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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

 

 

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

For the fiscal year ended December 31, 2009

OR

 

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

For the transition period from              to             

Commission file no. 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)

Registrant’s telephone number, including area code:

(405) 478-8770

 

 

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  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  x    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  x

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

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

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

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

 

Large Accelerated Filer		¨		Accelerated Filer		¨
Non-Accelerated Filer		x		Smaller Reporting Company		¨

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

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

1,401,376 shares of the registrant’s common stock were outstanding as of April 14, 2010.

 

 

 

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CHAPARRAL ENERGY, INC.

Index to Form 10-K

 

Part I
Items 1. and 2.		Business and Properties		8
Item 1A.		Risk Factors		32
Item 1B.		Unresolved Staff Comments		43
Item 2.		Properties		43
Item 3.		Legal Proceedings		43
Item 4.		[Reserved]		43
Part II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		44
Item 6.		Selected Financial Data		45
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		46
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		69
Item 8.		Financial Statements and Supplementary Data		72
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		112
Item 9A.		Controls and Procedures		112
Item 9B.		Other Information		113
Part III
Item 10.		Directors, Executive Officers and Corporate Governance		113
Item 11.		Executive Compensation		115
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		131
Item 13.		Certain Relationships and Related Transactions, and Director Independence		132
Item 14.		Principal Accounting Fees and Services		135
Part IV
Item 15.		Exhibits and Financial Statement Schedules		136
Signatures				139

 

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CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

The statements contained in this report that are not purely historical are forward-looking statements. The forward-looking statements include, but are not limited to, statements regarding our expectations, hopes, beliefs, intentions or strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions, are forward-looking statements. The words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “possible,” “potential,” “predict,” “project,” “should,” “would” and similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements in this report may include, for example, statements about:

 

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

 

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the amount, nature and timing of capital expenditures;

 

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drilling of wells;

 

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competition and government regulations;

 

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

 

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

 

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increases in proved reserves;

 

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operating costs and other expenses;

 

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cash flow and anticipated liquidity;

 

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estimates of proved reserves;

 

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exploitation of property acquisitions; and

 

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marketing of oil and natural gas.

The forward-looking statements contained in this report are based on our current expectations and beliefs concerning future developments and their potential effects. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) and other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties include those factors described under the heading “Risk Factors.” Specifically, some factors that could cause actual results to differ include:

 

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the significant amount of our debt;

 

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worldwide demand for oil and natural gas;

 

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volatility and declines in oil and natural gas prices;

 

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drilling plans (including scheduled and budgeted wells);

 

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the number, timing or results of any wells;

 

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changes in wells operated and in reserve estimates;

 

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future growth and expansion;

 

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future exploration;

 

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integration of existing and new technologies into operations;

 

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

 

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borrowings and capital resources and liquidity;

 

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changes in strategy and business discipline;

 

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future tax matters;

 

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any loss of key personnel;

 

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future seismic data (including timing and results);

 

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

 

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geopolitical events affecting oil and natural gas prices;

 

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outcome, effects or timing of legal proceedings;

 

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the effect of litigation and contingencies; and

 

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the ability to generate additional prospects.

 

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Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. 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 Form 10-K:

 

Bbl		One stock tank barrel, of 42 U.S. gallons liquid volume, 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.
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.
Basin		A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Boe		Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.
Enhanced oil recovery (EOR)		The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after secondary recovery.
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.
Henry Hub spot price		The price of natural gas, in dollars per MMbtu, being traded at the Henry Hub in Louisiana in transactions for next-day delivery, measured downstream from the wellhead after the natural gas liquids have been removed and a transportation cost has been incurred.
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.

 

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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.
NYMEX		The New York Mercantile Exchange.
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.
Net working interest		A working interest owner’s gross working interest in production, less the related royalty, overriding royalty, production payment, and net profits interests.
PDP		Proved developed producing.
Play		A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and gas reserves.
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 and abandonment 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% in accordance with the guidelines of the Securities and Exchange Commission.
Primary recovery		The period of production in which oil moves from its reservoir through the wellbore under naturally occurring reservoir pressure.
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 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.
Sand		A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogeneous to differentiate it from other formations.

 

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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.
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.
WTI Cushing spot price		The price of West Texas Intermediate grade crude oil, in dollars per barrel, in transactions for immediate delivery at Cushing, Oklahoma.
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”, “we”, “our”, “ours” 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

We are an independent oil and natural gas company engaged in the production, exploitation, and acquisition of oil and natural gas properties. Our core areas of operation include the Mid-Continent and Permian Basin with additional operations in the Gulf Coast, Ark-La-Tex, North Texas, and the Rocky Mountains. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and enhanced oil recovery (EOR) projects.

On April 12, 2010, we sold 475,043 shares of our common stock to CCMP Capital investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”) for a purchase price of $325.0 million. In connection with the closing of the sale, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. As of April 14, 2010, we had $275.3 million of availability under our Eight Restated Credit Agreement. See Note 14 to our consolidated financial statements for additional information regarding these transactions.

As of December 31, 2009, based on SEC pricing as defined below, we had estimated proved reserves of 141.9 MMBoe with a PV-10 value of approximately $1.3 billion. Our reserves were 66% proved developed and 63% crude oil. For the year ended December 31, 2009, our average daily production was 20.9 MBoe with an estimated reserve life of 19 years, and our oil and natural gas revenues were $292.4 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 24.

Our reserve estimates as of December 31, 2009 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’s Modernization of Oil and Gas Reporting. Our reserve estimates prior to December 31, 2009 were prepared using the spot price for oil and gas on the last day of the reporting period. If our reserves had been prepared based on the guidelines in effect prior to December 31, 2009, including spot prices on the last day of the reporting period of $79.36 per Bbl of oil and $5.79 per Mcf of natural gas at December 31, 2009, our estimated proved reserves would have been approximately 160.7 MMBoe with a PV-10 value of approximately $2.2 billion.

From 2003 to 2009, our proved reserves and production grew at a compounded annual growth rate of 19% and 20%, respectively. During this period, we have grown primarily through a combination of developmental drilling and a disciplined strategy of acquiring proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We typically pursue properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. In 1993, we began acquiring properties with CO₂ EOR potential. To date, over 72 of these properties have been acquired and CO₂ injection operations have been initiated in ten of these units. In 2005 and 2006, we completed two larger acquisitions of $152.9 million and $480.5 million of oil and natural gas properties which contained substantial CO₂ EOR potential and complemented our existing property base. We currently expect our future growth to continue through a combination of developmental drilling, exploitation projects, and acquisitions, complemented by a modest amount of exploration activities.

For the year ended December 31, 2009, we made capital expenditures for oil and natural gas properties of $150.9 million, including $77.8 million for developmental drilling and $18.3 million for acquisitions. The majority of our capital expenditures for developmental drilling in 2009 were allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower-risk. We have budgeted $268.0 million for capital expenditures for oil and natural gas properties in 2010.

Business Strengths

Consistent track record of reserve additions and production growth. From 2003 to 2009, we have grown proved reserves and production by a compounded annual growth rate of 19% and 20%, respectively. We have achieved this through a combination of drilling and acquisition success. A number of high impact wells that we expect will support our production throughout 2010 are currently being drilled and should be completed and on line during the first and second quarters of 2010. Six of these wells are located in the Texas Panhandle Atoka Wash and one is located in the Haley Area of Loving County, Texas. However, we cannot accurately predict the timing or level of future production.

Our reserve replacement ratio, which reflects our reserve additions from acquisitions, extensions and discoveries, and improved recoveries in a given period stated as a percentage of our production in the same period, has averaged 514% per year since 2002. We replaced approximately 243%, 200%, and 372% of our production in 2009, 2008, and 2007, respectively.

 

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Disciplined approach to proved reserve acquisitions. We have a dedicated team that analyzes all of our acquisition opportunities. This team conducts due diligence with reserve engineering on a well-by-well basis to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2009, 2008 and 2007, our capital expenditures for acquisitions of proved properties were $14.6 million, $39.2 million, and $41.7 million, respectively. These acquisition capital expenditures represented approximately 10%, 13%, and 18%, respectively, of our total capital expenditures and approximately 4%, 17%, and 13%, respectively, of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for those periods. We have budgeted $20.0 million, or 7% of our total capital expenditures, for acquisitions in 2010.

Property enhancement expertise. Our ability to enhance acquired properties allows us to increase their production rates and economic value. Our typical enhancements include the repair or replacement of casing and tubing, installation of plunger lifts and pumping units, installation of coiled tubing or siphon strings, compression, workovers and recompletion to new zones. Minimal amounts of investment have significantly enhanced the value of many of our properties.

Inventory of drilling locations. Based on SEC pricing for the year ended December 31, 2009 of $61.18 per Bbl of oil and $3.87 per Mcf of natural gas, we had an inventory of 1,333 proved undeveloped drilling locations.

