Chaparral Energy, Inc. - FORM 10-K

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EX-32.1 - EXHIBIT 32.1 - Chaparral Energy, Inc.	cprex32112312014.htm
EX-31.2 - EXHIBIT 31.2 - Chaparral Energy, Inc.	cprex31212312014.htm
EX-31.1 - EXHIBIT 31.1 - Chaparral Energy, Inc.	cprex31112312014.htm
EX-32.2 - EXHIBIT 32.2 - Chaparral Energy, Inc.	cprex32212312014.htm
EX-21.1 - EXHIBIT 21.1 - Chaparral Energy, Inc.	ex211subsidiaries2014.htm
EX-99.2 - EXHIBIT 99.2 - Chaparral Energy, Inc.	chaparralenergyllc12-31x20.htm
EXCEL - IDEA: XBRL DOCUMENT - Chaparral Energy, Inc.	Financial_Report.xls
EX-99.1 - EXHIBIT 99.1 - Chaparral Energy, Inc.	cga_finalreport.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________

Form 10-K

____________________________



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

For the fiscal year ended December 31, 2014



¨	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 ¨ No ý

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

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

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

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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 ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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	ý	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 ¨ No ý

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 31, 2015:



Class	Number of shares
Class A Common Stock, $0.01 par value	352,552
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

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CHAPARRAL ENERGY, INC.

Index to Form 10-K



Part I
Items 1. and 2.	Business and Properties	7
Item 1A.	Risk Factors	32
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	46
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	47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	67
Item 8.	Financial Statements and Supplementary Data	71
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	112
Item 9A.	Controls and Procedures	112
Item 9B.	Other Information	112
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	113
Item 11.	Executive Compensation	116
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	131
Item 14.	Principal Accounting Fees and Services	132
Part IV
Item 15.	Exhibits and Financial Statement Schedules	133
Signatures

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CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

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


•	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;


•	cash flow and anticipated liquidity;


•	estimates of proved reserves;


•	exploitation of property acquisitions; and


•	marketing of oil and natural gas.

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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;


•	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.

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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.

Bcf	One billion cubic feet of natural gas.

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.

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.

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

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.

Infill wells	Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

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.

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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.

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.

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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.

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.

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.

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.

Waterflood	The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.

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.

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PART I

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

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Overview

Founded in 1988, we are an independent oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma and are one of the largest oil producers in the state. In recent years, we have capitalized on our sustained success in our Mid-Continent area, expanding our holdings to become a leading player in both the liquids-rich Northern Oklahoma Mississippian and the oil-rich Panhandle Marmaton plays. In addition, we have a leadership position in CO₂ EOR and 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, 2014, we had estimated proved reserves of 159.4 MMBoe with a PV-10 value of approximately $2.5 billion. These estimated proved reserves included 57.5 MMBoe of reserves in our active EOR project areas. Our reserves were 58% proved developed, 64% crude oil, and 11% natural gas liquids. For the year ended December 31, 2014, our net average daily production was 30.1 MBoe, our estimated reserve life was approximately 14.5 years, and our oil and natural gas revenues were $681.6 million. 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 on page 22.

Beginning in 2011, we have increased our focus on acquisition 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 capital dollars being spent in the Mississippian Lime, Panhandle Marmaton, Oswego and Woodford Shale plays. By concentrating in these core areas, we are developing a significant resource base to achieve production and reserve growth.

In 1993, we began acquiring properties with CO₂ EOR potential. We have initiated CO₂ injection in nine of these units to date. In 2005 and 2006, we completed two larger acquisitions of $152.9 million and $480.5 million, respectively, of oil and natural gas properties containing substantial CO₂ EOR potential, which complemented our existing property base. In June of 2013, we commenced CO₂ injection in our North Burbank Unit, the largest of our EOR projects.

2015 Outlook

Until the last six months, crude oil prices had been reasonably stable, with NYMEX WTI averaging approximately $95 per barrel over the past four years. During that time period, relatively easy access to low-cost capital and advances in horizontal drilling and fracture stimulations led to significant growth in U.S. oil supply. Production in the U.S. in October 2014 surpassed 9 million barrels a day, a level not seen since the mid-1980s. As a result of increased U.S. production as well as other global supply and demand factors, crude oil prices declined by nearly 50% during the fourth quarter of 2014 and remain depressed into the first quarter of 2015. As of March 27, 2015, NYMEX WTI was $48.87 per barrel and the three-year forward curve for NYMEX WTI was $58.26 per barrel. In light of the foregoing, projected capital spending and drilling programs by exploration and production companies are expected to dramatically decline.

Given the uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, we have reduced planned capital spending in 2015 by approximately 76% compared to 2014 levels, to $177.3 million. At this investment level, we expect our capital spending to be within cash flows from operations.

Our primary goals during 2015 include:

• preserving liquidity and financial strength;

• limiting new borrowings and balancing capital investments with cash flows;

• immediately decreasing rig activity from ten rigs to two rigs and high-grading investments based on rates of return;

• implementing a plan to reduce net general and administrative expenses by 21% to 31% (after excluding the effects of non-recurring expenses due to implementation of a workforce reduction plan); and

• implementing a plan to reduce domestic per unit lease operating costs by approximately 9% to 12%.

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Business Strategy

Despite a reduced capital budget for 2015 that is reflective of the current price environment, our primary objective continues to be to create value for investors by developing our core acreage holdings located in the Mid-Continent region through application of modern technology. The hydrocarbon rich Mid-Continent basins offer several positive attributes, including a long history of commercial production from numerous petroleum reservoirs, extensive infrastructure and a supportive regulatory environment. Over the past several years, we have amassed a material acreage position in this region consisting of approximately 500,000 surface acres with much of our surface acreage having exposure to multiple pay horizons. Summing the acreage for each of the individual formation plays within our surface acreage would aggregate approximately 661,000 net play acres. We believe the magnitude and concentration of our acreage within our project areas provide us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilize centralized oil, natural gas and water fluid handling facilities and infrastructure, and reduce the time and cost of rig mobilization. Our significantly expanded holdings in the region provide us an opportunity to apply technology, including horizontal drilling with modern hydraulic fracture stimulations, to “unconventional” reservoirs. Additionally, we have numerous opportunities to apply and expand EOR techniques, including CO₂ injection, to reservoirs that have previously undergone secondary recovery operations to develop our acreage.

As part of our strategy to grow reserves and production profitably, we seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancing, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and natural gas production to maximize both volumes and wellhead price. As of December 31, 2014, we operated properties comprising approximately 85% of our proved reserves. The principal elements of our strategy are described further below.

