2014, and 2013, respectively.

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

 

 

2015

 

 

2014

 

 

2013

 

DD&A

 

$

204,692

 

 

$

231,761

 

 

$

179,734

 

DD&A per BOE:

 

$

20.07

 

 

$

21.10

 

 

$

18.45

 

 

Oil and natural gas properties not subject to amortization consist of the cost of unevaluated properties and seismic costs associated with specific unevaluated properties. Of the $66,905 of unproved property costs at 2015 being excluded from the amortization base, $24,587, $37,846, and $4,472 were incurred in 2015, 2014, and 2013, respectively. We expect to complete our evaluation for the majority of these costs relating to non-EOR properties 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.  

109


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, 2015 are as follows:

 

 

 

Oil

(MBbls)

 

 

Natural gas (MMcf)

 

 

Natural gas liquids

(MBbls)

 

 

Total

(MBoe)

 

Proved developed and undeveloped reserves

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of January 1, 2013

 

 

92,047

 

 

 

257,115

 

 

 

11,195

 

 

 

146,095

 

Purchase of minerals in place

 

 

3,283

 

 

 

3,618

 

 

 

1,059

 

 

 

4,945

 

Sales of minerals in place

 

 

(5,174

)

 

 

(9,708

)

 

 

(324

)

 

 

(7,116

)

Extensions and discoveries

 

 

11,556

 

 

 

62,412

 

 

 

3,127

 

 

 

25,085

 

Revisions (1)

 

 

(7,772

)

 

 

9,735

 

 

 

1,479

 

 

 

(4,671

)

Improved recoveries

 

 

3,879

 

 

 

 

 

 

 

 

 

3,879

 

Production

 

 

(5,006

)

 

 

(20,250

)

 

 

(1,361

)

 

 

(9,742

)

Balance at December 31, 2013

 

 

92,813

 

 

 

302,922

 

 

 

15,175

 

 

 

158,475

 

Purchase of minerals in place

 

 

276

 

 

 

859

 

 

 

55

 

 

 

474

 

Sales of minerals in place

 

 

(8,539

)

 

 

(79,579

)

 

 

(1,959

)

 

 

(23,761

)

Extensions and discoveries

 

 

12,776

 

 

 

56,159

 

 

 

3,405

 

 

 

25,541

 

Revisions (1)

 

 

(3,356

)

 

 

(11,957

)

 

 

1,741

 

 

 

(3,608

)

Improved recoveries

 

 

13,254

 

 

 

 

 

 

 

 

 

13,254

 

Production

 

 

(5,977

)

 

 

(20,648

)

 

 

(1,564

)

 

 

(10,982

)

Balance at December 31, 2014

 

 

101,247

 

 

 

247,756

 

 

 

16,853

 

 

 

159,393

 

Purchase of minerals in place

 

 

38

 

 

 

1,120

 

 

 

46

 

 

 

271

 

Sales of minerals in place

 

 

(2,225

)

 

 

(3,656

)

 

 

(117

)

 

 

(2,951

)

Extensions and discoveries

 

 

3,651

 

 

 

13,759

 

 

 

1,096

 

 

 

7,040

 

Revisions (1)

 

 

(19,840

)

 

 

(61,973

)

 

 

(4,257

)

 

 

(34,426

)

Improved recoveries (2)

 

 

36,414

 

 

 

 

 

 

 

 

 

36,414

 

Production

 

 

(5,519

)

 

 

(18,788

)

 

 

(1,550

)

 

 

(10,200

)

Balance at December 31, 2015

 

 

113,766

 

 

 

178,218

 

 

 

12,071

 

 

 

155,541

 

Proved developed reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2013

 

 

54,737

 

 

 

185,826

 

 

 

9,218

 

 

 

94,926

 

December 31, 2013

 

 

56,360

 

 

 

196,920

 

 

 

11,484

 

 

 

100,664

 

December 31, 2014

 

 

54,862

 

 

 

158,265

 

 

 

11,787

 

 

 

93,027

 

December 31, 2015

 

 

40,300

 

 

 

132,323

 

 

 

9,169

 

 

 

71,524

 

Proved undeveloped reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

January 1, 2013

 

 

37,310

 

 

 

71,289

 

 

 

1,977

 

 

 

51,169

 

December 31, 2013

 

 

36,453

 

 

 

106,002

 

 

 

3,691

 

 

 

57,811

 

December 31, 2014

 

 

46,385

 

 

 

89,491

 

 

 

5,066

 

 

 

66,366

 

December 31, 2015

 

 

73,466

 

 

 

45,895

 

 

 

2,902

 

 

 

84,017

 

 

(1)

The downward revision in our reserves during 2015 was primarily due to the decline in SEC pricing which resulted in future extraction of certain reserves being uneconomic. The downward revision in our reserves during 2014 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame mandated by the SEC and a decline in the estimated sales margin on natural gas. The downward revision in our reserves during 2013 was primarily due to removing proved undeveloped reserves that are not expected to be developed within the five-year time frame and to negative technical revisions. The 2013 downward revisions were partially offset by positive revisions due to improved pricing of oil and natural gas.

(2)

Improved recoveries in 2015 resulted from the addition of reserves from remaining future phases of CO2 injection at our North Burbank EOR unit.

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

110


Chaparral Energy, Inc. and subsidiaries

 

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

 

 

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 costs and sales prices will probably differ from those required to be used in these calculations;

 

·

actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

 

·

a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

 

·

future net revenues may be subject to different rates of income taxation.

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:

 

 

 

For the year ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Future cash flows

 

$

6,327,363

 

 

$

11,275,090

 

 

$

10,660,532

 

Future production costs

 

 

(2,670,692

)

 

 

(3,605,107

)

 

 

(3,841,723

)

Future development and abandonment costs

 

 

(1,536,063

)

 

 

(1,726,955

)

 

 

(1,506,585

)

Future income tax provisions

 

 

(89,999

)

 

 

(1,487,121

)

 

 

(1,328,925

)

Net future cash flows

 

 

2,030,609

 

 

 

4,455,907

 

 

 

3,983,299

 

Less effect of 10% discount factor

 

 

(1,345,920

)

 

 

(2,561,207

)

 

 

(2,239,527

)

Standardized measure of discounted future net cash flows

 

$

684,689

 

 

$

1,894,700

 

 

$

1,743,772

 

 

111


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:

 

 

 

For the year ended December 31,

 

 

 

2015

 

 

2014

 

 

2013

 

Beginning of year

 

$

1,894,700

 

 

$

1,743,772

 

 

$

1,523,681

 

Sale of oil and natural gas produced, net of production costs

 

 

(196,319

)

 

 

(502,928

)

 

 

(418,224

)

Net changes in prices and production costs (1)

 

 

(2,230,601

)

 

 

116,977

 

 

 

172,975

 

Extensions and discoveries

 

 

101,384

 

 

 

286,500

 

 

 

514,743

 

Improved recoveries

 

 

524,436

 

 

 

148,673

 

 

 

79,589

 

Changes in future development costs

 

 

204,199

 

 

 

(91,027

)

 

 

(236,121

)

Development costs incurred during the period that reduced future

   development costs

 

 

80,103

 

 

 

316,490

 

 

 

110,354

 

Revisions of previous quantity estimates (1)

 

 

(495,794

)

 

 

(40,481

)

 

 

(95,855

)

Purchases and sales of reserves in place, net

 

 

(47,079

)

 

 

(278,825

)

 

 

(20,021

)

Accretion of discount

 

 

237,134

 

 

 

223,324

 

 

 

152,830

 

Net change in income taxes (1)

 

 

605,766

 

 

 

(46,584

)

 

 

(60,981

)

Changes in production rates and other

 

 

6,760

 

 

 

18,809

 

 

 

20,802

 

End of year

 

$

684,689

 

 

$

1,894,700

 

 

$

1,743,772

 

 

(1)

Amounts in 2015 are primarily the result of the decrease in SEC pricing, which resulted in a loss of reserves as extraction has become uneconomic, lower margins on existing reserves and a decrease in taxes as a result of the lower margins.

 

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.

 

 

 

2015

 

 

2014

 

 

2013

 

Oil (per Bbl)

 

$

50.28

 

 

$

94.99

 

 

$

96.78

 

Natural gas (per Mcf)

 

$

2.58

 

 

$

4.35

 

 

$

3.67

 

Natural gas liquids (per Bbl)

 

$

15.84

 

 

$

36.10

 

 

$

32.53

 

 

 

 

112


 

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, 2015, 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:

 

·

pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions relating to and the dispositions of our assets;

 

·

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

 

·

provide reasonable assurance regarding prevention or the timely detection of unauthorized acquisition, or the use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. 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, 2015.

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, 2015 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.  

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ITEM 9B. OTHER INFORMATION

None.

 

114


 

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Executive Officers and Directors

The following table provides information regarding our executive officers and directors. Our board of directors currently consists of five members: Mark A. Fischer, K. Earl Reynolds, Charles A. Fischer, Jr., Christopher Behrens, and Will Jaudes. Mark A. Fischer and K. Earl Reynolds are full-time employees.

 

Name

 

Age

 

 

Position

Mark A. Fischer

 

 

66

 

 

Chairman, Chief Executive Officer and Co-Founder

K. Earl Reynolds

 

 

55

 

 

President and Chief Operating Officer

Joseph O. Evans

 

 

61

 

 

Chief Financial Officer and Executive Vice President

James M. Miller

 

 

53

 

 

Sr. Vice President—Enhanced Oil Recovery Business Unit

Charles A. Fischer, Jr.

 

 

67

 

 

Director

Christopher Behrens

 

 

54

 

 

Director

Will Jaudes

 

 

37

 

 

Director

 

Mark A. Fischer, Chairman and Chief Executive Officer, and Co-Founder, co-founded Chaparral in 1988 and has served as its Chief Executive Officer and Chairman of the Board since its inception. Mr. Fischer began his career with Exxon Company USA in 1972 in the Permian Basin of West Texas where he held various positions as production engineer, reservoir engineer, field superintendent and finally supervising production engineer. From 1977 until 1980, Mr. Fischer served as the drilling and production manager for the West Texas and then Mid-Continent Division of TXO Production Corp. Prior to founding Chaparral, he served as division operations manager for Slawson Exploration Company from 1980 until 1988, focusing on the Mid-Continent and Panhandle Divisions. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute (API). Mr. Fischer served as a director of the API from 1984-1986. He currently sits on the Board of Directors of Pointe Vista Development, LLC and several non-profit organizations including the Boy Scouts of America, the Texas A&M Look College of Engineering Advisory Council and Texas A&M Association of Former Students. Mr. Fischer graduated from Texas A&M University in 1972 with an honors degree in aerospace engineering. He was named as a Distinguished Alumni in Aerospace Engineering and a recipient of the College of Engineering Outstanding Alumni Award in 2014. Mark A. Fischer and Charles A. Fischer, Jr. are brothers. Mr. Fischer is the board designee of the holders of our class B common stock.