 

		Identified proved undeveloped drilling locations
Mid-Continent		1,061
Permian Basin		47
Gulf Coast		7
Ark-La-Tex		3
North Texas		128
Rocky Mountains		87
Total		1,333

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. 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. We have experienced a high historical drilling success rate of approximately 99% on a weighted average basis during 2009, 2008 and 2007. For the year ended December 31, 2009, we spent $82.8 million of developmental drilling and exploration costs to drill 51 (48 net) operated wells and to participate in 121 (4 net) wells operated by others, representing 80% of our additions to reserves. For 2010, we have budgeted $173.0 for developmental and exploratory drilling.

 

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Enhanced oil recovery expertise and asset. Beginning in 2000, we expanded our operations to include CO₂ EOR. CO₂ EOR involves the injection of CO₂, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of eight engineers that have substantial expertise in CO₂ EOR operations, and we also have specific software for modeling these projects. We own a 29% interest in and operate a large CO₂ EOR unit in southern Oklahoma and have installed and operate a second CO₂ EOR unit with a 54% interest in the Oklahoma and Texas panhandles. We began CO₂ injection in our Perryton Unit in December 2006 and in our Booker Area Units in September 2009, and plan to initiate CO₂ injection in our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. At December 31, 2009, our proved reserves included nine units where CO₂ EOR recovery methods are used, representing approximately 7% of our total proved reserves. In addition, we operate a polymer EOR flood in the North Burbank unit. This unit is in the early phases of a polymer EOR flood which was proven up by Phillips Petroleum Company through a pilot program in the early 1980’s before being shut down due to low prevailing oil prices at that time. We initiated polymer injection in this unit in a pilot program in December 2007. In the pilot area, we are seeing production response as production has increased from 90 Bbls of oil per day to 160 Bbls of oil per day. We plan to expand this polymer EOR program and introduce CO₂ injection into this unit after acquiring a source of CO ₂ in this area.

Experienced management team. Mark A. Fischer, our Chief Executive Officer and founder, has operated in the oil and natural gas industry for 38 years after starting his career at Exxon Mobil Corporation as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 30 years of experience in the oil and natural gas industry. Individuals in our 23-person management team have an average of nearly 30 years of experience in the oil and natural gas industry.

Business Strategy

We seek to grow reserves and production profitably through a balanced mix of developmental drilling, enhancements, acquisitions, EOR projects, and a modest number of exploration projects. Further, we strive to control our operations and costs and to minimize commodity price risk through a conservative financial hedging program. The principal elements of our strategy include:

Continue lower-risk developmental drilling program. During the year ended December 31, 2009, we spent approximately $77.8 million on development drilling, which represents 52% of our capital expenditures for such period. A majority of these drilling wells are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally infill or single stepout wells, which are characterized as lower risk. We currently plan to spend a total of approximately $163.0 million, or approximately 61% of our capital expenditures, on developmental drilling in 2010.

Acquire long-lived properties with enhancement opportunities. We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. During the year ended December 31, 2009, we made approximately $14.6 million of proved reserve acquisitions, or 10% of our total capital expenditures. We have budgeted $20.0 million, or 7% of our total capital expenditures, for acquisitions in 2010.

Apply technical expertise to enhance mature properties. Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built our business around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 21 field offices in Oklahoma, Texas and Kansas. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor, as well as returning inactive wells to production by repairing various mechanical problems. As of December 31, 2009, our reserve report included 840 shut-in and behind-pipe enhancement projects requiring total estimated capital expenditures of $69.6 million over the life of the reserves.

 

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Expand CO₂ EOR activities. As of December 31, 2009, we have accumulated interests in 72 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria for CO₂ EOR operations, and are expanding our CO₂ pipeline system to initiate CO₂ injection in certain of these properties. We began CO ₂ injection in our Perryton Unit in December 2006 and in our Booker Area Units in September 2009, and plan to initiate CO₂ injection in our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. To support our existing CO₂ EOR projects, we currently inject approximately 50 MMcf per day of purchased and recycled CO₂ and have developed a CO ₂ pipeline infrastructure system with ownership interests in over 374 miles of CO₂ pipelines. This consists of a 100% ownership interest in our 86-mile Borger CO₂ pipeline, a 29% interest in the 120-mile Enid to Purdy CO₂ pipeline, a 58% interest in the 23-mile Purdy to Velma CO₂ pipeline, which we operate, and a 100% interest in the 126-mile Booker CO2 pipeline. Most of our injected CO₂ is anthropogenic (man-made) CO₂ which we capture from three different sources. We recently installed compression and purification facilities, on which we have applied for a patent, that are currently capturing approximately eight to ten MMcf per day of CO₂ from the Arkalon ethanol plant in Liberal, Kansas. We began injecting CO₂ captured from this plant into the Booker Area fields in the third quarter of 2009. After the completion of additional work, we expect these facilities to capture approximately 15 to 19 MMcf per day of CO₂.

Pursue modest exploration program. During the year ended December 31, 2009, we spent $5.0 million on exploration activities. We have budgeted $10.0 million for exploration activities in 2010.

Control operations and costs. 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, 2009, we operated properties comprising approximately 86% of our proved reserves.

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, for capital investments, and to lock in returns on acquisitions, we enter into commodity price swaps, costless collars, and basis protection swaps. We consider all these derivative instruments to be economic hedges of our proved developed production, regardless of whether hedge accounting is applied. As of December 31, 2009, we had commodity price swaps and costless collars in place for approximately 77% and 73%, respectively of our most recent internally estimated proved developed oil and natural gas production for 2010 through 2011. For the year ended December 31, 2009, we received net derivative settlements of $157.9 million. While our derivative activities protect our cash flows during periods of commodity price declines, we paid net derivative settlements of $51.6 million and $20.5 million for the years ended December 31, 2008 and 2007, respectively, through a period of increasing commodity prices.

During the fourth quarter of 2008, we monetized oil and natural gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. During the first quarter of 2009, we monetized additional natural gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. During the second quarter of 2009, we monetized additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. The proceeds from these monetizations are included in the net settlements described above.

 

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Properties

The following table presents our proved reserves and PV-10 value as of December 31, 2009 and average daily production for the year ended December 31, 2009, by our areas of operation. Reserves as of December 31, 2009 were estimated using SEC pricing, which was $61.18 per Bbl of oil and $3.87 per Mcf of gas.

 

		Proved reserves as of December 31, 2009												Average daily production (MBoe per day) Year ended December 31, 2009
		Oil (MBbl)		Natural gas (MMcf)		Total (MBoe)		Percent of total MBoe			PV-10 value ($MM)
Mid-Continent		76,837		208,590		111,602		78.7	%		$	1,045.0		13.7
Permian Basin		6,687		56,898		16,170		11.4	%			148.8		4.4
Gulf Coast		1,785		30,300		6,835		4.8	%			57.3		1.3
Ark-La-Tex		1,002		10,140		2,692		1.9	%			22.4		0.7
North Texas		1,844		3,366		2,405		1.7	%			30.9		0.4
Rocky Mountains		1,314		5,136		2,170		1.5	%			19.1		0.4
Total		89,469		314,430		141,874		100.0	%		$	1,323.5		20.9

Our properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and natural gas properties is geographically diversified, 87% of our 2009 production was concentrated in our two core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2009, we owned interests in 8,174 gross (2,807 net) producing wells and we operated wells representing approximately 86% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.

Mid-Continent

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2009, accounted for 79% of our proved reserves and 79% of our PV-10 value. We own a working interest in 5,392 producing wells in the Mid-Continent Area, of which we operate 2,100. The Mid-Continent Area has nine of our top ten largest plays in terms of PV-10 value. During the year ended December 31, 2009, our net average daily production in the Mid-Continent Area was approximately 13.7 MBoe per day, or 66% of our total net average daily production. This area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the basins in the region and have significant holdings and activity in the areas described below.

 

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North Burbank Unit—Osage County, Oklahoma. The North Burbank Unit is our largest property. The unit was developed in the early 1920’s, is 23,080 acres in size and has cumulative production of approximately 317.1 MMBbls of oil (primary and secondary). The North Burbank Unit accounted for 27.2 MMBoe of our proved reserves and $187.1 million of our PV-10 value as of December 31, 2009, and 566 (492 net) MBoe of our production for the year ended December 31, 2009. The producing zones are the Red Fork and Bartlesville and occur at a depth of 3,000 feet. We own a 99% working interest in and are also the operator of this unit. As of December 31, 2009, the field was producing approximately 1,531 (1,330 net) Bbls of oil per day from 285 producing wells. There are also 201 active service wells and 469 temporarily abandoned wells at December 31, 2009. Upside potential exists in restoring a majority of the temporarily abandoned wells to production and in reinstituting the polymer EOR program that Phillips Petroleum Company instituted in the field from 1980 to 1986 as a project on 1,440 acres called “Block A.” Production increased from 500 Bbls of oil per day to 1,200 Bbls of oil per day in this project area as a result of the polymer injection program. The project was shut down in 1986 due to low oil prices. We reinstituted a polymer flood on 485 acres adjacent to Block A on a 19-well pattern in December 2007. Production has increased in this pilot area from approximately 90 Bbls of oil per day to approximately 160 Bbls of oil per day as of December 31, 2009. Since taking over the field on November 1, 2006, we have returned 99 temporarily abandoned wells to production with initial rates of production as high as 29 Bbls of oil per day. We believe that this field also may have upside with the injection of CO₂.