Focus drilling program on repeatable resource plays in the Mid-Continent Area. During the year ended December 31, 2014, we spent approximately $470.2 million on drilling. We consider our repeatable resource plays to include the Northern Oklahoma Mississippian Lime, Panhandle Marmaton, Oswego and Woodford Shale plays. We will refer to these, along with all of our other acreage and production (“Legacy Production Areas”), as “E&P Areas”. During 2014, we spent $434.9 million of our drilling capital in these E&P Areas. Our drilling expenditures represented approximately 64% of our total capital expenditures for oil and natural gas properties and approximately 65% of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for 2014. In 2015, we currently plan to spend approximately $127.7 million, or 72% of our 2015 capital budget, on our E&P Areas of which $97.7 million of the capital expenditures will be on drilling, including $91.9 million for drilling in our repeatable resource plays mentioned above. We plan to reduce our capital spending in 2015 as compared to 2014 in order to align our 2015 capital budget expenditures with lower crude oil and natural gas prices. As more fully discussed in the section “Risk factors,” our actual drilling activities may change depending on the availability of financing and capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

EOR activities. Our EOR properties include both currently active EOR projects and potential EOR properties with no current EOR production or reserves at December 31, 2014. We define active EOR projects as activities on properties that have proved EOR reserves, ongoing EOR operations, or that have an approved authorization for expenditure for EOR operations. Our active EOR projects are located in the Burbank area of northeast Oklahoma (“Burbank”), the Panhandle areas of Oklahoma and Texas (“Panhandle”), and Central Oklahoma (“Central Oklahoma”). As of December 31, 2014, we have nine active EOR units where we are actively injecting CO₂. During 2014, we spent $190.4 million on the development of our EOR projects, which was an increase from $151.1 million in 2013. As with our drilling program, we plan to reduce capital spending in 2015 as compared to 2014 in order to align our 2015 capital expenditures with lower crude oil prices. We intend to expand additional undeveloped patterns as oil prices increase. We have budgeted $49.6 million, or 28%% of our 2015 capital budget, for development of our EOR projects in 2015.

We define our potential EOR properties primarily as properties that we have assessed as having commercial EOR potential and that we plan to develop once additional CO₂volumes become available. We have not allocated any significant amount of our 2015 capital budget to our potential EOR properties.

High-quality asset portfolio. Through our successful drilling and leasing program, we have amassed a deep inventory of high-quality drilling locations. As of December 31, 2014, management has identified a drilling inventory of over 8,377 potential unrisked drilling locations, including 409 proved undeveloped drilling locations. Many of these locations have drilling potential in multiple horizons which we refer to as “stacked pay” opportunities. Our drilling inventory consists of the development of our proved and non-proved reserves. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs and drilling results.

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Maintain an experienced management team and strong investor support. Mark Fischer, our Chief Executive Officer and founder, has operated in the oil and natural gas industry for more than 40 years after starting his career at Exxon Mobil Corporation as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 35 years of experience in the oil and natural gas industry. Earl Reynolds, who became our Chief Operating Officer in February 2011 and President in January 2014, has over 30 years of oil and natural gas production experience. Individuals in our 11-person management team have an average of 33 years of experience in the oil and natural gas industry.

CCMP Capital is a leading global private equity firm with more than 25 years in the energy industry, investing approximately $1.5 billion in energy over its history. CCMP Managing Director Chris Behrens joined our board of directors in 2010. Mr. Behrens has worked in private equity for more than 20 years and leads CCMP Capital’s energy investment activities. Kyle Vann, an Advisor with CCMP, joined our board of directors in 2012.

Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. To protect cash flows that we use for on-going operations and for capital investments, we enter into oil and natural gas price swaps, enhanced swaps, costless collars, purchased and sold puts and basis protection swaps. Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process.

2014 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:


•	Response at North Burbank Unit. Our oil production from our North Burbank unit increased by 17% primarily as a result of continued response to our CO₂ injection, continued field development and expansion of facilities.

•

Asset sales. We completed the sale of two separate divestiture packages of non-core properties during the second quarter of 2014 for $148.4 million in cash, net of post-closing adjustments. In July 2014, we completed the sale of two additional divestiture packages of non-core properties for $95.9 million in cash, net of post-closing adjustments. The properties included in these four sales accounted for approximately 6% and 15% of our total production during 2014 and 2013, respectively. In addition to the packages described above, we also received approximately $44.5 million in cash for various other property divestitures during 2014.

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Properties

The following table presents our proved reserves, PV-10 value as of December 31, 2014, average net daily production for the year ended December 31, 2014, and average net daily production for the quarter ended December 31, 2014, 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, 2014 were $94.99 per Bbl of oil, $4.35 per Mcf of natural gas and $36.10 per Bbl of natural gas liquids.



	Proved reserves as of December 31, 2014								Average daily production (MBoe per day) Year ended December 31, 2014	Average daily production (MBoe per day) Quarter ended December 31, 2014
	Oil (MBbls)	Natural gas (MMcf)	Natural gas liquids (MBbls)	Total (MBoe)	Percent of total MBoe		PV-10 value ($MM)
E&P Areas
Mississippian	14,800	107,218	5,011	37,681	23.6	%	$	508	7.2	8.3
Panhandle Marmaton	4,194	6,462	1,222	6,493	4.1	%	111		2.9	3.6
Woodford Shale	760	17,981	1,619	5,376	3.4	%	52		1.2	1.4
Oswego	2,091	1,045	101	2,366	1.5	%	81		0.8	0.6
Legacy Production Areas	10,845	100,267	6,129	33,685	21.1	%	443		8.4	8.2
Total E&P Areas	32,690	232,973	14,082	85,601	53.7	%	1,195		20.5	22.1
EOR Project Areas
Active EOR Projects	57,382	421	22	57,474	36.1	%	1,073		5.0	5.3
Potential EOR Projects	10,976	11,692	2,749	15,674	9.8	%	266		2.7	2.6
Total EOR Project Areas	68,358	12,113	2,771	73,148	45.9	%	1,339		7.7	7.9
Non-Core Properties	199	2,670	—	644	0.4	%	13		1.9	0.1
Total	101,247	247,756	16,853	159,393	100.0	%	$	2,547	30.1	30.1

E&P Areas

E&P Areas includes our Mississippian, Panhandle Marmaton, Oswego and Woodford Shale plays which are our repeatable resource plays. In order to align our capital expenditures with lower crude oil prices, we are dramatically cutting back our drilling capital budget for 2015 and focusing on drilling in our highest return areas. We currently plan to spend the majority of our capital in 2015 for horizontal drilling in our Mississipian, Oswego and Woodford Shale plays. E&P Areas also includes our Legacy Production Areas which primarily include mature properties with low production decline curves. The majority of the properties in our Legacy Production Areas are located in the Mid-Continent and hold leasehold acreage for future exploration in our existing repeatable resource plays. Proved reserves in our E&P Areas at December 31, 2014 totaled 85.6 MMBoe, 60.7% of which were proved developed reserves.The Company’s interests in operated E&P Area properties as of December 31, 2014 included 883 (706 net) producing wells with an average working interest of 80%. During the year ended December 31, 2014, our net average daily production in E&P Area properties was approximately 20.5 MBoe per day, or 68% of our total net average daily production.