K. Earl Reynolds, President and Chief Operating Officer, joined Chaparral in February 2011 as an Executive Vice President and the Chief Operating Officer before being named President in 2014. From 2000 to 2010, Mr. Reynolds led the international business unit and was actively involved in strategic planning for Devon Energy, most recently serving as Senior Vice President of Strategic Development, where he was responsible for strategic planning, budgeting, coordination of acquisitions and divestitures, and oversight of the company’s assessment of oil and gas reserves. Prior to Devon Energy, Mr. Reynolds’ career included several key leadership roles in domestic and international operations with companies such as Burlington Resources and Mobil Oil. Mr. Reynolds has served on the board of directors for several non-profit organizations in Houston and Oklahoma City. He currently sits on the Board of Directors for the Oklahoma Independent Petroleum Association and serves as the Chairman of its Regulatory Committee. He also sits on the Board of Directors for the Oklahoma City YMCA. Mr. Reynolds holds a Master of Science degree in Petroleum Engineering from the University of Houston and a Bachelor of Science degree in Petroleum Engineering from Mississippi State University. In 2013, he was named as a Distinguished Fellow of the Mississippi State University Bagley College of Engineering. Mr. Reynolds is the second board designee of the holders of our class B common stock.

Joseph O. Evans, Chief Financial Officer and Executive Vice President, joined Chaparral in July of 2005 as Chief Financial Officer and Executive Vice President. From 1998 to 2005, Mr. Evans was a consultant and practiced public accounting with the firm of Evans Gaither & Assoc. From 1997 to 1998, he served as Senior Vice President and Financial Advisor, Energy Lending, for First National Bank of Commerce in New Orleans. From 1976 until 1997, Mr. Evans worked in the Oklahoma practice of Deloitte & Touche where he became an Audit Partner. While at Deloitte he was a member of the energy industry group and was responsible for services on numerous Commission filings for clients. Mr. Evans has instructed numerous continuing professional education courses focused on compliance with the Sarbanes Oxley Act. He is a Certified Public Accountant and an Accredited Petroleum Accountant. Mr. Evans is a graduate of the University of Central Oklahoma with a Bachelor of Science degree in Accounting.

James M. Miller, Senior Vice President—Enhanced Oil Recovery Business Unit, joined Chaparral in 1996 as Operations Engineer. Since joining Chaparral, Mr. Miller has been promoted to positions of increasing responsibility and currently serves as the senior vice president of the company’s Enhanced Oil Recovery Business Unit. During this time, he has gained particular expertise in the area of operating secondary and tertiary recovery units. Prior to joining Chaparral, Mr. Miller worked for KEPCO Operating Inc.

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as a petroleum engineer. From 1987 to 1995, he was employed by Robert A. Mason Production Co., as a petroleum engineer, and later as Vice President of Production. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Miller attended the University of Oklahoma and received a Bachelor of Science degree in Petroleum Engineering.

Charles A. Fischer, Jr., Director and Co-Founder, co-founded Chaparral in 1988 and has served as a director since its inception. Mr. Fischer joined Chaparral full-time in 2000 and served as the Chief Financial Officer, Senior Vice President and Chief Administrative Officer before retiring in 2007. Mr. Fischer serves as a managing partner of Altoma Energy GP and as President of C.A. Fischer Lumber Co. Ltd. which he formed in 1978 in western Canada. He began his career with Renewable Resources in 1974 as a senior scientist on the Polar Gas Pipeline Project investigating the feasibility of bringing natural gas from the high Arctic to south central Canada. Mr. Fischer has served as director and President of the Canadian Western Retail Lumberman’s Association and received the 2001 Industry Achievement Award. He graduated from Texas A&M University with a Bachelor of Science degree in Biology and from the University of Wisconsin with a Master of Science degree in Ecology. Mr. Fischer is a brother to Mark Fischer. Mr. Fischer is the board designee of the holders of our class C common stock.

Christopher Behrens, Director, joined Chaparral’s board of directors in April 2010 as a nominee of CCMP Capital Advisors, LLC. Mr. Behrens is a Managing Director of CCMP’s New York office and a member of the firm’s Investment Committee, where he focuses on making investments in the energy, industrial and distribution sectors. Prior to joining CCMP in 1994, he was a Vice President in the Merchant Banking group of The Chase Manhattan Corporation. Mr. Behrens also serves on the Board of Directors of Newark E&P Holdings, LLC and Noble Environmental Power, LLC. Mr. Behrens holds a Bachelors of Arts degree from the University of California, Berkeley and a Master’s of Arts degree from Columbia University. Mr. Behrens is one of the two board designees of the holders of our class E common stock.

Will Jaudes, Director, joined Chaparral’s board of directors in 2015 as a nominee of CCMP Capital Advisors, LLC. Mr. Jaudes is a principal at CCMP's Houston office where he focuses on energy and industrial sector investments. Prior to joining CCMP, Mr. Jaudes served as a principal at HM Capital Partners, where he worked with investments in upstream and midstream energy companies. Before that time, he worked in the Global Mergers & Acquisitions Group of Lehman Brothers. Mr. Jaudes holds a Bachelor of Science degree in finance from Wake Forest University.

As stated in the Form 8-K filed on January 22, 2016, effective January 19, 2016, David R. Winchester, Senior Vice President – Drilling Operations, and Jeffery D. Dahlberg, Senior Vice President – E&P Business Unit, are no longer employed with us.

Board Committees

On April 12, 2010, our board of directors established a compensation committee and an audit committee, effective upon the closing of the sale of our common stock to CCMP. All members of the board of directors were appointed to the compensation and audit committees, and the board of directors adopted charters for both committees on November 10, 2010. Christopher Behrens is Chairman of the audit and compensation committees. Mr. Behrens also serves as the audit committee financial expert.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics that is applicable to all employees, officers and members of our board of directors. The Code of Business Conduct and Ethics is available on our website at chaparralenergy.com/about-us.

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ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

Overview & Oversight of Compensation Program

Our compensation programs include programs that are designed specifically for our most senior executive officers (“Senior Executives”), which includes our Principal Executive Officer (“PEO”) and the other executive officers named in the Summary Compensation Table (the “Named Executive Officers” or “NEOs”). Currently, our PEO and board of directors oversee the compensation programs for our Senior Executives.

Overview of Compensation Philosophy and Program

In order to recruit and retain the most qualified and competent individuals as Senior Executives, we strive to maintain a compensation program that is competitive in the labor market. The following compensation objectives are considered in setting the compensation programs for our Senior Executives:

 

·

drive and reward performance which supports our core values;

 

·

align the interests of Senior Executives with those of stockholders;

 

·

design competitive total compensation and rewards programs to enhance our ability to attract and retain knowledgeable and experienced Senior Executives; and

 

·

set compensation and incentive levels that reflect mid-range market practices.

Compensation Targets

From time to time, we review compensation data from a variety of different sources, including from the Oil & Gas E&P Survey prepared by Effective Compensation, Incorporated (the “Survey Data”) to ensure that our Senior Executive base salary compensation program generally aligns with the median of the Survey Data. The Survey Data is a compilation of compensation and other data from the prior year based upon over 100 exploration and production firms that participated in the survey. We have previously utilized guidance and executive compensation data from the Southwest Energy Group and Meridian Compensation Partners.

In determining base salaries for our Senior Executives, in addition to the Survey Data referenced above, our board of directors also considers the current level of the Senior Executive’s compensation, both internally and relative to other Company officers and current industry and economic factors. The process can best be described as (i) looking within our Company at the current salary structure among the executive group to ensure fairness and consistency, (ii) evaluating the Company’s performance to ensure that compensation is, in large part, performance-based, (iii) looking at general industry conditions, and (iv) looking at peer group companies to determine if the range of compensation paid to our Senior Executives is within the “fairway” of the compensation paid to executives in similarly situated companies.

Compensation Elements and Rationale for Pay Mix Decisions

We believe that a competitive compensation program will enhance our ability to attract and retain Senior Executives. To reward both short-term and long-term performance in our compensation program and in furtherance of our compensation objectives noted above, our executive compensation philosophy includes the following four principles:

(i) Compensation levels should be competitive

We review the Survey Data to ensure that the base salary compensation is aligned with median levels.

(ii) Compensation should be related to performance

We believe that a significant portion of a Senior Executive’s compensation should be tied to individual performance and to our overall performance measured primarily by growth in reserves, production and earnings.

(iii) Variable compensation should represent a portion of a Senior Executive’s total compensation

We intend for a portion of compensation paid to Senior Executives to be variable in order to: 1) allow flexibility when our performance and/or industry conditions are not optimum; 2) maintain the ability to reward Senior Executives for our overall

117


 

growth; and 3) retain Senior Executives when industry conditions necessitate. Senior Executives should have the incentive of increasing our profitability and value in order to earn a portion of their compensation package.

(iv) Compensation should balance short-term and long-term performance

We seek to structure a balance between achieving strong short-term annual results and ensuring our long-term viability and success. To reinforce the importance of balancing these perspectives, Senior Executives are regularly provided compensation based on both the accomplishment of short-term objectives and incentives for achieving long-term objectives. While our annual bonus plans are structured to reward the accomplishment of short-term objectives, in 2004, we began a long-term compensation plan for our executive employees and other key employees. This plan is to deliver long-term incentive awards aligned with the interests of stockholders while simultaneously serving as a retention tool.

Review of Senior Executive Performance

The PEO reviews, on an annual basis, each compensation element of a Senior Executive. In each case, the PEO takes into account the scope of responsibilities and experience, succession potential, strengths and weaknesses, and contribution and performance over the past year and balances these against competitive salary levels. The PEO works daily with the Senior Executives, which allows him to form his assessment of each individual’s performance. The PEO’s performance is assessed by the board of directors, taking into account the scope of responsibilities and experience, strengths and weaknesses, and contributions and performance over the past year balanced against competitive salary levels.