Osage-Creek Area—Osage and Creek Counties, Oklahoma. The Osage-Creek area accounted for 16.2 MMBoe of our proved reserves and $228.1 million of our PV-10 value at December 31, 2009, and 846 (625 net) MBoe of our production for the year ended December 31, 2009. The majority of our recent activity has been in Osage County, with the largest portion of that being in our South Burbank Unit.

The South Burbank Unit is the southward extension of the “Stanley Stringer” sand development and lies to the south of the North Burbank Unit and covers 2,720 acres. It was discovered in 1934 and unitized in 1935. The South Burbank Unit has produced 56.9 MMBbls of oil from the Burbank Sand from both primary and secondary recovery efforts. The Burbank Sand occurs at a depth of 2,850 feet. Recently, we have been drilling infill and stepout locations in the unit area for both the Mississippi Chat, which occurs some 50 feet below the Burbank Sand, and to the Burbank Sand. It is currently estimated that the Mississippi Chat may be productive under a significant portion of the southern half of the South Burbank Unit. Seventeen wells have been drilled in the South Burbank Unit in 2009. Ten wells have been completed in the Burbank Sand with initial potentials ranging between 5 and 150 Bbls of oil per day. Seven wells are completed and produce from the Mississippi Chat with initial potentials as high as 210 Bbls of oil per day and 100 Mcf of gas per day. Any well drilled inside the South Burbank Unit is being developed with a pattern and spacing plan that will maximize any future EOR efforts.

Numerous other properties throughout Osage and Creek Counties are held by production and hold significant upside development potential. Recent new drilling activity outside of the South Burbank Unit has focused on the Mississippi Chat and Burbank reservoirs. We currently have a Company-owned drilling rig working full time in this area. Many of our Osage County units in which we have a large working interest also hold promise for future EOR efforts.

 

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Camrick Area—Beaver and Texas Counties, Oklahoma and Ochiltree County, Texas. The Camrick area accounted for 7.8 MMBoe of our proved reserves and $89.7 million of our PV-10 value at December 31, 2009. This area consists of three unitized fields, the Camrick Unit, which covers 9,168 acres, the NW Camrick Unit, which covers 2,980 acres and the Perryton Unit, which covers 2,508 acres. We currently operate these three units with an average working interest of 54%. Production in the Camrick area is from the Morrow reservoir that occurs between the depths of 6,900 and 7,500 feet. The three units have produced approximately 16.6 MMBbls of primary reserves and approximately 13.6 MMBbls of secondary reserves. There were 55 active producing wells in this area that produced 507 (249 net) MBbls during the year ended December 31, 2009. Currently, CO₂ injection operations are continuing in the Phase I, II and III areas of the Camrick Unit and the Perryton Unit. CO₂ injection has improved the gross production in the Camrick Area from approximately 115 Bbls of oil per day in 2001 from 11 wells to approximately 1,443 (710 net) Bbls of oil per day from 55 producing wells as of December 31, 2009. We plan to continue expansion of CO₂ injection operations across all of the units.

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma. SWAGSU accounted for 5.5 MMBoe of our proved reserves and $47.4 million of our PV-10 value at December 31, 2009, and 423 (368 net) MBoe of our production for the year ended December 31, 2009. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 40.3 MMBbls of oil and 262.5 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1965, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have 37 active producing wells in this unit as of December 31, 2009. We drilled one well in this area in 2009.

Sycamore Unit—Carter County, Oklahoma. The Sycamore Unit, which is 2,120 acres, was discovered in 1950 and unitized in 1973. A three stage development of the Sycamore Unit began in 1975 and was completed in 1992. This unit accounted for 2.8 MMBoe of our proved reserves and $40.9 million of our PV-10 value at December 31, 2009, and 243 (158 net) MBoe of our production for the year ended December 31, 2009. We operate this unit with a working interest of approximately 76%. Producing zones include the Deese and Sycamore, which occur at depths between approximately 2,500 and 4,900 feet. Cumulative production is 11.0 MMBbls of oil and, as of December 31, 2009, the unit has 107 producing wells and 44 active service wells. The unit is currently producing approximately 560 (363 net) Bbls of oil per day.

Cleveland Sand Area—Ellis, Custer, and Dewey Counties, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Area accounted for 4.9 MMBoe of our proved reserves and $38.7 million of our PV-10 value as of December 31, 2009, and 439 (242 net) MBoe of our production for the year ended December 31, 2009. This area includes the West Shattuck Cleveland Sand Play and the Aledo Bray Cleveland Sand Play.

We own approximately 6,864 net acres in the West Shattuck Cleveland Sand Play, which is located in Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand occurs at depths between 7,900 and 8,300 feet and is considered a tight gas sand reservoir. As of December 31, 2009, we own interests in 27 Cleveland Sand producing wells. We participated in the drilling of one well in 2009. We employed horizontal drilling technology in most of our drilled wells in this area.

We own approximately 2,135 net acres in the Aledo Bray Cleveland Sand Play, which is located in Custer and Dewey Counties, Oklahoma. The Cleveland Sand occurs at 9,700 feet and is considered a tight gas sand reservoir. As of December 31, 2009, we own interests in two Aledo Bray vertical producing wells. We drilled one horizontal well in this play during 2009.

 

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Granite Wash and Atoka Wash Areas—Washita County, Oklahoma and Wheeler County, Texas. The Granite Wash and Atoka Wash Areas accounted for 2.9 MMBoe of our proved reserves and $27.4 million of our PV-10 value as of December 31, 2009, and 781 (238 net) MBoe of our production for the year ended December 31, 2009. We have ongoing drilling activity in both these play areas.

The objective target of the Colony Granite Wash Horizontal Play, which is in Washita County, Oklahoma, is the Des Moinesian Granite Wash zones at an average depth of approximately 12,500 feet. To date, this play has encompassed an area approximately three townships in size. The Granite Wash is a quartz rich alluvial wash containing high concentrations of feldspar that results in reducing permeability and therefore reducing ultimate recoveries. Conventional vertical well bores in this area have recovered on average approximately 1.5 Bcfe. The technological advances of horizontal drilling allow maximum exposure of this tight gas filled reservoir to the well bore (most horizontal wells are drilled up to 4,800 feet horizontally in the Granite Wash), resulting in substantially improved recoveries that are currently estimated to be up to three to four times the recoveries of the typical vertical well in this play. We drilled and/or participated in the drilling of seven Colony Granite Wash wells in 2009.

The objective target of the Granite Wash and Atoka Wash Play, which is in Wheeler County, Texas, is the Des Moinesian Granite Wash and Atoka Wash zones at average depths ranging from approximately 12,600 feet to 14,500 feet. To date, this play has encompassed an area approximately two townships in size. The Granite Wash is a quartz rich alluvial wash containing high concentrations of feldspar that results in reducing permeability and therefore reducing ultimate recoveries. Conventional vertical well bores in this area have recovered on average approximately 1.5 Bcfe. The early Atoka Granite Wash is typically a carbonate wash sourced from the carbonates of the Wichita/Amarillo Uplift. The later Atoka Wash as found in the Britt area is an Arkosic wash with quartz with potassium and sodium feldspars. Other minerals present are calcite, dolomite, illite, and chlorite. The Britt Atoka Wash is producing a dryer gas with less condensate then the younger Des Moines Wash. The technological advances of horizontal drilling allow maximum exposure of this tight gas filled reservoir to the well bore (most horizontal wells utilize a lateral drilled up to 4,800 feet horizontally in the Granite Wash and Atoka Wash), resulting in substantially improved recoveries that are currently estimated to be up to three to four times the recoveries of the typical vertical well in this play. We participated in the drilling of six Atoka Wash wells in 2009. All of these wells were completed during the first quarter of 2010 and had initial producing rates of between 15 and 23 MMcf of gas per day.

Anadarko Basin Woodford Shale Play-Western Oklahoma. As of December 31, 2009, we have a significant acreage position in the emerging Woodford Shale Resource Play of western Oklahoma. We own and control approximately 68,780 gross acres and 22,270 net acres, which primarily are held by production from other formations. The Woodford Shale beneath our acreage ranges in thickness from approximately 80 to 280 feet thick at depths from 9,500 feet to 16,000 feet. The horizontal development of this non-conventional resource play began in 2007 in Canadian County and has expanded to include the nearby counties of Blaine, Grady and Caddo with approximately 100 Woodford targeted wells drilled to date. Natural gas in place is estimated to be between 120 to 160 Bcf per section with initial development well density to be four wells per section. The average recovery is expected to be four to six Bcf per well at an average cost of seven to nine million dollars. We participated in the drilling of two wells in this play during 2009, and an additional well in which we own a working interest was completed in the first quarter of 2010. These wells have reported initial daily production rates in the range of one to seven MMcf of natural gas per day per well.