Mississippian Play—Various Counties, Oklahoma. Our Mississippian operations consist of our Northern Oklahoma Mississippi Play (“NOMP”) which includes substantially all of northwest Oklahoma. The NOMP is principally carbonate rich in the north and develops into carbonate/shale sequence as the play moves south, where the upper portion is referred to as Meramac. As of December 31, 2014, our Mississippian operations accounted for 37.7 MMBoe, or 24% of our proved reserves. During the year ended December 31, 2014, our net average daily production in the Mississippian was approximately 7.2 MBoe per day, or 24% of our total net average daily production. This area has a long history of production from vertical wells and a well-developed infrastructure system to support further development. Several companies in the industry are devoting large amounts of capital toward horizontal drilling activities in further developing this shallow, cost-effective resource play. Across the play, we estimate the anticipated ultimate recovery per well to be 352 MBoe at an average completed well cost of approximately $3.0 million.

Leasing in the NOMP is competitive as the play continues to yield positive results. During 2014, we spent $68.1 million on acquisitions in this area which included leasehold acquisitions of 205,000 (72,300 net) acres. Our acreage position in the NOMP currently consists of approximately 771,000 (259,000 net) acres.

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Primarily as a result of our drilling activity, our net average daily production from this area has increased significantly to approximately 7,190 Boe/d in 2014, compared to 3,947 Boe/d and 1,490 Boe/d in 2013 and 2012, respectively. During 2014, we spent $200.3 million on drilling activities in the NOMP . We drilled and/or participated in the drilling of 75 (42 net) horizontal wells that were completed during 2014. As we align our 2015 drilling capital budget expenditures with lower crude oil and natural gas prices, this area, although reduced, remains core to our operations and we have allocated approximately $58.6 million of our 2015 drilling budget to this play. We plan to operate one to two rigs in this play throughout the year.

Panhandle Marmaton Play—Texas and Oklahoma Panhandles. Our Panhandle Marmaton play development program began in 2012. We currently own approximately 234,000 (117,000 net) leasehold acres in this play and we are the largest operator in the play. In addition, we own extensive infrastructure in this play, including saltwater disposal wells and electricity, that will generate efficiencies and economies of scale as our development program matures. Our leasehold position provides for horizontal drilling opportunities targeting the Marmaton lime, which consists of numerous productive carbonate benches. The multi-stage fracture stimulation jobs performed in the play have increased its productivity considerably. The anticipated ultimate recovery for a Panhandle Marmaton horizontal well is an estimated 120 -170 MBoe per well at an average completed well cost of approximately $3.0 million.

The Panhandle Marmaton play accounted for 6.5 MMBoe, or 4.1% of our proved reserves as of December 31, 2014. Primarily as a result of our recent drilling activity, our net average daily production from this area increased to approximately 2,878 Boe/d in 2014 compared to 889 Boe/d and 103 Boe/d in 2013 and 2012, respectively. Our expenditure for drilling activities in this area was $139.6 million in 2014. We drilled or participated in the drilling of 40 (31 net) horizontal wells that were completed in this play during 2014. Our expenditure for acquisitions in this area was $7.5 million in 2014. In order to align our 2015 capital expenditures with lower crude oil prices and to allow us time to further optimize the play, we have not allocated a significant amount of our 2015 drilling budget to this play.

Woodford Shale Play—Various Counties, Oklahoma. The horizontal development of this widespread unconventional shale resource play, as currently defined, spans the Anadarko basin from Dewey and Custer counties on the west to Pittsburg county on the east, Carter and Atoka counties on the south and northward into Alfalfa and Grant counties. Industry-wide drilling results through December 31, 2014 have established well-defined productive areas including separate oil-rich and natural gas-rich basins. The Woodford Shale play is the source rock for many of our carbonate plays and is a significant opportunity for reserve and production growth for Chaparral.

We currently own approximately 602,000 (166,000 net) acres in this play. The Woodford Shale play accounted for 5.4 MMBoe, or 3.4%, of our proved reserves as of December 31, 2014. Our net average daily production in this area increased to approximately 1,189 Boe/d in 2014 compared to 193 Boe/d and 190 Boe/d in 2013 and 2012, respectively. Our drilling investment was $17.6 million and we participated in the drilling of 10 (2 net) wells in this area during 2014. We have allocated approximately $11.7 million of our 2015 drilling budget to this play.

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Oswego Play—Kingfisher County, Oklahoma. We currently own approximately 339,000 (119,000 net) acres within the outline of our Oswego play. The Oswego formation is a carbonate which underlies the majority of the Sooner Trend, which encompasses NW Oklahoma, including Canadian, Kingfisher, Garfield, Major, and Woods Counties. It has historically produced vertically from thousands of wells. Over the last 18 months, we have drilled 8 (6 net) horizontal Oswego wells.

The Oswego play accounted for 2.4 MMBoe, or 1.5%, of our proved reserves as of December 31, 2014. Our average net daily production in this area increased from 164 Boe/d to approximately 777 Boe/d. Our drilling investment in this area was $25.2 million and we drilled and completed 7 (5 net) wells during 2014. We have allocated approximately $15.3 million of our 2015 drilling budget to this play. We estimate the anticipated ultimate recovery per well to be 331 MBoe at an average completed well cost of approximately $3.0 million.

Legacy Production Areas. Our Legacy Production Areas accounted for 33.7 MMBoe, or 21.1% of our proved reserves as of December 31, 2014. Our production in these areas was 8,375 Boe/d in 2014 compared to 9,859 Boe/d in 2013. The decrease in production year-over-year is primarily the result of natural production decline and divestitures within these areas. Our drilling investment in these areas was $52.3 million and we drilled 42 (25 net) wells that were completed during 2014. We have not allocated any significant amount of our 2015 drilling budget to this area.