Components of the Executive Compensation Program

We believe the total compensation and benefits program for Senior Executives should consist of the following:

 

·

base salaries;

 

·

annual bonus plans;

 

·

long-term retention and incentive compensation; and

 

·

health and welfare benefits and retirement.

Base Salaries

For 2015, Senior Executive base salaries were modestly increased from 2014 (on average 5%) due to general industry conditions at the time. We usually adjust base salaries for Senior Executives annually based on performance. The PEO did not rely solely on predetermined formulas or a limited set of criteria when evaluating the base salaries of the Senior Executives for 2015. This is in line with our philosophy that Senior Executive compensation should be paid at approximately the competitive median levels based on market data, and taking current industry and economic factors into consideration. The salaries paid to the PEO and the NEOs during fiscal year 2015 are shown in the Summary Compensation Table in this annual report.

Annual Bonus Plan

In 2011, we created a non-binding, discretionary incentive program called the Annual Incentive Measure Bonus Program (the “AIM” program) which pays cash bonus awards to eligible employees when the Company achieves certain performance measures on a Company-wide basis. Amounts payable under the AIM program are tied to the approved Company budget and to certain individual, departmental, and business unit measures, including, but not limited to, employees who reach individual performance goals and contribute positively to their respective business units and the Company’s goals and objectives.

The targets for individual awards are expressed as a percentage of an employee’s eligible earnings for the plan year and are based on pay grade and level of responsibility. When the board of directors determines industry and economic factors permit granting AIM awards, the first 50% of the computation of an employee’s AIM award is determined based solely on the Company’s performance on nine Company-wide performance measures: EBITDA—25%; Production Volume (Boe/d)—20%; Reserve Replacement—10%; Drilling and Completion Capital Effectiveness—15%; EOR Capital—5%; EOR Production Uplift—5%; Lease Operating Expenses ($/Boe)—10%; Safety—5%; and Environment—5%. When the board of directors approves granting AIM awards, the remaining 50% of the computation of an employee’s AIM award is discretionary and is based on the performance of the department or business unit in which the employee works and his or her individual performance and contributions, as reflected by his or her performance review.

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2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) in April 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. If any award is exercised, paid, forfeited, terminated or canceled without the delivery of shares, then the shares covered by such award will be available again for grant under the 2010 Plan. All of our or our affiliates’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.

Purpose

The 2010 Plan is intended to aid us in recruiting and retaining employees, officers, directors, and consultants capable of assuring our future success. We expect that the awards of stock-based compensation under the 2010 Plan and opportunities for stock ownership in the Company will provide incentives to participants to exert their best efforts for our success and also align their interests with those of our stockholders.

Administration

The 2010 Plan is administered by our Compensation Committee. Subject to the terms of the 2010 Plan, the Compensation Committee has the full power and authority to, among other things: (i) designate participants in the 2010 Plan; (ii) determine the type or types of awards to be granted to a participant; (iii) determine the number of shares to be covered by, or with respect to which payments, rights, or other matters are to be calculated in connection with, awards; (iv) determine the terms and conditions of any award; (v) determine whether, to what extent, and under what circumstances awards may be settled or exercised in cash, shares, other securities, other awards or other property, or canceled, forfeited, or suspended and the method or methods by which awards may be settled, exercised, canceled, forfeited, or suspended; (vi) interpret and administer the 2010 Plan or any award agreement issued under the 2010 Plan; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the 2010 Plan; (viii) determine the fair market value of any shares issued under the 2010 Plan; (ix) prescribe the form of each award agreement, which need not be identical for each participant; and (x) make any other determination and take any other action that the Compensation Committee deems necessary or desirable for the administration of the 2010 Plan.

Types of Awards

The 2010 Plan authorizes the following types of awards:

 

·

Stock Options. The grant of either non-qualified or incentive stock options (“ISOs”) to purchase shares of our class A common stock are permitted under the 2010 Plan. ISOs are intended to qualify for favorable tax treatment under the Internal Revenue Code to participants in the 2010 Plan. The stock options will provide for the right to purchase shares of our class A common stock at a specified price and will become exercisable after the grant date under the terms established by the Compensation Committee. In general, the per share option exercise price may not be less than 100% of the fair market value of a share of class A common stock on the grant date. No person owning more than 10% of the total combined voting power of the Company may be granted ISOs unless (i) the option exercise price is at least 110% of the fair market value of a share of class A common stock on the grant date and (ii) the term during which such ISO may be exercised does not exceed five years from the date of grant.

 

·

Restricted Stock. Awards of restricted stock are permitted under the 2010 Plan, subject to any restrictions the Compensation Committee determines to impose, such as satisfaction of performance measures for a performance period, or restrictions on the right to vote or receive dividends.

 

·

Performance Awards. Performance awards, denominated as a cash amount (e.g., $100 per award unit) at the time of grant are permitted under the 2010 Plan. Performance awards confer on the participant the right to receive payment of such award, in whole or in part, upon the achievement of certain performance objectives during such performance periods as established by the Compensation Committee.

 

·

Bonus Shares. Awards of class A common stock without restrictions are permitted under the 2010 Plan, but such grants may be subject to any terms and conditions the Compensation Committee may determine.

 

·

Phantom Shares. Awards of phantom shares are permitted under the 2010 Plan, upon such terms and conditions as determined by the Compensation Committee. Each phantom share award shall constitute an agreement by us to issue or transfer a specified number of shares or pay an amount of cash equal to a specified number of shares, or a combination thereof to the participant in the future, subject to the fulfillment of performance objectives, if any, during the restricted period as the Compensation Committee may specify at the date of grant.

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·

Cash Awards. Grants of cash awards, subject to the terms and conditions established by the Compensation Committee, are permitted under the 2010 Plan. If granted, a cash award shall be granted (simultaneously or subsequently) in tandem with another award and shall entitle a participant to receive a specified amount of cash from us upon such other award becoming taxable to the participant, which cash amount may be based on a formula relating to the anticipated taxable income associated with such other award and the payment of the cash award. 

 

·

Other Stock-Based Awards. Grants of other types of awards that are denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, shares of our class A common stock, subject to the terms and conditions established by the Compensation Committee, are permitted under the 2010 Plan.

Terms of Time Vested Restricted Stock Awards

Time Vested restricted stock awards generally vest with respect to twenty percent (20%) of the shares subject to the award on each of the first, second, third, fourth and fifth anniversaries of the award date, subject to the NEO remaining employed by us as of those dates.

Termination by Company Without Cause or by NEO for Good Reason. If the NEO is terminated by the Company without cause or by the NEO for good reason, then the vesting of the shares scheduled to vest during the period beginning on the date the NEO’s employment was terminated (the “Separation Date”) and ending on the 12-month anniversary of the Separation Date shall accelerate as of the Separation Date. Any shares not vested on the Separation Date will be forfeited as of the Separation Date. “Cause” and “good reason” shall have the same meanings as those terms are defined in any employment agreement then in effect between the NEO and us. See “—Potential Payments Upon Termination or Change in Control—Employment Agreements with Our NEOs” for the definitions of “cause” and “good reason.”

Accelerated Vesting Upon Certain Transactions. In the event of a transaction whereby CCMP receives cash in exchange for the sale, transfer or other disposition of its common stock pursuant to (i) a sale of the Company or (ii) an offering of its common stock to the public pursuant to a registration statement filed under the Securities Act of 1933, or any sale of its common stock thereafter (a “Transaction”), the shares held by each NEO who remains employed by us as of the date of such Transaction shall vest with respect to the fraction obtained by dividing (x) the number of shares of common stock sold pursuant to the Transaction, by (y) the 504,276 shares of class E common stock issued to CCMP on April 12, 2010 (the “Vesting Fraction”). Any shares of common stock sold pursuant to an “Excepted Transfer” are excluded from both the numerator and the denominator when determining the Vesting Fraction. “Excepted Transfer” means the transfer by CCMP and its permitted transferees of up to 20% of the common stock owned by them on or immediately following April 12, 2010. All other shares will remain subject to the normal vesting schedule.

Performance Vested Restricted Stock Awards

Performance Vested restricted stock awards vest in the event of a Transaction (i) whereby CCMP’s “net proceeds” from a Transaction yields certain target returns on investment, and (ii) the NEO remains employed by us as of the date of such Transaction. “Net proceeds” means the actual cash proceeds received by CCMP in a Transaction, but excludes the aggregate amount of out-of-pocket expenses incurred by CCMP in connection with such Transaction.

The table below sets forth the initial return-on-investment targets that triggered vesting of the Performance Vested restricted stock awards and the formula for calculating the number of shares of Performance Vested restricted stock that vest upon CCMP’s receipt of net proceeds in a Transaction.

 

Return on Investment Target

 

Target Shares Vested

200% per share

 

20% of shares multiplied by the Vesting Fraction

250% per share

 

20% of shares multiplied by the Vesting Fraction

300% per share

 

20% of shares multiplied by the Vesting Fraction

350% per share

 

20% of shares multiplied by the Vesting Fraction

400% per share

 

20% of shares multiplied by the Vesting Fraction

 

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

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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:

 

Return on Investment Target

 

Target Shares Vested

175% per share

 

33% of shares multiplied by the Vesting Fraction

200% per share

 

33% of shares multiplied by the Vesting Fraction

250% per share

 

34% of shares multiplied by the Vesting Fraction

 

Our Purchase Option

All Time Vested and Performance Vested restricted stock awards are subject to our right to purchase the shares that have vested under the terms of such awards, which purchase option lapses on the seventh anniversary of the grant date. If the NEO ceases his employment with us for any reason, we shall have the right to purchase the shares of restricted stock awarded to the NEO that have vested. If the NEO’s employment is terminated by us without cause, by the NEO for good reason, as a result of the NEO’s death or by the NEO without good reason, the purchase price for such shares shall be equal to the fair market value of such shares on the Separation Date. If the NEO’s employment is terminated by us for cause, the purchase price for such shares shall be $0.01 per share. In the event of the NEO’s material breach of the terms of any agreement with us that is in effect on or after the NEO’s Separation Date, other than a breach of noncompetition or nonsolicitation provisions, we may elect to purchase the shares for $0.01 per share.