 

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Velma Sims Unit CO₂ Flood—Stephens County, Oklahoma. The EVWB Sims Sand Unit accounted for 1.9 MMBoe of our proved reserves and $16.0 million of our PV-10 value as of December 31, 2009, and 342 (88 net) MBoe of our production for the year ended December 31, 2009. This unit, which covers approximately 1,300 acres, was discovered in 1949 and unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. Waterflood operations began in 1972. Hydrocarbon gas injection ended around 1977 and a miscible CO ₂ injection program was initiated in 1982. This miscible CO₂ injection was first begun in the updip portion of the reservoir and in 1990 expanded into the mid-section area of the Sims C2 reservoir. In 1996, miscible CO₂ injection began in the downdip section of the Sims C2. As of December 31, 2009, we had 43 active producing wells in this unit.

Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit, which is 2,335 acres, was discovered in 1915 and unitized in 1977. This unit accounted for 4.7 MMBoe of our proved reserves and $39.8 million of our PV-10 value at December 31, 2009, and 138 (94 net) MBoe of our production for the year ended December 31, 2009. We operate this unit with a working interest of 82%. Producing zones include the Deese, Sims, and Morris, which occur at depths between 3,300 and 5,500 feet. Cumulative production is 12.6 MMBbls of oil and, as of December 31, 2009, the unit has 62 producing wells and 48 active service wells. The unit is currently producing approximately 330 (224 net) Bbls of oil per day.

Sivells Bend Unit—Cooke County, Texas. The Sivells Bend Unit is 3,863 acres in size, produces primarily from the Strawn, which occurs at depths between 6,200 and 7,000 feet, and has recovered 39.4 MMBbls of oil to date. This unit accounted for 2.6 MMBoe of our proved reserves and $35.9 million of our PV-10 value at December 31, 2009, and 83 (48 net) MBoe of our production for the year ended December 31, 2009. There are currently 26 producing wells and 14 active service wells, with production of approximately 218 (126 net) Bbls of oil per day. We operate the field with a working interest of 65%. Upside potential exists in increased density drilling from 80 acres to 40 acres in the Strawn. The only 40-acre increased density well drilled in the unit has recovered over 390 MBbls of oil. Additional potential exists in deeper Ellenburger, as an Ellenburger well tested approximately 193 Bbls of oil per day in 1964 in the adjacent East Sivells Bend Unit, and one well in our unit tested 104 Bbls of oil per day for a short time. 3-D seismic will be required to better define the fault blocks for an Ellenburger test. We own approximately 1,000 acres of fee minerals in this Sivells Bend Unit and own approximately half of the rights below the Strawn, which includes the Ellenburger.

CO₂ EOR—Various counties, Oklahoma, Kansas, New Mexico and Texas.  As of December 31, 2009, we have accumulated interests in 72 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria for CO₂ EOR operations. These CO₂ EOR projects accounted for 6.2 MMBoe of our proved reserves and $80.2 million of our PV-10 value as of December 31, 2009, and 1,512 (449 net) MBoe of our production for the year ended December 31, 2009. We own a 100% interest in our 86-mile Borger CO₂ pipeline, a 29% interest in the 120-mile Enid to Purdy CO ₂ pipeline, a 58% interest in the 23-mile Purdy to Velma CO ₂ pipeline, which we operate, and a 100% interest in approximately 126 miles of pipeline that includes a CO₂ pipeline located between Liberal, Kansas and Booker, Texas as well as additional pipeline extensions in the SW Kansas and Texas Panhandle areas. We initiated CO₂ injection in three Booker units in 2009, and plan to expand CO₂ injections into our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. As of December 31, 2009, we had in place transportation and supply agreements to provide the necessary CO₂ for these projects. We have installed compression and purification facilities that are currently capturing approximately eight to ten MMcf per day of CO₂ from the Arkalon ethanol plant in Liberal, Kansas. We initiated injection of CO₂ captured from this facility into the Booker area fields in the third quarter of 2009. After the completion of additional work, we expect these facilities to capture approximately 15 to 19 MMcf per day of CO₂.

Arrangements to secure additional sources of CO₂ for potential future projects are currently in process. The U.S. Department of Energy-Office of Fossil Energy provided a report in February 2006 estimating that significant oil reserves could be technically recovered in the State of Oklahoma through CO₂ EOR processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of these reserves.

 

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Permian Basin

The Permian Basin Area is the second of our two core areas and, as of December 31, 2009, accounted for 11% of our proved reserves and 11% of our PV-10 value. We own a working interest in 1,693 producing wells in the Permian Basin, of which we operate 318. The Permian Basin Area has one of our top ten plays in terms of PV-10 value. During the year ended December 31, 2009, our net average daily production in the Permian Basin Area was approximately 4.4 MBoe per day, or 21% of our total net average daily production. Similar to the Mid-Continent Area, the Permian Basin Area is characterized by stable, long-life, shallow decline reserves.

Tunstill Field Play—Loving and Reeves Counties, Texas. Our Tunstill Field Play covers approximately 20,440 acres. We operate 86 producing wells in this play with an average working interest of 99%, and own a working interest in 120 producing wells operated by others. The Tunstill Field Play represented 2.7 MMBoe of our proved reserves and $33.6 million of our PV-10 value at December 31, 2009, and 252 (179 net) MBoe of our production for the year ended December 31, 2009. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,200 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,200 to 5,400 feet. Older wells produce from the shallower Bell Canyon Sands including the Ramsey and Olds, while more recent wells have established production from the deeper Cherry Canyon Sands as well as the shallower sands. We drilled three wells in this play during the year ended December 31, 2009.

Haley Area Play—Loving County, Texas. The Haley Area—Bone Springs, Strawn, Atoka, and Morrow play encompasses 3,840 gross acres. We own interests in and operate ten producing wells in this play. The Haley Area accounted for 4.7 MMBoe of our proved reserves and $27.7 million of our PV-10 value at December 31, 2009, and 1,163 (805 net) MBoe of our production for the year ended December 31, 2009. Production has been established from four main intervals: (1) the Bone Springs at a depth of approximately 9,800 to 11,500 feet; (2) the Strawn at a depth of approximately 15,000 feet; (3) the Atoka at a depth of approximately 15,300 feet; and (4) the Morrow at a depth of approximately 17,500 feet. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Strawn/Atoka/Morrow commingled interval with some initial potentials of 3 to 5 MBoe per day. The Bowdle 47 No. 2 began selling natural gas in late November 2008, and is currently producing at approximately 12.0 (8.7 net) MMcf per day. We are currently drilling an offset to the Bowdle 47 No. 2 well, the Bowdle 47 No. 4, which is expected to be completed in the second quarter of 2010.

Gulf Coast

The Gulf Coast Area is the most active of our four growth areas and accounted for 5% of our proved reserves and 4% of our PV-10 value as of December 31, 2009, and 6% of our production for the year ended December 31, 2009. We own an interest in 200 wells in the Gulf Coast Area, of which we operate 128. Unlike our core areas, the Gulf Coast Area is characterized by shorter-life and high initial potential production. We believe a balance of this type of production complements our long-life reserves and adds a dimension for increasing our near-term cash flow.

Mustang Island & Mesquite Bay—Aransas and Nueces Counties, TX. We own interests in approximately 1,700 net producing acres and 10,650 net non-producing acres. Multiple producing sand intervals are found from depths of 6,500 feet to 11,500 feet. We operate seven active producing wells in this area. As of December 31, 2009, this area accounted for 1.3 MMBoe of our proved reserves and $14.2 million of our PV-10 value. We recorded a 58-square mile proprietary 3-D seismic survey over parts of this area where we have entered into an area of mutual interest with a 50% ownership in an attempt to find bypassed reserves or other potential reservoirs. We drilled one Mustang Island well in 2009.

 

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Ark-La-Tex

The Ark-La-Tex Area accounted for 2% of our proved reserves and 2% of our PV-10 value as of December 31, 2009, and 3% of our production for the year ended December 31, 2009. We own an interest in 120 wells in the Ark-La-Tex Area, of which we operate 53. These reserves are characterized by shorter life and higher initial potential. We participated in the drilling of one Ark-La-Tex well in 2009.

North Texas

The North Texas Area accounted for 2% of our proved reserves and 2% of our PV-10 value as of December 31, 2009, and 2% of our production for the year ended December 31, 2009. We own an interest in 588 wells in the North Texas Area, of which we operate 107. We participated in the drilling of 81 North Texas wells in 2009.

Rocky Mountains

The Rocky Mountains Area accounted for 1% of our proved reserves and 2% of our PV-10 value as of December 31, 2009, and 2% of our production for the year ended December 31, 2009. We own an interest in 181 wells in the Rocky Mountains Area, of which we operate 39. We participated in the drilling of five Rocky Mountains wells in 2009.