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, 2014	Active EOR		Potential EOR		Total for EOR Project Areas
Reserves (MBoe)	57,474		15,674		73,148
Production (Boe/d)	5,042		2,747		7,789
Capital expenditures excluding acquisitions (in thousands)	$	179,035	$	11,395	$	190,430

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 our various 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 can 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.

Major EOR Property Areas

North Burbank Unit. As of December 31, 2014, the North Burbank Unit, which is our largest property, accounted for 44.7 MMBoe, or 28%, of our proved reserves, including 17.3 MMBoe of proved developed reserves and 27.4 MMBoe of proved undeveloped CO₂ reserves. The producing zones are the Red Fork and Bartlesville formations and occur at a depth of approximately 3,000 feet. We own a 99% working interest in this Unit and are also the operator. Our net average daily production from this Unit increased from 1,210 Boe/d in 2013 to approximately 1,418 Boe/d in 2014 primarily as a result of our CO₂ injection. As of December 31, 2014, we had 278 (276 net) producing wells, 184 active injection wells, and 558 shut-in and temporarily abandoned wells in this Unit. Upside potential exists in restoring a majority of the temporarily abandoned wells to production and in expanding the CO₂ programs. With the success of the CO₂ EOR program, we have terminated the earlier polymer EOR program in the field. Due to the size of the North Burbank Unit, there is insufficient CO₂ availability and third party services available to complete the development of the North Burbank Unit within five years, and as a result the development of the North Burbank Unit will be an ongoing project.

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We commenced CO₂ injection at the 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 13—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 the North Burbank Unit in June 2013. With some response by December, we added proved EOR CO₂ reserves of 5.3 MMBoe and removed polymer reserves of 1.5 MMBoe for the 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. Development of remaining phases will follow in future years as a sufficient volume of purchased and recycled CO₂ becomes available.

Our total investment in the North Burbank Unit during 2014 was $123.6 million associated with drilling 16 wells including 12 injection wells, reactivating 12 wells, installing surface facilities and purchasing CO₂ for injection. In order to align our 2015 capital expenditures with the lower crude oil prices, we have reduced our budgeted level of expenditures in the North Burbank unit in 2015. During 2013 and 2014, we expanded our capital budget to include the development of CO₂ injection patterns into Phase III which have not yet been utilized. We will be expanding our CO₂ injection into these patterns during 2015. In 2015, we plan to invest approximately $16.8 million to continue developing the North Burbank Unit, primarily for continuing injection and maintenance in our existing patterns and for completion of central batteries and other production facilities which were initiated in 2014. Significant additional capital expenditures will be required over several years to fully develop the North Burbank unit.

Camrick Area Units. As of December 31, 2014, the Camrick Area Units accounted for 5.8 MMBoe, or 3.7% of our proved reserves, substantially all of which are considered EOR reserves. Approximately 2.9 MMBoe of the proved reserves in this area are undeveloped. The Camrick Area Units consist of the Camrick Unit, where we began CO₂ injection in 2001 and the North Perryton Unit, where we began CO₂ injection in 2006. Currently, CO₂ injection operations are continuing in the Phase I and II areas of the Camrick Unit and within the North Perryton Unit. As of December 31, 2014, we had 67 (40 net) producing wells with an average working interest of 60%, 40 active water and CO₂ injection wells, and 47 temporarily abandoned wells in this area. Our net average daily production from this area increased to 1,037 Boe/d in 2014 compared to 916 Boe/d in 2013 and 1,006 Boe/d in 2012.

Our total investment in the Camrick Area Units during 2014, including the purchase of CO₂ for injection and general well work, was $6.3 million. We have allocated approximately $4.9 million of our capital expenditures budget for 2015 to this area for continued purchase of CO₂, drilling and completions, electrical upgrades, and remedial well work.

Booker Area Units. As of December 31, 2014, the Booker Area Units accounted for 1.0 MMBoe, or 0.6%, of our proved reserves, all of which are developed. All of the reserves in this Unit are considered EOR reserves as of December 31, 2014. In September 2009, we began CO₂ injection into our three Booker Area Units, which we operate with an average working interest of 99%. As of December 31, 2014, we had 13 producing wells, 8 active water and CO₂ injection wells, and 2 shut-in and temporarily abandoned wells in the Unit. Our net average daily production from this area decreased to 789 Boe/d in 2014 compared to 813 Boe/d in 2013, which was an increase from 402 Boe/d in 2012. The significant increase in net average daily production from 2012 to 2013 is primarily a result of continued response from our 2012 project development, which increased the CO₂ injection patterns from five to nine.

Our total investment in the Booker Area Units during 2014 was $11.6 million, primarily spent on CO₂ related purchases. We have allocated approximately $4.5 million of our capital expenditures budget for 2015 to this area for continued purchase of CO₂and remedial well work.

Farnsworth Unit. The Farnsworth Unit, which lies to the southeast of and is analogous to the Camrick Area Units, accounted for 5.1 MMBoe, or 3.2%, of our proved reserves, at December 31, 2014. All of the reserves in this Unit, which includes 1.9 MMBoe of proved undeveloped reserves, are considered EOR reserves as of December 31, 2014. We acquired a 100% working interest in the Farnsworth Unit in November 2009 and we began CO₂ injection in December 2010. As of December 31, 2014, we had 34 producing wells, 14 active water and CO₂ injection wells, and 46 shut-in and temporarily abandoned wells in the Unit. Our net average daily production from this Unit increased to 1,368 Boe/d in 2014 compared to 815 Boe/d in 2013 and 475 Boe/d in 2012. The increase in net average daily production from 2013 to 2014 is primarily due to pattern expansion related to new drills and reactivated wells. The significant increase in net average daily production from 2012 to 2013 is primarily due to higher volumes of CO₂ injected into the reservoir.

During 2014, we invested $30.4 million in the Farnsworth Unit to drill 9 wells, return 4 production and 4 injection well to service and complete associated field facilities work. We have allocated approximately $7.9 million of our capital expenditures budget for 2015 to this Unit for the continued development of the CO₂ project and related field facilities.

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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 CO₂volumes become available. Production generated from these fields, most of which we intend to flood with CO₂ in the future, totaled 2,747 Boe/d, or 9%, of total production in 2014. We have not allocated any significant amount of our 2015 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 and 68 miles of CO₂ pipeline to transport the CO₂ to the Burbank field, both of which we completed in 2013. During 2014, we purchased an average of 38 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 the North Burbank Unit.