Health and Welfare and Retirement Benefits

We offer a variety of health and welfare and retirement programs to all eligible employees. The Senior Executives are eligible for the same benefit programs on the same basis as the rest of our employees. The health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. Our health and welfare programs include medical under a preferred provider option or high deductible plan, as well as pharmacy, dental and vision plans, as well as life insurance, supplemental insurance policies.  Employees may also contribute pre-tax funds into flexible spending plans and health savings accounts.

We offer employees the opportunity to make investments in our 401(k) Profit Sharing Plan, which is intended to supplement the employee’s personal savings and social security. All employees, including Senior Executives, are generally eligible for the 401(k) plan. Senior Executives participate in the 401(k) plan on the same basis as other employees.

We adopted the 401(k) plan to enable employees to save for retirement through a tax-advantaged combination of employee and Company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. The 401(k) plan allows eligible employees to elect to contribute from 1% to 60% of their eligible compensation, up to the annual IRS dollar limit. Employees are automatically enrolled at 3% of their salary. Eligible compensation generally means all wages, salaries and fees for services paid by us. The Company matches at a rate of $1.00 per $1.00 employee contribution for the first 7% of the employee’s salary. Company contributions vest as follows:

 

Years of

Service for

Vesting

 

Percentage

 

1

 

 

33

%

2

 

 

33

%

3

 

 

34

%

 

However, regardless of the number of years of service, an employee is fully vested in his 401(k) plan if the employee retires at age 65 or later, attains age 62 and completes six years of service, or the employee’s employment is terminated due to death or total and permanent disability. The 401(k) plan provides for different investment options, for which the participant has sole discretion in determining how both the employer and employee contributions are invested. The 401(k) plan does not provide our employees the option to invest directly in our stock. The 401(k) plan offers in-service withdrawals in the form of loans, hardship distributions, after-tax account distributions and age 59.5 distributions.

Indemnification Agreements

We have indemnification agreements with Mark A. Fischer, K. Earl Reynolds, Joseph O. Evans, James M. Miller, Charles A. Fischer, Jr., Christopher Behrens and Will Jaudes. These indemnification agreements are intended to permit indemnification to the

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fullest extent now or hereafter permitted by the General Corporation Law of Delaware. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.

The indemnification agreements cover expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements will generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements will also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.

We are not obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:

 

·

us, except for:

 

·

claims regarding the indemnitee’s rights under the indemnification agreement;

 

·

claims to enforce a right to indemnification under any statute or law; and

 

·

counter-claims against us in a proceeding brought by us against the indemnitee; or

 

·

any other person, except for claims approved by our board of directors.

We also maintain director and officer liability insurance for the benefit of each of the above indemnitees. These policies include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnitees are named as an insured under such policies and provided with the same rights and benefits as are accorded to the most favorably insured of our directors and officers.

Employment Agreements

We have entered into employment agreements with each of our NEOs, under the terms of which each will serve in their respective officerial positions. The initial term of the employment agreements are three years, each with an automatic two-year renewal and automatic annual renewals thereafter. The employment agreements provide our NEOs the following compensation arrangements:

 

Name

 

Effective Date

 

Minimum

Base Salary

 

 

Target Annual

AIM Bonus

(as a % of Base)

 

 

Equity Grant

(Time Vested)(1)

 

 

Equity Grant

(Performance Vested)(1)

 

Mark A. Fischer

 

April 12, 2010

 

$

620,298

 

 

 

100

%

 

$

1,814,366

 

 

$

3,673,995

 

K. Earl Reynolds

 

January 1, 2014

 

 

500,400

 

 

 

90

%

 

 

1,578,616

 

 

 

1,935,177

 

Joseph O. Evans

 

April 12, 2010

 

 

345,030

 

 

 

80

%

 

 

725,883

 

 

 

1,469,598

 

James M. Miller

 

April 12, 2010

 

 

273,798

 

 

 

70

%

 

 

700,324

 

 

 

3,287,099

 

Jeffery D. Dahlberg

 

October 22, 2012

 

 

275,000

 

 

 

70

%

 

 

646,979

 

 

 

1,904,066

 

 

(1)

The value shown is the aggregate grant date fair value computed in accordance with FASB ASC Topic 718. These grants are one-time awards specified in the respective employment agreements.

Each NEO participates in our welfare benefit plans and fringe benefit, vacation and expense reimbursement policies. Each employment agreement provides for certain payments in the event of an NEO’s termination. The termination payments are discussed below under the heading “Potential Payments Upon Termination or Change of Control.” Each employment agreement contains certain restrictive covenants that generally prohibit our NEOs from (i) competing against us, (ii) disclosing information that is confidential to us and our subsidiaries and (iii) during the employment term and for each NEO, a period of months equal to the product of 12 times the Severance Multiple of that NEO, as described below, thereafter, from soliciting or hiring our employees and those of our subsidiaries or soliciting our customers.

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Compensation Committee Report

The compensation committee has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review and discussions, the board of directors recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

 

Mark A. Fischer

K. Earl Reynolds

Christopher Behrens

Will Jaudes

Charles A. Fischer

Compensation Committee Interlocks and Insider Participation

None of our Senior Executives have served as members of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors. All members of the board of directors serve on the compensation committee and Christopher Behrens serves as Chairman of the compensation committee.


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Summary Compensation Table

The following table below summarizes the total compensation paid to or earned by each of the NEOs for the fiscal year ended December 31, 2015, 2014, and 2013. We have also included the total compensation information for two individuals which were not employed by the Company on December 31, 2015, but would have been considered Named Executive Officer based on their total compensation during 2015 if they had been so employed.

 

Name and Principal Position

 

Year

 

 

Salary

($)

 

 

Bonus

($)(1)

 

 

Stock awards

($)(2)

 

 

All other

compensation

($)(3)

 

 

Total

($)

 

Mark A. Fischer

 

 

2015

 

 

$

830,305

 

 

$

896,729

 

 

$

 

 

$

59,485

 

 

$

1,786,519

 

Chairman and Chief Executive Officer

 

 

2014

 

 

 

783,307

 

 

 

501,316

 

 

 

2,020,884

 

 

 

86,464

 

 

 

3,391,971

 

 

 

 

2013

 

 

 

725,284

 

 

 

767,093

 

 

 

1,147,815

 

 

 

81,059

 

 

 

2,721,251

 

K. Earl Reynolds

 

 

2015

 

 

$

530,424

 

 

$

513,572

 

 

$

 

 

$

35,765

 

 

$

1,079,761

 

President and Chief Operating Officer

 

 

2014

 

 

 

500,400

 

 

 

288,230

 

 

 

2,449,171

 

 

 

39,211

 

 

 

3,277,012

 

 

 

 

2013

 

 

 

437,400

 

 

 

370,091

 

 

 

456,387

 

 

 

34,674

 

 

 

1,298,552

 

Joseph O. Evans

 

 

2015

 

 

$

448,914

 

 

$

323,218

 

 

$

 

 

$

38,835

 

 

$

810,967

 

Chief Financial Officer and Executive

 

 

2014

 

 

 

424,865

 

 

 

218,899

 

 

 

808,486

 

 

 

40,429

 

 

 

1,492,679

 

Vice President

 

 

2013

 

 

 

399,567

 

 

 

329,208

 

 

 

459,126

 

 

 

38,551

 

 

 

1,226,452

 

James M. Miller

 

 

2015

 

 

$

391,540

 

 

$

296,004

 

 

$

 

 

$

42,891

 

 

$

730,435

 

Senior Vice President—Enhanced Oil

 

 

2014

 

 

 

375,540

 

 

 

168,242

 

 

 

808,486

 

 

 

37,092

 

 

 

1,389,360

 

Recovery Business Unit

 

 

2013

 

 

 

351,540

 

 

 

267,961

 

 

 

459,126

 

 

 

36,461

 

 

 

1,115,088

 

Jeffery D. Dahlberg

 

 

2015

 

 

$

338,750

 

 

$

170,730

 

 

$

 

 

$

34,493

 

 

$

543,973

 

Senior Vice President—Exploration and

 

 

2014

 

 

 

322,750

 

 

 

144,592

 

 

 

808,486

 

 

 

37,840

 

 

 

1,313,668

 

Production Business Unit

 

 

2013

 

 

 

299,750

 

 

 

229,109

 

 

 

456,995

 

 

 

35,562

 

 

 

1,021,416

 

David J. Ketelsleger

 

 

2015

 

 

$

64,001

 

 

$

 

 

$

 

 

$

1,076,041

 

 

$

1,140,042

 

Former Senior Vice President and

 

 

2014

 

 

 

356,899

 

 

 

160,586

 

 

 

808,486

 

 

 

36,171

 

 

 

1,362,142

 

General Counsel

 

 

2013

 

 

 

335,000

 

 

 

255,681

 

 

 

456,995

 

 

 

33,785

 

 

 

1,081,461

 

Scott C. Wehner

 

 

2015

 

 

$

78,111

 

 

$

 

 

$

 

 

$

694,897

 

 

$

773,008

 

Former Senior Vice President—

 

 

2014

 

 

 

307,304

 

 

 

137,672

 

 

 

808,486

 

 

 

37,504

 

 

 

1,290,966

 

Enhanced Oil Recovery Business Unit

 

 

2013

 

 

 

290,304

 

 

 

213,671

 

 

 

459,285

 

 

 

36,829

 

 

 

1,000,089

 

 

(1)

Bonuses were performance-based cash incentives under our AIM program.

(2)

The values shown are the aggregate grant date fair value for initial awards or the incremental fair value as of the modification date for modified awards, computed in accordance with FASB ASC Topic 718. As discussed above in “2010 Equity Incentive Plan - Performance Vested Restricted Stock Awards,” awards were modified in 2014 and 2013 resulting in the recognition of incremental fair value in both years.

(3)

Perquisites and other compensation are limited in scope and in 2015 were primarily comprised of company 401K  matching; company automobile and airplane usage; and employer-paid medical benefits including accidental death and dismemberment, dental, life, medical and long-term and short-term disability coverage.  In 2015, Mr. Ketelsleger and Mr. Wehner received severance benefits, as described in the subsequent section “Payments Made Upon Termination Without Cause or by the NEO for Good Reason Not Following a Change in Control”, which are included in “All other compensation.”