Oil and Natural Gas Reserves

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

Our policies regarding internal controls over the recording of reserves are structured to objectively estimate our oil and natural gas reserve quantities and values in compliance with SEC regulations. Users of this information should be aware that the process of 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. Responsibility for preparation of our reserve estimates is delegated to our reservoir engineering group, which is led by our Senior Vice President of Reservoir Engineering and Acquisitions who is a registered Professional Engineer with 37 years of diversified management and operational and technical engineering experience.

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. We have internal auditing guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. Technologies and economic data used include updated production data, well performance, formation logs, geological maps, reservoir pressure tests and wellbore mechanical integrity information.

This data is then provided 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 properties 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 26 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a registered Professional Engineer with over 27 years of reservoir engineering experience.

 

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

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2009. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (59% of PV-10 value) and by Ryder Scott Company, L.P. (23% of PV-10 value). Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits to this annual report. Our internal engineering staff has prepared a report of estimated proved reserves on the remaining smaller value properties (18% of PV-10 value) at December 31, 2009. 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 24.

 

		Net proved reserves as of December 31, 2009
		Oil (MBbl)		Natural gas (MMcf)		Total (MBoe)		PV-10 value (In thousands)
Developed—producing		40,793		183,150		71,318		$	813,407
Developed—non-producing		15,068		44,856		22,544			180,239
Undeveloped		33,608		86,424		48,012			329,895
Total proved		89,469		314,430		141,874		$	1,323,541

Our reserve estimates as of December 31, 2009 were prepared using new guidelines set forth in the SEC’s Modernization of Oil and Gas Reporting. The following changes impacted our reserves:

 

•

Commodity prices used to estimate proved reserves were the average price based upon the first day of the month for the twelve months ended December 31, 2009, or $61.18 per Bbl of oil and $3.87 per Mcf of natural gas. Under the previous method, commodity prices used to calculate estimated proved reserves at December 31, 2009 would have been the year-end price of $79.36 per Bbl of oil and $5.79 per Mcf of natural gas. We estimate that the lower commodity prices used decreased estimated proved reserves and PV-10 value by approximately 15.9 MMBoe and $881.2 million, respectively.

 

•

As a result of the expanded definition of estimated proved undeveloped reserves that can be recorded, we added proved undeveloped reserves and PV-10 value of approximately 0.9 MMBoe and $10.3 million, respectively, primarily related to horizontal wells.

 

•

The new guidelines limit the recording of estimated proved undeveloped reserves to those reserves in undrilled locations that are scheduled to be developed within five years, unless specific circumstances justify a longer time. As a result of implementing this change in the guidelines, our proved undeveloped reserves and PV-10 value decreased by approximately 3.8 MMBoe and $38.5 million, respectively.

The following table summarizes our estimated net proved oil and natural gas reserves and PV-10 values at December 31, 2009, assuming they had been prepared under the old guidelines:

 

		Net proved reserves as of December 31, 2009 based on prior methodology
		Oil (MBbl)		Natural gas (MMcf)		Total (MBoe)		PV-10 value (In thousands)
Developed—producing		44,169		206,376		78,565		$	1,281,588
Developed—non-producing		15,345		49,266		23,556			278,269
Undeveloped		35,934		135,774		58,563			673,040
Total proved		95,448		391,416		160,684		$	2,232,897

 

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The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2009.

 

Proved undeveloped reserves (MBoe)		For the year ended December 31, 2009
Proved undeveloped reserves as of January 1, 2009		29,073
Undeveloped reserves transferred to developed(1)		(881	)
Extensions and discoveries		10,989
Revisions and other		8,831
Proved undeveloped reserves as of December 31, 2009(2)		48,012

 

(1)	Approximately $17.8 million of capital expenditures during the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.

(2)	Includes 4.0 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.

The estimated reserve life as of December 31, 2009, 2008 and 2007 was 18.6, 16.0, and 24.3 years, respectively. The estimated reserve life was calculated by dividing total proved reserves by production volumes for the year indicated. The shorter reserve life in 2009 and 2008 was primarily a result of reduced proven reserves associated with lower SEC pricing.

The following table sets forth the 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.

 

(Dollars in thousands, except prices)		2009			2008			2007
Future net revenue		$	3,080,410		$	1,918,270		$	6,203,720
PV-10 value			1,323,541			932,692			2,671,982
Standardized measure of discounted future net cash flows			971,364			755,013			1,793,980
Oil price (per Bbl)		$	61.18		$	44.60		$	96.01
Natural gas price (per Mcf)		$	3.87		$	5.62		$	6.80

The following table sets forth information at December 31, 2009 relating to the producing wells in which we owned a working interest as of that date. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Wells are classified as oil or natural gas according to their predominant production stream. 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.

 

		Total wells
		Gross		Net
Crude oil		5,870		2,058
Natural gas		2,304		749
Total		8,174		2,807

 

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The following table details our gross and net interest in producing wells in which we have a working interest and the number of wells we operated at December 31, 2009 by area.

 

		Total wells				Operated Wells
		Gross		Net
Mid-Continent		5,392		2,122		2,100
Permian Basin		1,693		361		318
Gulf Coast		200		117		128
Ark-La-Tex		120		48		53
North Texas		588		120		107
Rocky Mountains		181		39		39
Total		8,174		2,807		2,745

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2009 by area.

 

		Developed				Undeveloped
		Gross		Net		Gross		Net
Mid-Continent		903,160		398,598		56,096		45,309
Permian Basin		71,962		49,302		18,101		16,983
Gulf Coast		73,356		43,891		25,546		19,476
Ark-La-Tex		22,366		10,106		—		—
North Texas		26,073		18,343		181		17
Rocky Mountains		48,837		15,921		3,251		2,611
Total		1,145,754		536,161		103,175		84,396

The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. Development wells are wells drilled within the proved area of an oil or natural gas 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.

 

		2009						2008						2007
		Gross			Net			Gross			Net			Gross			Net
Development wells
Productive		168.0			49.5			319.0			74.9			214.0			51.7
Dry		2.0			1.9			4.0			2.0			3.0			1.2
Exploratory wells
Productive		2.0			1.0			3.0			2.2			6.0			5.9
Dry		0.0			0.0			0.0			0.0			0.0			0.0
Total wells
Productive		170.0			50.5			322.0			77.1			220.0			57.6
Dry		2.0			1.9			4.0			2.0			3.0			1.2
Total		172.0			52.4			326.0			79.1			223.0			58.8
Percent productive		99	%		96	%		99	%		97	%		99	%		98	%

 

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The following table summarizes our estimates of net proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at such dates (using an average price for oil and natural gas based upon the first day of each month for the year ended December 31, 2009, and using prices in effect on December 31, 2008 and 2007), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2009 and 2008 were prepared by Cawley, Gillespie & Associates, Inc. (59% and 68% of PV-10 value, respectively), and Ryder Scott Company, L.P. (23% and 7% of PV-10 value, respectively). Estimates of our net proved oil and natural gas reserves as of December 31, 2007 were prepared by Cawley, Gillespie & Associates, Inc. (36% of PV-10 value), and Lee Keeling & Associates, Inc. (52% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (18%, 25%, and 12% of PV-10 value in 2009, 2008, and 2007, respectively).

 

		As of December 31,
Proved Reserves		2009				2008				2007
Oil (Mbbl)			89,469				51,283				99,104
Natural gas (MMcf)			314,430				372,366				392,269
Oil equivalent (MBoe)			141,874				113,344				164,482
Proved developed reserve percentage			66	%			74	%			65	%
PV-10 value (in thousands)		$	1,323,541			$	932,692			$	2,671,982
Estimated reserve life in years(1)			18.6				16.0				24.3
Cost incurred (in thousands):
Property acquisition costs
Proved properties(2)		$	14,552			$	39,201			$	41,724
Unproved properties			3,781				6,677				8,032
Total acquisition costs			18,333				45,878				49,756
Development costs(3)			127,640				251,690				165,177
Exploration costs			4,942				5,108				15,287
Total		$	150,915			$	302,676			$	230,220
Annual reserve replacement ratio(4)			243	%			200	%			372	%

 

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

(2)	Includes $15.6 million of amounts disbursed from escrow related to title defects and other purchase price allocation adjustments on the Calumet acquisition in 2007.

(3)	Includes $3.6 million and $16.1 million of costs related to the construction of a compressor station and CO2 pipeline in 2009 and 2008, respectively.