Borger. We have a long-term contract to purchase up to approximately 20 MMcf/d of CO₂ produced at the Agrium nitrogen fertilizer plant in Borger, Texas. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, and has commenced installation of such additional equipment in 2014. We own and operate the Borger CO₂ compression facility 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 2014 we purchased an average of 14 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 to approximately 11 MMcf/d by the end of 2015. 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 compression and processing facility, 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 2014 we purchased an average of 13 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 2014 we purchased an average of approximately three MMcf/d from the 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 pipeline and compression facility infrastructure during 2014 was $3.4 million. We have allocated approximately $8.6 million of our capital expenditures budget for 2015 to maintenance associated with our CO₂pipeline and compression facility infrastructure.

Non-Core Properties

Our Non-Core Properties consist of our assets outside of the Mid-Continent Area, which prior to 2014 included primarily the Permian Basin, Ark-La-Tex, North Texas and Gulf Coast areas. During the second and third quarters of 2014, we closed on the majority of our previously announced strategic divestitures of our non-core oil and natural gas properties in the Permian Basin, Ark-La-Tex, and North Texas areas in an effort to redeploy capital and employee resources to develop our core areas. Before 2014, these properties accounted for approximately 20.6 MMBoe, or 12.9% of our proved reserves as of December 31, 2013.

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.

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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 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 responsible for overseeing the preparation of our reserve estimates. He has a Master of Science degree in Petroleum Engineering and 19 years of industry experience that includes diverse petroleum engineering roles and reserves management. In addition, he has been a member of the Society of Petroleum Engineers since 1996.

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 eight full-time employees, comprised of five degreed engineers and four engineering analysts/technicians.

We have internal auditing 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.

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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,
	2014		2013		2012
Cawley, Gillespie & Associates, Inc.	39	%	53	%	50	%
Ryder Scott Company, L.P.	50	%	33	%	34	%
Internally prepared	11	%	14	%	16	%

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. 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 on page 22.




	As of December 31,
	2014			2013			2012
Estimated proved reserve volumes:
Oil (Mbbls)(1)	101,247			92,813			103,243
Natural gas (MMcf)	247,756			302,922			257,115
Natural gas liquids (MBbls)(1)	16,853			15,175			—
Oil equivalent (MBoe)	159,393			158,475			146,095
Proved developed reserve percentage	58		%	64		%	65		%
Estimated proved reserve values (in thousands):
Future net revenue	$	5,943,028		$	5,312,224		$	4,780,316
PV-10 value	$	2,547,204		$	2,349,656		$	2,068,620
Standardized measure of discounted future net cash flows	$	1,894,700		$	1,743,772		$	1,523,681
Oil and natural gas prices:(2)
Oil (per Bbl)	$	94.99		$	96.78		$	94.71
Natural gas (per Mcf)	$	4.35		$	3.67		$	2.76
Natural gas liquids (per Bbl)(3)	$	36.10		$	32.53		$	—
Estimated reserve life in years(4)	14.5			16.3			16.0

____________


(1)	Prior to 2013, NGLs were included with oil reserves, which affects the comparability of estimated reserves for 2014, 2013, and 2012.


(2)	Prices were based upon the average first day of the month prices for each month during the respective year.


(3)	The NGL price is provided only for 2014 and 2013 to coincide with our separate presentation of NGL reserves in those years.


(4)	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 at December 31, 2014:



	Net proved reserves as of December 31, 2014
	Oil (MBbls)	Natural gas (MMcf)	Natural gas liquids (MBbls)	Total (MBoe)	PV-10 value (in thousands)
Developed—producing	47,584	144,461	11,287	82,948	$	1,760,176
Developed—non-producing	7,278	13,804	500	10,079	139,814
Undeveloped	46,385	89,491	5,066	66,366	647,214
Total proved	101,247	247,756	16,853	159,393	$	2,547,204

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Proved Undeveloped Reserves. The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2014.



	MBoe
Proved undeveloped reserves as of January 1, 2014	57,811
Undeveloped reserves transferred to developed(1)	(4,566	)
Purchases of minerals	—
Sales of minerals in place	(5,474	)
Extensions and discoveries	13,421
Improved recoveries	13,176
Revisions and other	(8,002	)
Proved undeveloped reserves as of December 31, 2014(2)	66,366

____________


(1)	Approximately $144.1 million of developmental costs incurred during 2014 related to undeveloped reserves that were transferred to developed.


(2)	Includes 2.9 MMBoe of reserves that have been reported for more than five years that relate specifically to our Camrick Area CO₂ EOR projects. 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, 2014 by area. Productive wells consist of producing wells and wells capable of producing. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Gross wells is the total number of producing wells in which we have a working interest, and net wells is the sum of our working interest in all producing wells.

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	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Operated Wells:
E&P Areas
Mississippian	76	66	3	2	79	68
Panhandle Marmaton	69	59	—	—	69	59
Woodford Shale	1	1	—	—	1	1
Oswego	8	6	—	—	8	6
Legacy Production Areas	471	390	255	182	726	572
Total E&P Areas	625	522	258	184	883	706
Enhanced Oil Recovery Project Areas
Active EOR Projects	418	389	—	—	418	389
Potential EOR Projects	513	467	22	19	535	486
Total EOR Project Areas	931	856	22	19	953	875
Non-Core Properties	3	3	5	4	8	7
Total	1,559	1,381	285	207	1,844	1,588
Non-Operated Wells:
E&P Areas
Mississippian	104	14	2	1	106	15
Panhandle Marmaton	44	9	—	—	44	9
Woodford Shale	6	1	39	3	45	4
Oswego	—	—	—	—	—	—
Legacy Production Areas	925	39	918	103	1,843	142
Total E&P Areas	1,079	63	959	107	2,038	170
Enhanced Oil Recovery Project Areas
Active EOR Projects	93	5	—	—	93	5
Potential EOR Projects	353	66	—	—	353	66
Total EOR Project Areas	446	71	—	—	446	71
Non-Core Properties	—	—	1	—	1	—
Total	1,525	134	960	107	2,485	241
Total Wells:
E&P Areas
Mississippian	180	80	5	3	185	83
Panhandle Marmaton	113	68	—	—	113	68
Woodford Shale	7	2	39	3	46	5
Oswego	8	6	—	—	8	6
Legacy Production Areas	1,396	429	1,173	285	2,569	714
Total E&P Areas	1,704	585	1,217	291	2,921	876
Enhanced Oil Recovery Project Areas
Active EOR Projects	511	394	—	—	511	394
Potential EOR Projects	866	533	22	19	888	552
Total EOR Project Areas	1,377	927	22	19	1,399	946
Non-Core Properties	3	3	6	4	9	7
Total	3,084	1,515	1,245	314	4,329	1,829

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Drilling Activity

The following table sets forth information with respect to wells drilled and completed during the periods indicated. Development wells are wells drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return. As of December 31, 2014, we had nine (nine net) operated wells drilling, completing or awaiting completion.