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Grants of Plan-Based Awards in 2015

No equity-based awards were granted in 2015 for any NEO.

 

Outstanding Equity Awards at Fiscal Year-End 2015

The following table shows outstanding restricted stock awards as of December 31, 2015 for each NEO.

 

 

 

Time Vested Awards

 

 

Performance Vested Awards

 

Name

 

Number of

Shares of Stock

That Have Not

Vested

(#)(1)

 

 

Market Value of

Shares of Stock

That Have Not

Vested

($)(2)

 

 

Number of

Shares of Stock

That Have Not

Vested

(#)(3)

 

 

Market Value of

Shares of Stock

That Have Not

Vested

($)(4)

 

Mark A. Fischer

 

 

2,988

 

 

$

55,876

 

 

 

7,968

 

 

$

159

 

K. Earl Reynolds

 

 

2,519

 

 

 

47,105

 

 

 

4,774

 

 

 

95

 

Joseph O. Evans

 

 

1,196

 

 

 

22,365

 

 

 

3,187

 

 

 

64

 

James M. Miller

 

 

1,196

 

 

 

22,365

 

 

 

3,187

 

 

 

64

 

Jeffery D. Dahlberg

 

 

1,533

 

 

 

28,667

 

 

 

3,187

 

 

 

64

 

 

(1)

Initial grants of the Time Vested restricted stock awards vest over a five-year period.

(2)

The table assumes an estimated fair value per share of $18.70 as of December 31, 2015.

(3)

See “Executive Compensation—Compensation Discussion and Analysis—2010 Equity Incentive Plan—Performance Vested Restricted Stock Awards” for specific information regarding the potential vesting scenarios.

(4)

The table assumes an estimated fair value per share of $0.02 as of December 31, 2015.

2015 Stock Vested

The following table shows restricted stock awards that vested during the year ended December 31, 2015 for each NEO that participates in the 2010 Plan.

 

 

 

Time Vested Restricted Stock Awards

 

Name

 

Number of

Shares of Stock

That Have

Vested

(#)

 

 

Value Realized

on Vesting

($)

 

Mark A. Fischer

 

 

1,527

 

 

$

815,113

 

K. Earl Reynolds (1)

 

 

912

 

 

 

486,826

 

Joseph O. Evans (2)

 

 

611

 

 

 

326,152

 

James M. Miller (3)

 

 

611

 

 

 

326,152

 

Jeffery D. Dahlberg (4)

 

 

609

 

 

 

302,104

 

David J. Ketelsleger (5)

 

 

1,008

 

 

 

538,070

 

Scott C. Wehner (6)

 

 

1,008

 

 

 

538,070

 

 

(1)

In 2015, we withheld 415 vested shares to pay taxes of $221,527.

(2)

In 2015, we withheld 228 vested shares to pay taxes of $121,706.

(3)

In 2015, we withheld 200 vested shares to pay taxes of $106,760.

(4)

In 2015, we withheld 201 vested shares to pay taxes of $99,741.

(5)

In 2015, we withheld 464 vested shares to pay taxes of $247,683.

(6)

In 2015, we withheld 331 vested shares to pay taxes of $176,688.

Potential Payments Upon Termination or Change in Control

Employment Agreements with our NEOs

Our employment agreements with our NEOs obligate us to pay certain separation benefits to them in the event of voluntary termination, termination without cause, termination for good reason and termination in the event of disability or death. The term

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“disability” means the NEO’s incapacity due to physical or mental illness whereby the NEO is substantially unable to perform his duties under the employment agreement (with or without reasonable accommodation, as defined under the Americans With Disabilities Act) for a period of six consecutive months. The term “cause” means termination for one of the following reasons:

 

·

the NEO’s conviction of, or entry by the NEO of a guilty or no contest plea to a felony or crime involving moral turpitude;

 

·

the NEO’s willful commission of an act of fraud or dishonesty resulting in economic or financial injury to us or any affiliate;

 

·

the NEO’s willful failure to substantially perform or gross neglect of his duties, including, but not limited to, the failure to follow any lawful directive of our Chief Executive Officer, within the reasonable scope of the NEO’s duties;

 

·

the NEO’s performance of unapproved acts materially detrimental to us or any affiliate;

 

·

the NEO’s use of narcotics, alcohol, or illicit drugs in a manner that has or may reasonably be expected to have a detrimental effect on his performance of his duties as our employee or on the reputation of the Company or any affiliate;

 

·

the NEO’s commission of a material violation of any of our rules or policies which results in injury to us; or

 

·

the NEO’s material breach of the employment agreement.

In Mr. Fischer’s case, the term “cause” also includes:

 

·

the occurrence or existence of any event constituting “Cause,” with respect to Mr. Fischer under our Second Amended and Restated Certificate of Incorporation, as amended and restated on April 12, 2010; (the “Certificate of Incorporation”);

 

·

a material breach by us of Article 7 of the Certificate of Incorporation caused by specific acts or omissions of Mr. Fischer, provided that we fail to remedy such breach within 90 days after we have knowledge of the initial existence of such breach; or

 

·

a material breach by Fischer Investments, L.L.C. of that certain Stockholders’ Agreement dated April 12, 2010.

The term “good reason” means the occurrence, without the written consent of the NEO, of one of the events set forth below:

 

·

a material diminution in the NEO’s authority, duties or responsibilities, combined with a demotion in the NEO’s pay grade ranking;

 

·

the reduction by us of the NEO’s base salary by more than 10% (unless done so for all of our executive officers);

 

·

the requirement that the NEO be based at any office or location that is more than 50 miles from our principal executive offices, except for travel reasonably required in the performance of the NEO’s responsibilities; or

 

·

any other action or inaction that constitutes a material breach by us under the employment agreement.

The term “change in control” means:

 

·

the consummation of any transaction or series of related transactions involving the sale of our outstanding securities (but excluding a public offering of our capital stock) for securities or other consideration issued or paid or caused to be issued or paid by such other corporation or an affiliate thereof and which results in our shareholders (or their affiliates) immediately prior to such transaction not holding at least a majority of the voting power of the surviving or continuing entity following such transaction; or

 

·

the consummation by us (whether directly involving us or indirectly involving us through one or more intermediaries) of (x) a merger, consolidation, reorganization, or business combination or (y) a sale or other disposition of all or substantially all of our assets or (z) the acquisition of assets or stock of another entity, in each case, other than a transaction which results in our voting securities outstanding immediately before the transaction continuing to represent (either by remaining outstanding or by being converted into our voting securities or the person that, as a result of the transaction, controls, directly or indirectly, us or owns, directly or indirectly, all or substantially all of our assets or otherwise succeeds to our business), directly or indirectly, at least a majority of the combined voting power of the successor entity’s outstanding voting securities immediately after the transaction.

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Payments Made Upon Termination Without Cause or by the NEO for Good Reason Not Following a Change in Control

In the event an NEO’s employment is terminated without cause or by the NEO for good reason at any time that is not within two years after the occurrence of a change in control, we will be obligated:

 

·

to pay to the NEO an amount equal to the Severance Multiple, as specified in the NEO’s employment agreement, times the sum of (x) the NEO’s base salary in effect on the date of termination plus (y) the annual bonus granted to the NEO for the fiscal year immediately on or preceding the date of termination, payable in the form of a salary continuation for a period of months equal to the product of 12 times the Severance Multiple;

 

·

subject to certain limitations, to maintain for a period of 18 months following the date of termination, participation by the NEO (and his spouse and/or eligible dependents, as applicable) in our medical, hospitalization, and dental programs maintained for the benefit of our Senior Executives as in effect on the date of termination, at such level and terms and conditions (including, without limitation, contributions required by the NEO for such benefits) as in effect on the date of termination (the “Termination Welfare Benefits”);

 

·

to pay to the NEO any earned but unpaid base salary, annual bonus from prior years, and vacation pay in the form of a lump sum payment; and

 

·

to pay to the NEO any unreimbursed reasonable business expenses incurred by the NEO on our behalf in the form of a lump sum payment.

The following table quantifies amounts that would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination without cause or by the NEO for good reason not following a change in control took place on December 31, 2015, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2015.

 

Name

 

Base Salary

 

 

Annual Bonus

 

 

Severance Multiple

 

 

Benefits

 

 

Total

 

Mark A. Fischer

 

$

830,305

 

 

$

896,729

 

 

 

2.5

 

 

$

59,485

 

 

$

4,377,070

 

K. Earl Reynolds

 

 

530,424

 

 

 

513,572

 

 

 

2.0

 

 

 

35,765

 

 

 

2,123,757

 

Joseph O. Evans

 

 

448,914

 

 

 

323,218

 

 

 

2.0

 

 

 

38,835

 

 

 

1,583,099

 

James M. Miller

 

 

391,540

 

 

 

296,004

 

 

 

1.5

 

 

 

42,891

 

 

 

1,074,207

 

Jeffery D. Dahlberg

 

 

338,750

 

 

 

170,730

 

 

 

1.5

 

 

 

34,493

 

 

 

798,713

 

David J. Ketelsleger

 

 

372,788

 

 

 

 

 

 

2.0

 

 

 

28,006

 

 

 

773,582

 

Scott C. Wehner

 

 

319,304

 

 

 

 

 

 

1.5

 

 

 

28,955

 

 

 

507,911

 

 

Payments Made Upon Termination Without Cause or by the NEO for Good Reason Following a Change in Control

If at any time within two years after a change in control (“CiC”), the NEO’s employment is terminated without cause or by the NEO for good reason, we will be obligated:

 

·

to pay to the NEO an amount equal to the CiC Severance Multiple, as specified in the NEO’s employment agreement, times the sum of (x) the NEO’s base salary in effect on the date of termination plus (y) the annual bonus granted to the NEO for the fiscal year immediately on or preceding the date of termination, payable in the form of a salary continuation for a period of months equal to the product of 12 times the CiC Multiple, or in the form of a lump sum payment if the CiC occurs as a result of the sale or other disposition of all or substantially all of the Company’s assets;

 

·

subject to certain limitations, to provide the Termination Welfare Benefits;

 

·

to pay to the NEO any earned but unpaid base salary, annual bonus from prior years and vacation pay in the form of a lump sum payment; and

 

·

to pay to the NEO any unreimbursed reasonable business expenses incurred by the NEO on our behalf in the form of a lump sum payment.