(4)

Calculated by dividing the sum of reserve additions (from purchases of minerals in place, extensions and discoveries, and improved recoveries) by the production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in Note 16 of the notes to our consolidated financial statements. In calculating reserves replacement, we do not use unproved reserve quantities. 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,
		2009						2008						2007
		Reserves replaced			Percent of total			Reserves replaced			Percent of total			Reserves replaced			Percent of total
Purchases of minerals in place		9	%		3.5	%		35	%		17.2	%		46	%		12.5	%
Extensions and discoveries		195	%		80.4	%		155	%		77.6	%		214	%		57.4	%
Improved recoveries		39	%		16.1	%		10	%		5.2	%		112	%		30.1	%
Total		243	%		100.0	%		200	%		100.0	%		372	%		100.0	%

 

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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,
		2009			2008			2007
Production:
Oil (MBbls)			3,874			3,773			3,356
Natural gas (MMcf)			22,584			19,795			20,504
Combined (MBoe)			7,638			7,072			6,773
Average daily production:
Oil (Bbls)			10,614			10,309			9,195
Natural gas (Mcf)			61,874			54,085			56,175
Combined (Boe)			20,926			19,323			18,558
Average prices (excluding derivative settlements):
Oil (per Bbl)		$	55.04		$	92.47		$	69.85
Natural gas (per Mcf)			3.51			7.72			6.41
Combined (per Boe)		$	38.28		$	70.95		$	54.03
Average costs per Boe:
Lease operating expenses		$	12.33		$	17.05		$	15.42
Production taxes			2.66			4.78			3.87
Depreciation, depletion, and amortization			13.62			14.24			12.61
General and administrative			3.11			3.16			3.22

 

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Non-GAAP Financial Measures and Reconciliations

The PV-10 value is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using generally accepted accounting principles (“GAAP”). PV-10 value is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 value is equal to the standardized measure of discounted future net cash flows at December 31, 2009 before deducting future income taxes, discounted at 10%. 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 the standardized measure of discounted future net cash flows to PV-10 value as of December 31, 2009 for our major areas of operation:

 

(dollars in millions)		PV-10 Value			Present value of future income tax discounted at 10%			Standardized measure of discounted future net  cash flow
Mid-Continent		$	1,045.0		$	256.1		$	788.9
Permian Basin			148.8			51.0			97.8
Gulf Coast			57.3			18.6			38.7
Ark-La-Tex			22.4			8.6			13.8
North Texas			30.9			10.7			20.2
Rocky Mountains			19.1			7.1			12.0
Total		$	1,323.5		$	352.1		$	971.4

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 hedges and reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) deferred compensation expense (gain), (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges. Any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization are excluded from the calculation of adjusted EBITDA.

 

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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 the financial measurement that is used in the covenant calculation required under our Credit Agreement 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. 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. The following table provides a reconciliation of net loss to adjusted EBITDA for the specified periods:

 

		Year Ended December 31,
		2009				2008				2007
Net loss		$	(144,318	)		$	(54,750	)		$	(4,793	)
Interest expense			90,102				86,038				87,656
Income tax benefit			(85,936	)			(34,386	)			(2,745	)
Depreciation, depletion, and amortization			104,734				101,973				85,842
Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments			(21,752	)			(12,549	)			8,343
Non-cash change in fair value of non-hedge derivative instruments			149,106				(89,554	)			23,031
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from monetization date			(102,352	)			—				—
Interest income			(283	)			(409	)			(755	)
Deferred compensation expense (gain)			1,145				(306	)			831
Gain on disposed assets			(10,463	)			(177	)			(712	)
Loss on impairment of oil and natural gas properties			240,790				281,393				—
Loss on impairment of ethanol plant			—				2,900				—
Loss on litigation settlement			2,928				—				—
Adjusted EBITDA		$	223,701			$	280,173			$	196,698

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil 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 development 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.

 

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Markets

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

 

•

the 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 federal and state regulation of production, refining, transportation and sales;

 

•

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

 

•

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

 

•

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

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

 

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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 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 and other protected areas;

 

•

require remedial measures to prevent 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. For example, we are currently undertaking additional construction tests of our CO₂ pipeline to fully document it is in substantial compliance with rules and regulations regarding natural gas pipeline safety. We cannot predict how future environmental laws and regulations may affect our properties or operations. For the years ended December 31, 2009 and 2008, 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 2010 or that will otherwise have a material impact on our financial position or results of operations.

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

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal 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 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.

 

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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 presently classified wastes 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 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 them may be subject to CERCLA, RCRA, and analogous state laws. 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. 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. We believe we are in substantial compliance with the requirements of the Clean Water Act.

The Safe Drinking Water Act, groundwater protection, and the Underground Injection Control Program

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 it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal permits, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater.

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.

 

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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. The U.S. Congress is considering legislation that would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate regulations requiring permits and implementing potential new requirements of hydraulic fracturing under the SDWA. This could, in turn, require state regulatory agencies in states with programs delegated under the SDWA to impose additional requirements on hydraulic fracturing operations.

The Clean Air Act

The federal Clean Air Act 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 Clean Air Act and associated state laws and regulations. The EPA proposed in a consent decree, which has not been approved by a federal court, that it will issue by January 31, 2011 a proposal to revise its national emissions standards for hazardous air pollution for crude oil and natural gas production, as well as gas transmission and storage and its new source performance standards for oil and natural gas production.

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. 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 Clean Air Act.

In December 2009, the EPA promulgated a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas (GHG) regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, in September 2009, the EPA also promulgated a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect sources in the oil and gas exploration and production industry and pipeline industry.

The EPA’s finding, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry. See “Risk factors—Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.”

Other Laws and Regulation

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.

Other Regulation of the Oil and Natural Gas Industry

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

 

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

Drilling and Production

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

 

•

the location of wells;

 

•

the method of drilling and casing wells;

 

•

the rates of production or “allowables”;

 

•

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.

Natural Gas Sales 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 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 gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under 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.

 

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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. and the hazardous material transportation laws codified at 49 U.S.C. 5101, et seq.

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 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 and the Rocky Mountains may experience seasonal fluctuations, we do not believe these fluctuations have had, or will have, a material impact on our consolidated results of operations.

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 assure 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, 2009, we had 689 full-time employees, including 14 geologists and geophysicists, 32 reservoir, production, and drilling engineers and 16 land professionals. Of these, 293 work in our Oklahoma City office and 396 work in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

 

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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 natural gas prices are volatile. A decline in oil and natural 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 natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following:

 

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the level of consumer demand for oil and natural gas;

 

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the domestic and foreign supply of oil and natural gas;

 

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

 

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

 

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the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

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domestic and foreign governmental regulations and taxes;

 

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the price and availability of alternative fuel sources;

 

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weather conditions;

 

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financial and commercial market uncertainty;

 

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

 

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worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices 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. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our senior secured credit facility and our Senior Notes, or be unable to make planned capital expenditures.

 

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Price declines at the end of 2008 and early 2009 resulted in write downs of the carrying values of our properties, 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 natural gas reserves discounted at 10%, adjusted for derivatives accounted for as cash flow hedges and net of tax considerations, plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date as adjusted for our derivative positions deemed “cash flow hedge positions.” A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

During the fourth quarter of 2008, our evaluation of our full cost ceiling required a non-cash impairment charge of $281.4 million to the value of our oil and natural gas properties as a result of a decline in oil and natural gas prices at the measurement date. The impairment was calculated based on December 31, 2008 prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. During the first quarter of 2009, natural gas prices declined significantly (as compared to the December 31, 2008 spot price of $5.62 per Mcf), and based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, our reserves declined by 13.5%, as a result of which we recorded a non-cash ceiling test impairment of $240.8 million during the first quarter of 2009. Oil and natural gas prices have remained 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 write downs could have a material adverse effect on our financial condition, results of operations, and our ability to comply with debt covenants.

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

Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates and assumptions, including estimates based upon assumptions relating to economic factors such as commodity prices, production costs, severance and excise taxes, capital expenditures, workovers, remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to possible or probable reserves, including with respect to our EOR operations. Reserve estimates are, therefore, inherently imprecise and, although we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results will vary from our estimates. Any significant variations in the interpretations or assumptions underlying our estimates or changes of conditions (e.g. economic growth 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 Securities and Exchange Commission, the estimates of present values are based on prices and costs in effect as of the date of the estimates and exclude 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, 2009 reserve report used realized prices based on an average price of $3.87 per Mcf for natural gas and an average price of $61.18 per Bbl for oil.

 

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A significant portion of total proved reserves as of December 31, 2009 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2009, approximately 34% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and EOR operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct and we may ultimately determine the development of all, or any portion of, such proved but undeveloped reserves is not economically feasible.

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

As of December 31, 2009, approximately 14% of our proved reserves were based on EOR methods including the injection of CO₂ and polymers, a synthetic chemical. Some of these properties have not been injected with CO₂ or with polymers having the identical chemical composition as polymers used in historical production, and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or improvements in anticipated production levels. Our ability to develop future 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.

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

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

 

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

 

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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 and debt financing. 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 34% of our total estimated proved reserves (by volume) at December 31, 2009 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, 2009 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14%, 11%, and 9% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations, and cash flows are highly dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves.

 

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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. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

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unexpected drilling conditions;

 

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title problems;

 

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pressure or lost circulation in formations;

 

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equipment failures or accidents;

 

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adverse weather conditions;

 

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compliance with environmental and other governmental requirements; and

 

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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.