	2014				2013				2012
	Gross		Net		Gross		Net		Gross		Net
Development wells
Productive	174.0		100.0		156.0		65.0		134.0		43.0
Dry	2.0		2.0		3.0		—		1.0		1.0
Exploratory wells
Productive	26.0		19.0		17.0		13.0		29.0		14.0
Dry	1.0		1.0		1.0		1.0		—		—
Total wells
Productive	200.0		119.0		173.0		78.0		163.0		57.0
Dry	3.0		3.0		4.0		1.0		1.0		1.0
Total	203.0		122.0		177.0		79.0		164.0		58.0
Percent productive	99	%	98	%	98	%	99	%	99	%	98	%

Developed and Undeveloped Acreage

The following table sets forth our gross and net interest in developed and undeveloped acreage at December 31, 2014 by state. This does not include acreage in which we hold only royalty interests.



	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
Oklahoma	498,647	272,418	191,945	133,562	690,592	405,980
Texas	84,749	50,955	29,453	27,195	114,202	78,150
Other	10,889	8,363	106	2	10,995	8,365
Total	594,285	331,736	221,504	160,759	815,789	492,495

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, 2014 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, 2015	81,887	55,429
December 31, 2016	79,564	61,034
December 31, 2017	56,375	41,567
December 31, 2018	80	224
Other (1)	—	4
Total	217,906	158,258

____________


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

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Of the total undeveloped acreage identified as expiring over the next three years, approximately 2,369 net acres have proved undeveloped reserves on location. These proved undeveloped reserves represent less than 1% of our overall proved undeveloped reserves. We anticipate using lease extensions and drilling to hold the leases associated with these 2,369 net acres. Less than 1% of the net acres of leasehold that were identified as attributable to proved undeveloped reserves and potentially expiring in 2014 actually expired. The remainder of such acreage was kept either through lease extensions or drilling.

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)	2014			2013			2012
Property acquisition costs
Proved properties	$	3,496		$	69,962		$	1,108
Unproved properties	84,938			145,853			46,895
Total acquisition costs	88,434			215,815			48,003
Development costs	561,578			376,394			409,429
Exploration costs(1)	90,146			77,507			54,432
Total	$	740,158		$	669,716		$	511,864
Annual reserve replacement ratio(2)	359		%	348		%	156		%

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(1)	Includes $0.2 million, $37.3 million, and $52.2 million of EOR costs in 2014, 2013, and 2012 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 15—Disclosures about oil and natural gas activities” 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,
	2014				2013				2012
	Reserves replaced		Percent of total		Reserves replaced		Percent of total		Reserves replaced		Percent of total
Purchases of minerals in place	5	%	1.2	%	51	%	14.6	%	1	%	0.1	%
Extensions and discoveries	233	%	65.0	%	257	%	74.0	%	146	%	94.0	%
Improved recoveries	121	%	33.8	%	40	%	11.4	%	9	%	5.9	%
Total	359	%	100.0	%	348	%	100.0	%	156	%	100.0	%

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Production and Price History

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



	Year ended December 31,
	2014		2013		2012
Production:
Oil (MBbls)	5,977		5,006		4,562
Natural gas (MMcf)	20,648		20,250		19,834
Natural gas liquids (MBbls)	1,564		1,361		1,250
Combined (MBoe)	10,982		9,742		9,118
Average daily production:
Oil (Bbls)	16,375		13,715		12,464
Natural gas (Mcf)	56,570		55,479		54,191
Natural gas liquids (MBbls)	4,285		3,729		3,415
Combined (Boe)	30,088		26,691		24,911
Average prices (excluding derivative settlements):
Oil (per Bbl)	$	90.50	$	95.08	$	90.87
Natural gas (per Mcf)	$	4.17	$	3.48	$	2.64
Natural gas liquids (MBbls)	$	34.86	$	33.19	$	34.05
Combined (per Boe)	$	62.06	$	60.73	$	55.88
Average costs per Boe:
Lease operating expenses	$	13.65	$	14.35	$	14.36
Production taxes	$	2.58	$	3.41	$	3.51
Depreciation, depletion, and amortization	$	22.39	$	19.75	$	18.57
General and administrative	$	4.86	$	5.53	$	5.46

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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 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)	2014			2013			2012
PV-10 value	$	2,547,204		$	2,349,656		$	2,068,620
Present value of future income tax discounted at 10%	(652,504		)	(605,884		)	(544,939		)
Standardized measure of discounted future net cash flows	$	1,894,700		$	1,743,772		$	1,523,681

Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our senior secured revolving credit facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. 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 (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedge reclassification adjustments, (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, and (9) impairment charges and other significant, unusual non-cash charges.

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The following table provides a reconciliation of net income to adjusted EBITDA for the specified periods:



	Year ended December 31, 2014
(in thousands)	2014			2013			2012
Net income	209,293			55,687			64,403
Interest expense	104,241			96,876			98,402
Income tax expense	124,443			32,849			37,837
Depreciation, depletion, and amortization	245,908			192,426			169,307
Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments	—			(37,134		)	(46,746		)
Non-cash change in fair value of non-hedge derivative instruments	(228,903		)	40,748			(12,411		)
Premiums paid on settled derivative contracts	(664		)	—			—
Interest income	(117		)	(254		)	(225		)
Stock-based compensation expense	3,172			4,933			3,065
Net gain on sale of assets	(2,152		)	(670		)	(149		)
Loss on extinguishment of debt	—			—			21,714
Loss on impairment of other assets	—			3,490			2,000
Adjusted EBITDA	$	455,221		$	388,951		$	337,197

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. 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.

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

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.

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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 U.S. 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 expensive 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;


•	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. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry 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 have a significant impact on our operating costs.

We 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, 2014, 2013 and 2012, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. 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 2015 or that will otherwise have a material impact on our financial position or results of operations.

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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 the U.S. Congress, 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 previously disposed substances and wastes, remediate contaminated property, 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 April 2014, EPA and the United States Army Corps of Engineers jointly proposed guidance regarding the definition of waters of the United States that could significantly expand the waters regulated under the Clean Water Act. 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.