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The following table quantifies amounts that would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination without cause or by the NEO for good reason following a CiC took place on December 31, 2015, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2015.

 

Name

 

Base Salary

 

 

Annual Bonus

 

 

Severance Multiple

 

 

Benefits

 

 

Total

 

Mark A. Fischer

 

$

830,305

 

 

$

896,729

 

 

 

3.0

 

 

$

59,485

 

 

$

5,240,587

 

K. Earl Reynolds

 

 

530,424

 

 

 

513,572

 

 

 

2.5

 

 

 

35,765

 

 

 

2,645,755

 

Joseph O. Evans

 

 

448,914

 

 

 

323,218

 

 

 

2.5

 

 

 

38,835

 

 

 

1,969,165

 

James M. Miller

 

 

391,540

 

 

 

296,004

 

 

 

2.0

 

 

 

42,891

 

 

 

1,417,979

 

Jeffery D. Dahlberg

 

 

338,750

 

 

 

170,730

 

 

 

2.0

 

 

 

34,493

 

 

 

1,053,453

 

 

Payments Made Upon Termination for Cause or by the NEO Without Good Reason

In the event an NEO is terminated for cause, or the NEO resigns without good reason, we have no further obligations to the NEO other than a lump sum payment of the following amounts:

 

·

any earned but unpaid base salary, annual bonus from prior years and vacation pay; and

 

·

unreimbursed reasonable business expenses incurred by the NEO on our behalf, so long as the NEO was not fired for cause due to his misappropriation of Company funds.

No amounts would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination for cause or by the NEO without good reason took place on December 31, 2015, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2015.

Payments Made Upon Death or Disability

In the event of an NEO’s death or disability, we will be obligated to pay to the NEO:

 

·

any earned but unpaid base salary, annual bonus from prior years and vacation pay;

 

·

unreimbursed reasonable business expenses incurred by the NEO on our behalf; and

 

·

a pro rata share of the annual bonus for the fiscal year in which the termination of employment occurs.

No amounts would have been paid pursuant to the employment agreements for each of our NEOs assuming an event of death or disability took place on December 31, 2015, and assuming all accrued compensation or reimbursable expenses had been paid on December 31, 2015.

Payments of separation benefits may be delayed if (i) the NEO is a “specified employee” within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (“Section 409A”), as of the date of his separation from service and (ii) the amount of any separation benefits payable to him are subject to Section 409A. In such instance, the separation benefits will not be paid to the NEO until six months after the date of separation from service, or, if earlier, the date of his death.

Other Payments Made Upon Termination, Retirement, Death or Disability

Certain accelerated vesting provisions will apply to each NEO’s restricted stock awards if the NEO’s employment is terminated without cause or by the NEO for good reason. See “—Compensation Discussion and Analysis—2010 Equity Incentive Plan.”

Regardless of the manner in which an NEO’s employment is terminated, he is entitled to receive amounts earned during his term of employment, including unused vacation pay and bonuses earned but not yet paid under the Annual Officers Bonus.

Additionally, if an NEO is terminated due to death or disability, that NEO will receive benefits under our disability plan or payments under our life insurance plan.

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Director Compensation

Members of our board of directors do not receive compensation for their services as board members. We do, however, reimburse our directors for all reasonable out-of-pocket costs and expenses incurred by them in connection with their service as a director.

Compensation Policies and Risk Management

While our board of directors strives to create incentives that encourage a level of risk-taking behavior consistent with our business strategy, our compensation policies and practices do not create risks that are reasonably likely to have a material adverse affect on our operations or financial condition.

 

 

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

Principal Stockholders

The following table sets forth information, as of March 25, 2016, with respect to all persons who own of record or are known by us to own beneficially more than 5% of our outstanding common stock, each director, and each of the NEOs, and by all directors and Senior Executives as a group.

 

 

 

Beneficial ownership

 

 

 

 

 

Name

 

Number

 

 

Class

 

 

% of

class

 

 

% of total

outstanding

 

Mark A. Fischer (1)(2)(7)

 

 

344,859

 

 

B

 

 

 

100.0

%

 

 

24.7

%

 

 

 

1

 

 

G

 

 

 

50.0

%

 

*

 

 

 

 

14,727

 

 

A

 

 

 

4.4

%

 

 

1.1

%

Altoma Energy G.P. (1)(3)

 

 

209,882

 

 

C

 

 

 

100.0

%

 

 

15.1

%

 

 

 

1

 

 

G

 

 

 

50.0

%

 

*

 

Charles A. Fischer, Jr. (1)(4)

 

 

209,882

 

 

C

 

 

 

100.0

%

 

 

15.1

%

 

 

 

1

 

 

G

 

 

 

50.0

%

 

*

 

CCMP Capital Investors II (AV-2), L.P.(5)

 

 

386,750

 

 

E

 

 

 

76.7

%

 

 

27.8

%

 

 

 

1

 

 

F

 

 

 

100.0

%

 

*

 

Christopher Behrens (5)

 

 

 

 

 

 

 

 

 

 

 

 

Will Jaudes (5)

 

 

 

 

 

 

 

 

 

 

 

 

Healthcare of Ontario Pension Plan Trust Fund (6)

 

 

295,078

 

 

A

 

 

 

88.2

%

 

 

21.2

%

K. Earl Reynolds (1)(7)

 

 

7,778

 

 

A

 

 

 

2.3

%

 

*

 

Joseph O. Evans (1)(7)

 

 

5,041

 

 

A

 

 

 

1.5

%

 

*

 

James M. Miller (1)(7)

 

 

4,911

 

 

A

 

 

 

1.5

%

 

*

 

Jeffery D. Dahlberg  (1)(7)

 

 

1,235

 

 

A

 

 

 

0.4

%

 

*

 

All Directors and Officers as a group (12 persons—ownership of

   total outstanding)

 

 

594,210

 

 

Various

 

 

 

 

 

 

 

42.6

%

 

*

Less than 1%

(1)

The address of the stockholder is in care of Chaparral Energy, Inc., 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114.

(2)

Fischer Investments, L.L.C., which is owned 50% by Mark A. Fischer 1994 Trust, for which Mark A. Fischer serves as Trustee, and 50% by Susan L. Fischer 1994 Trust, for which Susan L. Fischer, the spouse of Mark A. Fischer, serves as trustee, is the record owner of these shares of our common stock with the exception of 15,103 shares held by Mark A. Fischer and 3,030 shares held by the irrevocable trusts of his children.

(3)

Charles A. Fischer, Jr., one of our directors, is one of Altoma’s four managing general partners and beneficially owns a 23.15% general partner interest (including 0.90% owned by his spouse) in Altoma Energy G.P. The other partners of Altoma Energy G.P. who are each managing general partners and beneficially own in excess of 5% of its general partner interests are: Kenneth H. McCourt-36.75%; Ronald D. Jakimchuck-17.86%; and Gary H. Klassen-12.80%.

(4)

Includes all 209,883 shares owned of record by Altoma Energy G.P. Charles A. Fischer, Jr. serves as one of four managing partners of Altoma Energy G.P. Charles A. Fischer, Jr. owns directly a 22.25% general partner interest and his spouse owns directly a 0.90% general partner interest in Altoma Energy G.P.

(5)

CCMP Capital Investors II (AV-2), L.P. (“AV-2”), which owns 386,750 shares of Class E common stock and 1 share of Class F common, is part of an affiliated group of our stockholders ultimately controlled by CCMP Capital, LLC (“CCMP Capital”). The

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affiliated group also includes CCMP Energy I, Ltd. (“CCMP Energy”), which is wholly owned by CCMP Capital Investors II (AV-1), L.P. (“AV-1”) and which owns 58,217 shares of Class E common stock, and CCMP Capital Investors (Cayman) II, L.P. (“CCMP Cayman”), which owns 59,309 shares of Class E common stock. We refer to CCMP Cayman, AV-2 and AV-1 as the “CCMP Capital Funds”. The affiliated group controlled by CCMP Capital owns an aggregate of 504,277, or 36.2%, of our common shares outstanding as of March 25, 2016. 

The general partner of the CCMP Capital Funds is CCMP Capital Associates, L.P. (“CCMP Capital Associates”). The general partner of CCMP Capital Associates is CCMP Capital Associates GP, LLC (“CCMP Capital Associates GP”). CCMP Capital Associates GP is wholly owned by CCMP Capital. CCMP Capital ultimately exercises voting and dispositive power over the shares held directly or indirectly by the CCMP Capital Funds.

Christopher Behrens is a Managing Director of CCMP Capital Advisors, LLC, an investment advisor which is wholly owned by CCMP Capital. Will Jaudes is a principal at CCMP's Houston office. The address of Mr. Behrens, Mr. Jaudes and of each of the CCMP entities described above (other than CCMP Energy and CCMP Cayman) is c/o CCMP Capital, LLC, 245 Park Avenue, 16th FL, New York, NY 10167. The address of CCMP Energy and CCMP Cayman is c/o Intertrust Corporate Services (Cayman) Limited, 190 Elgin Avenue, George Town, Grand Cayman, KY1-9005, Cayman Islands.

(6)

Healthcare of Ontario Pension Plan Trust Fund purchased 280,000 shares of Class A stock converted from Class D and Class G stock held by CHK Energy Holdings, Inc. (CHK Energy Holdings”) effective January 14, 2014, and the remainder was purchased from various other stockholders effective January 14, 2014. The address of the stockholder is 1 Toronto Street, Suite 1400, Toronto, Ontario M5C 3B2.

(7)

Ownership of the Class A common stock is pursuant to restricted stock grants under our 2010 Plan. When granted, the Class A common stock related to these grants may vote, but remain subject to vesting in accordance with the 2010 Plan.