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 natural gas, as well as environmental and safety matters. Although we believe that we are in substantial compliance with all applicable laws and regulations, 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:

 

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land use restrictions;

 

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drilling bonds and other financial responsibility requirements;

 

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spacing of wells;

 

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reporting or other limitations on emissions of greenhouse gases;

 

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unitization and pooling of properties;

 

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

 

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well stimulation processes;

 

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produced water disposal;

 

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CO2 pipeline requirements;

 

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safety precautions;

 

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operational reporting; and

 

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taxation.

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

 

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personal injuries;

 

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property and natural resource damages;

 

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oil spills and releases or discharges of hazardous materials;

 

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well reclamation costs;

 

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

 

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other environmental damages; and

 

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reporting or other issues arising from greenhouse gas emissions.

 

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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, future regulations promulgated pursuant to the Clean Air Act or other mandatory federal legislation may require monitoring and reporting of greenhouse gas emissions and eventually may impose restrictions on these emissions resulting in liability for exceeding permitted air pollutant emission rates or other mandatory caps on greenhouse gas emissions. We are unable to predict the ultimate cost of compliance with these requirements 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. 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. 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:

 

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timing and amount of capital expenditures;

 

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

 

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financial resources;

 

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inclusion of other participants in drilling wells; and

 

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use of technology.

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

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

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

 

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

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

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

Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental 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:

 

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injury or loss of life;

 

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

 

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pollution or other environmental damage;

 

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clean-up responsibilities;

 

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regulatory investigations and administrative, civil and criminal penalties; and

 

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

Our liability for environmental hazards 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, in the future, 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:

 

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the uncertainties in estimating clean up costs;

 

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

 

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

 

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

 

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

Our ability to make scheduled payments on or to refinance our long-term indebtedness 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 flows 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 long-term 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. Our Credit Agreement and the indentures governing our Senior Notes restrict our ability to dispose of assets and use the proceeds from the disposition. 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:

 

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

 

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

 

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the lenders under the Credit Agreement could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and

 

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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, 2009, our total long-term indebtedness, including current maturities, was $1,177.0 million. As of April 14, 2010, our total long term indebtedness was approximately $841.0 million, and our maximum commitment amount and the borrowing base under our Eighth Restated Credit Agreement was $450.0 million. 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 natural gas at specified dates.

Our level of indebtedness affects our operations in several ways, including the following:

 

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a significant portion of our cash flows from operating activities must be used to service our indebtedness and, therefore, is not available for other purposes such as acquisitions, exploration, or property development;

 

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we may be at a competitive disadvantage as compared to similar companies that have less debt;

 

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the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

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additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

 

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changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings may increase the interest rate and fees we pay on our revolving bank credit facility; and

 

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we may be more vulnerable to general adverse economic and industry conditions.

 

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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 Credit Agreement is subject to a borrowing base, which was $450.0 million as of April 14, 2010, 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 the Eighth Restated Credit Agreement, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued. If the outstanding borrowings under our Credit Agreement 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 natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 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 natural gas and provide stability to cash flows, we enter into derivative positions, some of which are designated as cash flow hedges for accounting purposes. These derivative products include fixed-price swaps, collars, and basis swaps with financial institutions or other similar transactions. As of December 31, 2009, we had entered into swaps for 23,700 BBtu of our natural gas production for 2010 through 2011 at average monthly prices ranging from $6.90 to $8.00 per MMBtu of natural gas. We also entered into collars for 3,360 BBtu of our natural gas production for 2010 at a floor of $10.00 per MMBtu. As of December 31, 2009, we had entered into swaps for 4,482 MBbls of our crude oil production for 2010 through 2011 at average monthly prices ranging from $67.39 to $69.03 per Bbl of oil. We also entered into collars for 444 MBbls of our crude oil production for 2010 through 2011 at a floor of $110.00 per Bbl of oil. As of December 31, 2009, we had basis protection swaps for 29,590 BBtu of our natural gas production for 2010 through 2011 at average monthly prices ranging from $0.70 to $0.94 per MMBtu. The fair value of our oil and natural gas derivative positions outstanding as of December 31, 2009 was a liability of approximately $26.8 million.

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

 

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our production is less than expected;

 

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the counter-party to the derivative instruments defaults on its contractual obligations; or

 

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

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, derivatives that are not hedges must be adjusted to fair value through income. If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, is immediately recognized in gain (loss) from oil and natural gas hedging activities in the statement of operations.

If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting must be discontinued and the gain or loss reported in accumulated other comprehensive income (loss) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting must be discontinued. The gain or loss associated with the discontinued hedges remains in accumulated other comprehensive income (loss) and is reclassified into income as the hedged transactions occur.

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

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

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

 

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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;

 

•

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

 

•

tax burden due to new tax laws.

Assuming a constant debt level of $513.0 million, equal to our borrowing base at December 31, 2009, the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $5.1 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects.

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

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

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 natural gas.

Recent scientific studies have suggested that emissions of gases, commonly referred to as “greenhouse gases” including carbon dioxide, methane, and nitrous oxide among others, may be contributing to warming of the earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, several states have already taken legal measures to reduce emissions of greenhouse gases.

As a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, 549 U.S. 497 (2007), finding that greenhouse gases fall within the Clean Air Act (“CAA”) definition of “air pollutant,” the Environmental Protection Agency (“EPA”) was required to determine whether emissions of greenhouse gases “endanger” public health or welfare. In April 2009, EPA proposed a finding of such endangerment. Consistent with its proposed endangerment finding, in September 2009, EPA proposed regulations to control greenhouse gas emissions from light duty vehicles. The EPA also announced that its proposed action to control greenhouse gas emissions from light duty vehicles, should it become final, would automatically trigger application of the CAA prevention of significant deterioration and Title V operating permit programs to major stationary sources of greenhouse gas emissions. In September 2009, EPA issued a proposed “tailoring” rule explaining the legal mechanism upon which it would rely to raise the “major stationary source” air pollutant emission threshold of 250 tons per year and 100 tons per year to 25,000 tons per year. With its proposed “tailoring rule,” EPA also explained the manner in which it would implement the CAA permitting programs to major stationary source greenhouse gas emission sources. In September 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in implementing the major stationary source permitting programs triggered by the mobile source rules. This reporting rule became effective on December 29, 2009. On December 15, 2009, EPA promulgated its final endangerment rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act.” This final rule became effective on January 14, 2010. Currently, EPA is expected to promulgate its final rules regulating and controlling greenhouse gas emissions from light duty vehicles, as well as its final “tailoring rule,” in March 2010. Though subject to legal challenge, EPA’s rules promulgated thus far are currently final and effective, and will remain so unless successfully challenged directly in court, or unless Congress adopts legislation preempting EPA’s regulatory authority to address greenhouse gases under the CAA.

 

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Beyond legislative and regulatory developments, there have been several court cases impacting this area of risk. First, in September 2009, the United States Court of Appeals for the Second Circuit issued its decision in Connecticut v. American Electric Power Co., 2009 U.S. App. LEXIS 20873 (2d Cir. Sept. 21, 2009). With this case, the Second Circuit reversed a lower court’s dismissal of plaintiff claims that public utilities greenhouse gas emissions created a “public nuisance.” In reversing, the Second Circuit rejected the lower court’s reliance on defenses including political question, preemption and lack of standing to dismiss. In this case, the plaintiffs consist of State entities and public trusts, and are seeking to enjoin excessive greenhouse gas emissions. Second, on October 16, 2009, the United States Court of Appeals for the Fifth Circuit issued its decision in Comer v. Murphy Oil USA, 2009 U.S. App. LEXIS 22774 (5th Cir. Oct. 16, 2009). With this case, the Fifth Circuit reversed a lower court’s dismissal of plaintiff claims that corporations operating energy, fossil fuel and chemical industries caused the emission of greenhouse gases that ultimately resulted in additional property damage from Hurricane Katrina, asserting claims of public and private nuisance, trespass, negligence, unjust enrichment, fraudulent misrepresentation and civil conspiracy. In reversing, the Fifth Circuit rejected the lower court’s reliance on similar defenses, including the political question defense. In this case, the plaintiffs consist of property owners and they are seeking only damages. A similar case, Native Village of Kivalina v. ExxonMobil Corp., Case No: C 08-1138 SBA (N.D. Cal., Oakland Div.) (Sept. 30, 2009) (order granting defendants’ motion to dismiss for lack of subject matter jurisdiction), was appealed to the Ninth Circuit in November, 2009. These cases expose other significant emission sources of greenhouse gases to similar litigation risk. The effect of this recent caselaw may be mitigated by actions that the courts determine displace federal common law, potentially including Congressional adoption of greenhouse gas legislation and, or, EPA’s final adoption of the light duty vehicle emission regulations which, without legislative intervention, will trigger application of other CAA provisions to greenhouse gas emissions.

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) have agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Though the 15th meeting of the Council of the Parties in Copenhagen in December 2009 failed to result in a final agreement, international negotiations continue, with the participation of the United States. 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 further development of caselaw allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and demand for oil and natural gas.