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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 the casing is not leaking saltwater to groundwater. Because some states have become concerned that the disposal of produced water could, under certain circumstances, trigger or contribute to eartquakes, 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, 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 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 expects to release a draft assessment report for peer review and comment in early 2015. 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. These developments may result in additional levels of regulation or level of 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.

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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 New Source Performance Standards that, among other things, distinguish 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, in January 2015 the EPA announced a series of additional steps it plans to take to address methane and smog-forming emissions from the oil and gas industry and that it intends to issue a rule governing methane emissions from oil and gas sources in the summer of 2015. The BLM is also expected to address methane emissions from oil and gas sources on federal lands in the summer of 2015. These standards, as well as any future laws and their implementing regulations, may cause us to incur increased operating costs and additional capital expenditures related to, among other things: (a) pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, (b) imposition of stringent air permit requirements, or (c) installation of specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.

Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new 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 subjecting greenhouse gas to regulation 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. These regulations govern our operations to the extent applicable. 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 federal regulations on greenhouse gas and fugitive emissions come to deadline this year. This may result in additional permitting costs and additional equipment needed for operational activities that will increase the cost of production. The trend from EPA is to aggressively monitor and enforce these programs and fine at each incident to speed compliance, therefore any such non-compliance may result in additional production costs. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe we are in substantial compliance with the current requirements of the CAA.

Endangered Species

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. The U.S. Fish and Wildlife Service identified the Lesser Prairie Chicken, which inhabits portions of Colorado, Kansas, Nebraska, New Mexico, Oklahoma and Texas, as candidate for listing in 1998. 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

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[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”). “The rangewide plan identifies the ecoregional population goals . . . for the four ecoregions: the Shinnery Oak Prairie Region (eastern New Mexico and southwest Texas panhandle); the Sand Sagebrush Prairie Region (southeastern Colorado, southwestern Kansas, and western Oklahoma panhandle); the Mixed Grass Prairie Region (northeastern Texas panhandle, western Oklahoma, and south central Kansas); and the Short Grass/CRP Mosaic Region (northwestern Kansas).” 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.

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, and Congress is considering proposed legislation directed at reducing greenhouse gas emissions. Also, 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 restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, 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. The EPA has announced that it will propose new standards of performance limiting methane emissions from oil and natural gas sources in 2015. Operating costs for our operations could potentially 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. In addition to federal action, various states may consider enacting new legislation governing or restricting greenhouse gas emissions from oil and natural gas operations.

Other Regulation of the Oil and Natural Gas Industry

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

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

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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;


•	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 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.

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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.

CO₂Pipeline 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 CO₂from 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, 2014, we had 684 full-time employees, including 17 geologists and geophysicists, 57 reservoir, production, and drilling engineers and 19 land professionals. Of these, 380 work in our Oklahoma City office and 304 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.

On February 2, 2015, we began implementation of a workforce reduction plan as part of a Company-wide effort to decrease our capital, operating and administrative costs. The workforce reduction plan resulted in a total reduction of 180 employees, of which 121 were located in the Oklahoma City headquarters office and 59 were located at various field offices. See “Note 16—Subsequent Events” in Item 8. Financial Statements and Supplementary Data of this report for further discussion.

We believe that our relations with our employees are satisfactory.

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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.

Oil and gas price volatility, including the recent decline in oil and gas prices, could 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 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 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;


•	oil and natural gas 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 the Organization of Petroleum Exporting Countries 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, 2014, the posted price for West Texas Intermediate light sweet crude oil, commonly referred to as West Texas Intermediate or WTI, has ranged from a low of $53.45 per barrel, or Bbl, in December 2014 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 $1.82 per million British thermal units, or MMBtu, in April 2012 to a high of $8.15 per MMBtu in February 2014. Over the past several months, oil prices have declined from over $105.00 per Bbl in June 2014 to below $45.00 per Bbl in January 2015 due in large part to increasing supplies and weakening demand growth, and have remained low compared to prices in the first half of 2014.

Lower oil and natural gas prices for an extended period would not only reduce our revenue, but could reduce the amount of oil and natural gas we can produce economically, and as a result, could have a material adverse effect on our financial condition, results of operations, and reserves. We could also determine during periods of low commodity prices to shut in or curtail production from our wells and to defer drilling new wells challenging our ability to produce at commercially paying quantities required to hold our leases.

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 senior secured revolving credit facility and our senior notes, or be unable to make planned capital expenditures.

We expect to write down the carrying values of our properties in 2015 if oil and natural gas prices remain low, and further price declines could result in 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 gas reserves discounted at 10%,

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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.

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. Any such further write-downs could have a material adverse effect on our financial condition and results of operations. We did not have a ceiling test write-down in 2012, 2013 or 2014. Due to the substantial decline of commodity prices during the third and fourth quarters of 2014, which have remained low during the first quarter of 2015, we anticipate that we will have a ceiling test write-down during 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes.

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 oil and natural gas 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, 2014 reserve report used prices of $4.35 per Mcf for natural gas, $94.99 per Bbl for oil and $36.10 per Bbl for natural gas liquids. These prices are substantially higher than the current and expected 2015 prices for oil and natural gas.

A significant portion of total proved reserves as of December 31, 2014 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2014, approximately 42% 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 $0.8 billion during the five years ending in 2019. 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. We may be required to write off any reserves that are not developed within this five-year time frame unless such reported reserves are otherwise exempted from the SEC’s five-year reporting rules.

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.

Of our 57.5 million MMBoe of reserves on our active EOR properties as of December 31, 2014, 43.1 MMBoe were based on EOR methods including the injection of CO₂ and represent approximately 27% 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

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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, 2014, undeveloped reserves comprised 47% of the total estimated proved reserves of our active EOR projects. As of December 31, 2014, we expect to incur future development costs of $1.0 billion, including $306.0 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 60% of our total estimated future development and abandonment costs of $1.7 billion as of December 31, 2014. 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.

Competition in the oil and 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 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 42% of our total estimated proved reserves (by volume) at December 31, 2014 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, 2014 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 21%, 14%, and 12% 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

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dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves. Due to lower oil prices, we are significantly reducing capital expenditures in 2015 which will 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 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;


•	adverse weather conditions;


•	decline in commodity prices;


•	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, 2014, 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;


•	reporting on emissions of greenhouse gases;


•	permitting of emissions of greenhouse gases and other regulated air pollutants;


•	unitization and pooling of properties;


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


•	well stimulation processes;


•	produced water disposal;

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•	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;


•	other environmental damages; and


•	additional reporting, permitting or other issues arising from emissions of greenhouse gases and other regulated air pollutants;


•	and fines, penalties, and / or consent orders for non-compliance with the Clean Air Act.