Securities Presently Authorized for Issuance under Our 2010 Plan

The following table provides information for all equity compensation plans as of December 31, 2015, under which our equity securities were authorized for issuance:

 

Plan Category

 

Number of Securities

to be Issued upon

Exercise of

Outstanding Options,

Warrants, and Rights

(a)

 

 

Weighted Average

Exercise Price of

Outstanding Options,

Warrants, and Rights

(b)

 

 

Number of Securities

Remaining Available for

Future Issuance under

Equity Compensation

Plans (Excluding

Securities Reflected

in Column (a))

(c)

 

 

Equity compensation plans approved by security

   holders

 

 

 

 

 

 

 

 

 

 

Equity compensation plans not approved by

   security holders

 

 

 

 

 

 

 

 

36,090

 

(1)

Total

 

 

 

 

 

 

 

 

36,090

 

 

 

(1)

This number reflects shares available for issuance under our 2010 plan. In addition, shares related to grants that are terminated, canceled, expire unexercised, or settled in such manner that all or some of the shares are not issued to a participant or are surrendered unvested shall immediately become available for issuance.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons, Promoters and Certain Control Persons

Stockholders Agreement

CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”), we, CHK Energy Holdings, Altoma Energy GP (“Altoma”), and Fischer Investments, L.L.C. (“Fischer”) entered into a Stockholders Agreement on April 12, 2010 (the “Original Date”), the closing date of the private sale of our common stock to CCMP. The Stockholders Agreement provides 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 (as defined in the Stockholders Agreement) 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 our indentures for our senior notes. In connection with the January 13, 2014 sale of our stock owned by CHK Energy Holdings to Healthcare of Ontario Pension Plan Trust Fund, the Stockholders Agreement was amended and restated.

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The Amended and Restated Stockholders Agreement also provides for the following stockholder-specific rights or restrictions:

 

·

Prior to a Qualified IPO, Altoma will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO (as defined in the Amended and Restated Stockholders Agreement), (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer votes for such approval.

 

·

Other than pursuant to the exercise of preemptive rights, Healthcare of Ontario Pension Plan Trust Fund may not acquire more than 25% of our outstanding common stock.

 

·

CCMP may sell up to 20% of its common stock owned on the Original Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Amended and Restated Stockholders Agreement (the “ROFO provisions”).

 

·

Fischer may sell up to 20% of its common stock owned immediately prior to the Original Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Original Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

 

·

Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, Fischer and CCMP in accordance with the procedures set forth in the Amended and Restated Stockholders Agreement.

 

·

Either (i) CCMP or (ii) a majority in interest of Fischer and Altoma may demand that we engage in a Qualified IPO if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock and (b) certain other conditions are met.

 

·

At any time after the four year anniversary of the Original Date, CCMP may demand a Demand IPO.

 

·

At any time after the sixth anniversary of the Original Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale (as defined in the Amended and Restated Stockholders Agreement), subject to a right of first offer to purchase the Company provided to Fischer.

With the exception of registration rights, the rights and preferences of a stockholder under the Amended and Restated Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of the Company’s fully-diluted common stock.

Review, Approval or Ratification of Transactions with Related Persons

Our board of directors is responsible for approving all related party transactions between us and any officer or director that would potentially require disclosure. The board of directors expects that any transactions in which related persons have a direct or indirect interest will be presented to the board of directors for review and approval but we have no written policy in place at this time.

Director Independence

Our board of directors uses the independence standards under the New York Stock Exchange (“NYSE”) corporate governance rules for determining whether directors are independent. The board of directors has determined that Messrs. Behrens, Jaudes and Charles A. Fischer, Jr. are independent under these NYSE rules for purposes of service on the board of directors.

131


 

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Independent Auditor and Fees

Grant Thornton LLP, our independent registered public accounting firm, audited our consolidated financial statements for fiscal year 2015. Grant Thornton LLP has billed us and our subsidiaries fees as set forth in the table below for (i) the audits of our 2015 and 2014 annual financial statements, reviews of quarterly financial statements, and other documents filed with the Securities and Exchange Commission and (ii) assurance and other services reasonably related to the audit or review of our financial statements.

 

 

 

Audit Fees

 

 

Audit-

Related

Fees

 

Fiscal year 2015 (1)

 

$

445,896

 

 

$

33,770

 

Fiscal year 2014 (1)

 

$

451,883

 

 

$

57,015

 

 

(1)

There were no fees billed in 2015 or 2014 that would constitute “Tax Fees” or “All Other Fees.”

Pre-Approved Policies and Procedures

We currently have two board committees, audit and compensation. Our board of directors has adopted policies regarding the pre-approval of auditor services. Specifically, the board of directors approves all services provided by the independent public accountants at its March meeting. All additional services must be pre-approved on a case-by-case basis. Our board of directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All of the services provided by Grant Thornton LLP during fiscal year 2015 were approved by the board of directors.

 

 

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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

 

Exhibit

No.

 

Description

 

 

 

3.1*

 

Second Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

3.2*

 

Second Amended and Restated Bylaws of the Company, dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

4.1*

 

Indenture dated September 16, 2010, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No.333-134748) filed on September 16, 2010)

 

 

 

4.2*

 

Form of 9% Senior Note due 2020 (included in Exhibit 4.9). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748) filed on September 16, 2010)

 

 

 

4.3*

 

Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)

 

 

 

4.4*

 

Form of 8¼ % Senior Note due 2021 (included as Exhibit A to Exhibit 4.11). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on February 22, 2011)

 

 

 

4.5*

 

Indenture dated May 2, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on May 2, 2012)

 

 

 

4.6*

 

Form of 7.625 % Senior Note due 2022 (included as Exhibit A to Exhibit 4.14). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on May 2, 2012)

 

 

 

4.7*

 

First Supplemental Indenture dated November 15, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on November 15, 2012)

 

 

 

4.8*

 

Form of 7.625% Senior Note due 2022 (included as Exhibit A to Exhibit 4.17). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on November 15, 2012)

 

 

 

10.1*†

 

Form of Indemnification Agreements, between the Company and each of the directors and certain executive officers thereof. (Incorporated by reference to Exhibit 10.6 to Form S-4 (SEC File No. 333-134748) filed on June 6, 2006)

 

 

 

10.2*†

 

Form of Assignment of Overriding Royalty Interest to James M. Miller. (Incorporated by reference to Exhibit 10.7 to Form S-1 (SEC File No. 333-130749) filed on December 29, 2005)

 

 

 

10.3*†

 

Second Amended and Restated Phantom Stock Plan dated December 31, 2008. (Incorporated by reference to Exhibit 10.22 of the Company’s Quarterly Report on Form 10-Q filed on November 10, 2009)

133


 

Exhibit

No.

 

Description

 

 

 

10.4*†

 

Non-Officer Restricted Stock Unit Plan dated as of March 1, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on May 2, 2012)

 

 

 

10.5*†

 

Amended and Restated 2010 Equity Incentive Plan effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed April 1, 2013)

 

 

 

10.6*†

 

Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Time Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed April 1, 2013)

 

 

 

10.7*†

 

Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Performance Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed April 1, 2013)

 

 

 

10.8*†

 

Chaparral Energy, LLC Long-Term Cash Incentive Plan Agreement. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 16, 2015)

 

 

 

10.9*†

 

Employment Agreement, dated as of April 12, 2010, by and among the Company and Mark A. Fischer. (Incorporated by reference to Exhibit 10.23 of the Company's Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.10*†

 

Employment Agreement, dated as of April 12, 2010, by and among the Company and Joseph O. Evans. (Incorporated by reference to Exhibit 10.24 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.11*†

 

Employment Agreement, dated as of April 12, 2010, by and among the Company and James M. Miller. (Incorporated by reference to Exhibit 10.26 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.12*†

 

Employment Agreement dated as of October 31, 2012, by and among the Company and Jeffery D. Dahlberg. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)

 

 

 

10.13*†

 

Form of Change of Control Severance Agreement for Corporate Officers, between the Company and certain executive officers thereof. (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed on May 10, 2013)

 

 

 

10.14*†

 

Employment Agreement, dated as of September 22, 2014, by and among the Company and Dave Winchester. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed November 12, 2014)

 

 

 

10.15*†

 

Amended and Restated Employment Agreement, dated as of January 1, 2014, by and among the Company and K. Earl Reynolds. (Incorporated by reference to Exhibit 10.25 of the Company’s Annual Report on Form 10-K filed on March 31, 2015)

 

 

 

10.16*

 

Eighth Restated Credit Agreement, dated as of April 12, 2010, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein. (Incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.17*

 

First Amendment to Eighth Restated Credit Agreement dated as of July 26, 2010. (Incorporated by reference to Exhibit 10.28 to the Company’s Quarterly Report on Form 10-Q filed on August 11, 2010)

 

 

 

10.18*

 

Second Amendment to Eighth Restated Credit Agreement dated as of January 11, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)

 

 

 

10.19*

 

Third Amendment to Eighth Restated Credit Agreement dated as of February 7, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)

 

 

 

10.20*

 

Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)

 

 

 

10.21*

 

Fifth Amendment to Eighth Restated Credit Agreement dated as of October 31, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 14, 2011)

 

 

 

10.22*

 

Sixth Amendment to Eighth Restated Credit Agreement dated as of December 1, 2011. (Incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)

 

 

 

134


 

Exhibit

No.

 

Description

10.23*

 

Seventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to

Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)

 

 

 

10.24*

 

Eighth Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)

 

 

 

10.25*

 

Ninth Amendment to Eighth Restated Credit Agreement dated as of May 24, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on August 14, 2012)

 

 

 

10.26*

 

Tenth Amendment to Eighth Restated Credit Agreement dated as of November 2, 2012. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 13, 2012)

 

 

 

10.27*

 

Eleventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2013. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on May 10, 2013)

 

 

 

10.28*

 

Twelfth Amendment to Eighth Restated Credit Agreement dated as of May 6, 2013. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on May 10, 2013)

 

 

 

10.29*

 

Thirteenth Amendment to Eighth Restated Credit Agreement dated as of October 29, 2013. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 14, 2013)

 

 

 

10.30*

 

Limited Consent and Fourteenth Amendment to Eighth Restated Credit Agreement dated as of May 19, 2014. (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q filed August 8, 2014)

 

 

 

10.31*

 

Letter Agreement to Eighth Restated Credit Agreement dated as of August 14, 2014. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed August 8, 2014)

 

 

 

10.32*

 

Letter Agreement to Eighth Restated Credit Agreement dated as of November 5, 2014. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed November 12, 2014)

 

 

 

10.33*

 

Fifteenth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2015. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed May 12, 2015)

 

 

 

10.34*

 

Carbon Dioxide Purchase and Sale Agreement dated March 24, 2011, by and between Chaparral CO2, LLC, as buyer and Coffeyville Resources Nitrogen Fertilizers, LLC, as seller. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on March 29, 2011)

 

 

 

10.35*

 

Asset Purchase Agreement dated as of October 11, 2013, by and between Chaparral Energy L.L.C. and Cabot Oil & Gas Corporation. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed November 14, 2013)

 

 

 

10.36*

 

Amended and Restated Stockholders’ Agreement, dated as of January 12, 2014, by and among the Company, CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., CCMP Capital Investors (Cayman) II, L.P Altoma Energy GP, CHK Energy Holdings, Inc. and Fischer Investments, L.L.C. (Incorporated by reference to Exhibit 10.38 of the Company’s Annual Report on Form 10-K filed March 31, 2014)

 

 

 

21.1

 

Subsidiaries of the Company.