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 Clean Air Act 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.

Properties that we acquire may not produce as projected and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties, or obtain protection from sellers against such liabilities.

Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves, exploration or development potential, future oil and natural gas prices, operating costs, and potential environmental and other liabilities. We perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices, and also endeavor to evaluate environmental risks. However, such assessments are inexact and their accuracy is inherently uncertain for a number of reasons. For instance, in connection with our assessments, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not physically inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited. Often we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities associated with acquired properties. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. Additionally, properties previously acquired have not been subject to greenhouse gas requirements which have recently been adopted. As a result, significant unknown liabilities, including environmental liabilities, may exist and we may experience losses due to title defects in acquisitions for which we have limited or no contractual remedies or insurance coverage. These risks are magnified during a period of lower oil prices like we are currently experiencing in the United States. In addition, we may acquire oil and natural gas properties that contain economically recoverable reserves which are less than predicted. Thus, liabilities and uneconomically feasible oil and natural gas recoveries related to our acquisitions of producing and undeveloped properties may have a material adverse effect on our results of operations and reserve growth.

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;

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•	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 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 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.

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 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 gas drilling and production operations can be hazardous and may expose us to environmental or other liabilities.

Oil and 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;


•	clean-up 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 clean up 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 clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, incur material clean up costs, other liabilities, and/

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or expend significant sums to defend ourselves against litigation related to legacy environmental issues, which could have an adverse effect on our operating results.

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 senior secured revolving 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 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 senior secured revolving 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.

If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result:


•	debt holders could declare all outstanding principal and interest to be due and payable;


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


•	the lenders under the senior secured revolving credit facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and


•	we could be forced into bankruptcy or liquidation.

Our level of indebtedness may adversely affect our operations and limit our growth.

As of December 31, 2014, our total long-term indebtedness, including current maturities, was $1.6 billion. As of March 31, 2015, our total long-term indebtedness, including current maturities, was approximately $1.7 billion, and the borrowing base under our senior secured revolving credit facility was $650.0 million. Effective April 1, 2015, the borrowing base under our senior secured revolving credit facility was reduced from $650.0 million to $550.0 million. The borrowing base is based part on oil, natural gas and NGL prices and the value of our reserves. Many considerations, including but not limited to a significant decline in prices, a significant increase in operating costs, a downward revision of reserves, or other factors, could decrease our borrowing base. We may incur additional indebtedness, including significant secured indebtedness, in order to make future acquisitions or to develop our properties for production or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future. Covenants set forth in the indentures for our senior notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and gas at specified dates.

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 senior secured revolving 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.

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

Availability under our senior secured revolving credit facility is subject to a borrowing base, which will be $550 million as of April 1, 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 senior secured revolving credit facility, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued, unless otherwise agreed to by our lenders. If the outstanding borrowings under our senior secured revolving 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. 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. Any such sale could have a material adverse effect on our business and financial 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, 2014, we had entered into commodity hedges covering 34,170 BBtu of our natural gas, 10,618 MBbls of our oil and natural gas liquids production for 2015 through 2016. Our commodity hedges are comprised of fixed price swaps, enhanced price swaps, basis protection swaps and three way collars. The volumes and average notional prices of these hedges are disclosed in “Note 6 -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, 2014 was an asset of approximately $251.6 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 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 us from 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 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 gas exploration and production industry; and


•	our tax burden due to new tax laws.

Assuming a constant debt level of $650.0 million, equal to our borrowing base at December 31, 2014 (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 $6.5 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 commodity sales, joint interest billings, or hedging with third parties could expose us to credit risk.

Substantially all of our accounts receivable result from commodity 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 gas to a limited number of customers, combined with decreases in commodity prices could result in adverse effects.

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.

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

The U.S. 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, federal legislation to reduce greenhouse gases appears uncertain. As a result, regulation of greenhouse gases will continue to result primarily from regulatory action by the Environmental Protection Agency (EPA) or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.

Federal regulation. EPA has adopted regulations requiring Clean Air Act (“CAA”) permitting of greenhouse gas emissions from stationary sources. 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,” the EPA was required to determine whether concentrations of greenhouse gases in the atmosphere “endanger” public health or welfare, and whether emissions of greenhouse gases from motor vehicles may “cause or contribute” to this endangerment. On December 15, 2009, EPA promulgated its final rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act”. On May 7, 2010, EPA and the Department of Transportation’s National Highway Traffic and Safety Administration, or NHTSA, promulgated a final action establishing a national program providing new standards for certain motor vehicles to reduce greenhouse gas emissions and improve fuel economy. While these motor vehicle regulations do not directly impact oil and gas production operations, they can automatically trigger application of the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs for stationary sources of greenhouse gas emissions, potentially including oil and gas production operations. On June 3, 2010, EPA promulgated its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” to add new higher thresholds of 75,000 tons per year carbon dioxide equivalents (“CO₂e”) for modifications to existing sources and 100,000 tons per year CO2e for new sources.

EPA has promulgated separate regulations requiring greenhouse gas emission reporting from certain industry sectors, including 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 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

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fractured gas wells completed or refractured after January 1, 2015. They also set new requirements for emissions from compressors, controllers, dehydraters, storage vessels and other affected production equipment.

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 potentially 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.

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 caselaw 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.

Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash flow from commodity 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 gas. Proposals have included, but have not been limited to, repealing the enhanced oil recovery 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 gas properties, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and gas companies, and increasing the amortization period of geological and geophysical expenses. In 2009, 2010, and 2011, 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 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 gas resources and (ii) could negatively affect our financial condition and results of operations.

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 included a workforce reduction of 121 employees in our headquarters office and the release of approximately 59 field personnel.

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 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.

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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. EPA expects to release a draft assessment report for peer review and comment in early 2015.

We conduct oil and natural gas exploration, development and drilling activities in Oklahoma and elsewhere. In recent years, Oklahoma has experienced a significant increase in earthquakes and other seismic activity. Some parties believe that there is a correlation between the operation of underground injection wells for the disposal of produced water and the increased occurrence of earthquakes. The extent of this correlation, if any, is the subject of studies by both state and federal agencies, the results of which remain uncertain.

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.

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 an

Chaparral Energy, Inc. - FORM 10-K - March 31, 2015

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