 

 

 

31.1

 

Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

 

 

 

31.2

 

Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

 

 

 

32.1

 

Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

32.2

 

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

99.1

 

Report of Cawley, Gillespie & Associates, Inc.

 

 

 

99.2

 

Report of Ryder Scott Company, L.P.

 

 

 

101.INS

 

XBRL Instance Document.

 

 

 

101.SCH

 

XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL

 

XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

135


 

Exhibit

No.

 

Description

101.DEF

 

XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

101.LAB

 

XBRL Taxonomy Extension Label Linkbase Document.

 

 

 

101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 

 

*

Incorporated by reference

Management contract or compensatory plan or arrangement  

 

136


 

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.

 

 

 

 

 

 

CHAPARRAL ENERGY, INC.

 

 

 

By:

 

/s/ Mark A. Fischer

Name:

 

Mark A. Fischer

Title:

 

Chief Executive Officer

 

 

(Principal Executive Officer)

 

 

 

By:

 

/s/ Joseph O. Evans

Name:

 

Joseph O. Evans

Title:

 

Chief Financial Officer and

Executive Vice President

 

 

(Principal Financial Officer and

Principal Accounting Officer)

 

Date: March 30, 2016

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.

 

Signature

 

Title

 

Date

 

 

 

 

 

/S/    MARK A. FISCHER

 

Director

 

March 30, 2016

Mark A. Fischer

 

 

 

 

 

 

 

 

 

/S/    CHARLES A. FISCHER, JR.

 

Director

 

March 30, 2016

Charles A. Fischer, Jr.

 

 

 

 

 

 

 

 

 

/S/    CHRISTOPHER BEHRENS

 

Director

 

March 30, 2016

Christopher Behrens

 

 

 

 

 

 

 

 

 

/S/    K. EARL REYNOLDS

 

Director

 

March 30, 2016

K. Earl Reynolds

 

 

 

 

 

 

 

 

 

/S/    WILL JAUDES

 

Director

 

March 30, 2016

Will Jaudes

 

 

 

 

137


 

EXHIBIT INDEX

 

Exhibit

No.

 

Description

 

 

 

3.1*

 

Second Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

3.2*

 

Second Amended and Restated Bylaws of the Company, dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

4.1*

 

Indenture dated September 16, 2010, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No.333-134748) filed on September 16, 2010)

 

 

 

4.2*

 

Form of 9% Senior Note due 2020 (included in Exhibit 4.9). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748) filed on September 16, 2010)

 

 

 

4.3*

 

Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)

 

 

 

4.4*

 

Form of 8¼ % Senior Note due 2021 (included as Exhibit A to Exhibit 4.11). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on February 22, 2011)

 

 

 

4.5*

 

Indenture dated May 2, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on May 2, 2012)

 

 

 

4.6*

 

Form of 7.625 % Senior Note due 2022 (included as Exhibit A to Exhibit 4.14). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on May 2, 2012)

 

 

 

4.7*

 

First Supplemental Indenture dated November 15, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on November 15, 2012)

 

 

 

4.8*

 

Form of 7.625% Senior Note due 2022 (included as Exhibit A to Exhibit 4.17). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on November 15, 2012)

 

 

 

10.1*†

 

Form of Indemnification Agreements, between the Company and each of the directors and certain executive officers thereof. (Incorporated by reference to Exhibit 10.6 to Form S-4 (SEC File No. 333-134748) filed on June 6, 2006)

 

 

 

10.2*†

 

Form of Assignment of Overriding Royalty Interest to James M. Miller. (Incorporated by reference to Exhibit 10.7 to Form S-1 (SEC File No. 333-130749) filed on December 29, 2005)

 

 

 

10.3*†

 

Second Amended and Restated Phantom Stock Plan dated December 31, 2008. (Incorporated by reference to Exhibit 10.22 of the Company’s Quarterly Report on Form 10-Q filed on November 10, 2009)

 

 

 

10.4*†

 

Non-Officer Restricted Stock Unit Plan dated as of March 1, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on May 2, 2012)

 

 

 

10.5*†

 

Amended and Restated 2010 Equity Incentive Plan effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed April 1, 2013)

 

 

 

10.6*†

 

Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Time Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed April 1, 2013)

 

 

 

10.7*†

 

Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Performance Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed April 1, 2013)

 

 

 

10.8*†

 

Chaparral Energy, LLC Long-Term Cash Incentive Plan Agreement. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 16, 2015)

 

 

 

138


 

Exhibit

No.

 

Description

10.9*†

 

Employment Agreement, dated as of April 12, 2010, by and among the Company and Mark A. Fischer. (Incorporated

by reference to Exhibit 10.23 of the Company's Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.10*†

 

Employment Agreement, dated as of April 12, 2010, by and among the Company and Joseph O. Evans. (Incorporated by reference to Exhibit 10.24 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.11*†

 

Employment Agreement, dated as of April 12, 2010, by and among the Company and James M. Miller. (Incorporated by reference to Exhibit 10.26 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.12*†

 

Employment Agreement dated as of October 31, 2012, by and among the Company and Jeffery D. Dahlberg. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)

 

 

 

10.13*†

 

Form of Change of Control Severance Agreement for Corporate Officers, between the Company and certain executive officers thereof. (Incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q filed on May 10, 2013)

 

 

 

10.14*†

 

Employment Agreement, dated as of September 22, 2014, by and among the Company and Dave Winchester. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed November 12, 2014)

 

 

 

10.15*†

 

Amended and Restated Employment Agreement, dated as of January 1, 2014, by and among the Company and K. Earl Reynolds. (Incorporated by reference to Exhibit 10.25 of the Company’s Annual Report on Form 10-K filed on March 31, 2015)

 

 

 

10.16*

 

Eighth Restated Credit Agreement, dated as of April 12, 2010, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein. (Incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)

 

 

 

10.17*

 

First Amendment to Eighth Restated Credit Agreement dated as of July 26, 2010. (Incorporated by reference to Exhibit 10.28 to the Company’s Quarterly Report on Form 10-Q filed on August 11, 2010)

 

 

 

10.18*

 

Second Amendment to Eighth Restated Credit Agreement dated as of January 11, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)

 

 

 

10.19*

 

Third Amendment to Eighth Restated Credit Agreement dated as of February 7, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)

 

 

 

10.20*

 

Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)

 

 

 

10.21*

 

Fifth Amendment to Eighth Restated Credit Agreement dated as of October 31, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 14, 2011)

 

 

 

10.22*

 

Sixth Amendment to Eighth Restated Credit Agreement dated as of December 1, 2011. (Incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)

 

 

 

10.23*

 

Seventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)

 

 

 

10.24*

 

Eighth Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)

 

 

 

10.25*

 

Ninth Amendment to Eighth Restated Credit Agreement dated as of May 24, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on August 14, 2012)

 

 

 

10.26*

 

Tenth Amendment to Eighth Restated Credit Agreement dated as of November 2, 2012. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 13, 2012)

 

 

 

10.27*

 

Eleventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2013. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on May 10, 2013)

 

 

 

10.28*

 

Twelfth Amendment to Eighth Restated Credit Agreement dated as of May 6, 2013. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on May 10, 2013)

 

 

 

10.29*

 

Thirteenth Amendment to Eighth Restated Credit Agreement dated as of October 29, 2013. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 14, 2013)

 

 

 

139


 

Exhibit

No.

 

Description

10.30*

 

Limited Consent and Fourteenth Amendment to Eighth Restated Credit Agreement dated as of May 19, 2014. (Incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q filed August 8, 2014)

 

 

 

10.31*

 

Letter Agreement to Eighth Restated Credit Agreement dated as of August 14, 2014. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed August 8, 2014)

 

 

 

10.32*

 

Letter Agreement to Eighth Restated Credit Agreement dated as of November 5, 2014. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed November 12, 2014)

 

 

 

10.33*

 

Fifteenth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2015. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed May 12, 2015)

 

 

 

10.34*

 

Carbon Dioxide Purchase and Sale Agreement dated March 24, 2011, by and between Chaparral CO2, LLC, as buyer and Coffeyville Resources Nitrogen Fertilizers, LLC, as seller. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on March 29, 2011)

 

 

 

10.35*

 

Asset Purchase Agreement dated as of October 11, 2013, by and between Chaparral Energy L.L.C. and Cabot Oil & Gas Corporation. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed November 14, 2013)

 

 

 

10.36*

 

Amended and Restated Stockholders’ Agreement, dated as of January 12, 2014, by and among the Company, CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., CCMP Capital Investors (Cayman) II, L.P Altoma Energy GP, CHK Energy Holdings, Inc. and Fischer Investments, L.L.C. (Incorporated by reference to Exhibit 10.38 of the Company’s Annual Report on Form 10-K filed March 31, 2014)

 

 

 

21.1

 

Subsidiaries of the Company.

 

 

 

31.1

 

Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

 

 

 

31.2

 

Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act.

 

 

 

32.1

 

Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

32.2

 

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

 

 

99.1

 

Report of Cawley, Gillespie & Associates, Inc.

 

 

 

99.2

 

Report of Ryder Scott Company, L.P.

 

 

 

101.INS

 

XBRL Instance Document.

 

 

 

101.SCH

 

XBRL Taxonomy Extension Schema Document.

 

 

 

101.CAL

 

XBRL Taxonomy Extension Calculation Linkbase Document.

 

 

 

101.DEF

 

XBRL Taxonomy Extension Definition Linkbase Document.

 

 

 

101.LAB

 

XBRL Taxonomy Extension Label Linkbase Document.

 

 

 

101.PRE

 

XBRL Taxonomy Extension Presentation Linkbase Document.

 

*

Incorporated by reference

Management contract or compensatory plan or arrangement

 

 

140