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

Pending federal budget proposals released by the White House on February 26, 2009 and February 1, 2010 would potentially increase and accelerate the payment of federal income taxes of independent producers of oil and natural gas. Proposals that would significantly affect us include, but are not limited to, repealing the expensing of intangible drilling costs, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and natural gas companies and increasing the amortization period of geological and geophysical expenses. Additionally, the Senate Bill version of the Oil Industry Tax Break Repeal Act of 2009, introduced on April 23, 2009, and the Senate Bill version of the Energy Fairness for America Act, introduced on May 20, 2009, include many of the proposals outlined in the federal budget proposals. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. The passage of any legislation as a result of the budget proposals, either Senate Bill or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change (i) would make it more costly for us to explore for and develop our oil and natural gas resources and (ii) could negatively affect our financial condition, results of operation and, thus, our ability to make payments on the notes.

The U.S. Congress is considering measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. We maintain an active price and basis protection hedging program related to the oil and natural gas we produce.

Additionally, we have used the OTC market exclusively for our oil and natural gas derivative contracts and rely on our hedging activities to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. Proposals being considered would impose clearing and standardization requirements for all OTC derivatives and restrict trading positions in the energy futures markets. Such changes would likely materially reduce our hedging opportunities and could negatively affect our revenues and cash flow during periods of low commodity prices.

 

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

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma, Texas, and Louisiana, our operations are constantly at risk of extreme adverse weather conditions such as tornadoes and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as hurricanes or floods, whether due to climate change or otherwise.

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

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

Certain risks are amplified by the current economic environment.

During 2007, the U.S. and many other countries began to exhibit signs of economic weakness, which continued throughout 2008 and 2009. This weakness has had an adverse impact on the global financial system, stressing a number of large financial institutions. Capital constraints coupled with significant energy price volatility have produced pervasive liquidity issues for many companies. Such events have created uncertainty in the economic outlook, and have amplified the potential likelihood of certain risks inherent in our business, such as:

 

•

increased cost of capital and increased difficulties accessing capital to fund expansion and acquisition activities as well as routine operating requirements;

 

•

the failure of counterparties to fulfill their delivery or purchase obligations;

 

•

business failures by vendors, suppliers or customers that result in (i) delays in progress on our capital projects, (ii) nonpayment of receivables or (iii) expensive and protracted court or bankruptcy proceedings; and

 

•

decreases in domestic consumption or in volumes imported to or produced in the United States and related reductions in transportation or marketing margins.

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. Despite the recent decline in commodity prices and lower industry activity levels, competition for these professionals remains strong. We are likely to continue to experience increased costs to attract and retain these professionals.

 

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

Congress is currently considering 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 natural gas production. Sponsors of bills currently pending 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 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 which would allow the EPA to establish an additional level of regulation at the federal level 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.

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Items 1. and 2. Business and Properties—Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Liquidity and Capital Resources—Contractual Obligations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 13, “Commitments and Contingencies,” to the Consolidated Financial Statements. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

In the opinion of management, there are no other material pending legal proceedings to which we or any of our subsidiaries 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.

ITEM 4. [RESERVED]

 

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PART II

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

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

As of April 14, 2010, we had 1,401,376 shares of common stock outstanding held by 21 record holders.

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

 

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ITEM 6. SELECTED FINANCIAL DATA

You should read the following historical financial data in connection with the financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this report. The financial data as of and for each of the five years ended December 31, 2009 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.

 

		Year Ended December 31,
(dollars in thousands, except per share data)		2009				2008				2007				2006				2005
Operating results data:
Revenues
Oil and natural gas sales		$	292,387			$	501,761			$	365,958			$	249,180			$	201,410
Gain (loss) from oil and natural gas hedging activities			19,403				(76,417	)			(28,140	)			(4,166	)			(68,324	)
Total revenues			311,790				425,344				337,818				245,014				133,086
Costs and expenses
Lease operating			94,155				120,547				104,469				71,663				42,147
Production tax			20,341				33,815				26,216				18,710				14,626
Depreciation, depletion and amortization			103,998				100,672				85,431				52,299				31,423
Loss on impairment of oil & natural gas properties			240,790				281,393				—				—				—
Loss on impairment of ethanol plant			—				2,900				—				—				—
General and administrative			23,741				22,372				21,838				14,659				9,808
Litigation settlement			2,928				—				—				—				—
Total costs and expenses			485,953				561,699				237,954				157,331				98,004
Operating income (loss)			(174,163	)			(136,355	)			99,864				87,683				35,082
Non-operating income (expense)
Interest expense			(90,102	)			(86,038	)			(87,656	)			(45,246	)			(15,588	)
Non-hedge derivative gains (losses)			11,169				126,941				(23,781	)			(4,677	)			—
Merger costs			(2,169	)			(1,400	)			—				—				—
Termination fee			—				3,500				—				—				—
Other income			14,403				1,845				2,276				792				665
Net non-operating income (expense)			(66,699	)			44,848				(109,161	)			(49,131	)			(14,923	)
Income (loss) from continuing operations before income taxes and non-controlling interest			(240,862	)			(91,507	)			(9,297	)			38,552				20,159
Income tax expense (benefit)			(89,895	)			(35,301	)			(3,386	)			14,817				7,309
Non-controlling interest			—				—				—				(71	)			—
Income (loss) from continuing operations			(150,967	)			(56,206	)			(5,911	)			23,806				12,850
Income from discontinued operations, net of related taxes			6,649				1,456				1,118				—				—
Net income (loss)		$	(144,318	)		$	(54,750	)		$	(4,793	)		$	23,806			$	12,850
Income (loss) per share (basic and diluted):
Continuing operations		$	(172.14	)		$	(64.09	)		$	(6.74	)		$	29.74			$	16.58
Discontinued operations			7.58				1.66				1.27				—				—
Net income (loss) per share (basic and diluted)		$	(164.56	)		$	(62.43	)		$	(5.47	)		$	29.74			$	16.58
Weighted average number of shares used in calculation of basic and diluted earnings (loss) per share			877,000				877,000				877,000				800,500				775,000
Cash flow data:
Net cash provided by operating activities		$	98,675			$	145,831			$	113,070			$	89,154			$	55,744
Net cash provided by (used in) investing activities			21,904				(262,905	)			(239,069	)			(703,804	)			(325,068	)
Net cash provided by (used in) financing activities			(99,274	)			157,499				128,883				621,855				257,080

 

		As of December 31,
(dollars in thousands, except per share amounts)		2009				2008			2007				2006				2005
Financial position data:
Cash and cash equivalents		$	73,417			$	52,112		$	11,687			$	8,803			$	1,598
Total assets			1,353,920				1,712,836			1,530,898				1,331,435				647,379
Total debt			1,177,007				1,271,589			1,114,237				976,272				446,544
Retained earnings (accumulated deficit)			(122,978	)			21,340			76,090				80,883				58,126
Accumulated other comprehensive income (loss), net of income taxes			17,618				82,133			(73,839	)			(3,946	)			(47,967	)
Total stockholders’ equity (deficit)			(4,433	)			204,400			103,178				177,864				10,167
Cash dividends per common share			—				—			—			$	1.35			$	4.40

 

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

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

Overview

We are an independent oil and natural gas company engaged in the production, exploitation and acquisition of oil and natural gas properties. Our areas of operation include the Mid-Continent, Permian Basin, Gulf Coast, Ark-La-Tex, North Texas and the Rocky Mountains. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and EOR projects.

Our reserve estimate as of December 31, 2009 was prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’s Modernization of Oil and Gas Reporting. As of December 31, 2009, we had estimated proved reserves of 141.9 MMBoe, with a PV-10 value of approximately $1.3 billion. Our reserves were 66% proved developed reserves and 63% crude oil. Despite the decline in SEC gas price from $5.62 per Mcf as of December 31, 2008 to $3.87 per Mcf as of December 31, 2009, our estimated proved reserves have increased significantly since December 31, 2008 due in part to an increase in SEC oil price from $44.60 per Bbl as of December 31, 2008 to $61.18 per Bbl as of December 31, 2009. As of December 31, 2008, we had estimated proved reserves of 113.3 MMBoe with a PV-10 value of $932.7 million, of which 74% were proved developed reserves and 45% were crude oil.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.

Generally our producing properties have declining production rates. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14%, 11%, and 9% for the next three years. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

Oil and natural gas prices fluctuate widely. We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The prices we receive for our oil and natural gas production affect our:

 

•

cash flow available for capital expenditures;

 

•

ability to borrow and raise additional capital;

 

•

ability to service debt;

 

•

quantity of oil and natural gas we can produce;

 

•

quantity of oil and natural gas reserves; and

 

•

operating results for oil and natural gas activities.

 

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Operating summary

Our production for 2009 was 7,638 MBoe, an 8% increase over 2008, primarily due to our capital expenditures in the Permian and Mid-Continent areas during 2008 and 2009. However a 46% decline in our average sales price before derivative settlements resulted in a 42% decrease in revenue from oil and natural gas sales compared to 2008. Although total operating costs and expenses decreased by 13% compared to 2008, the decrease was not commensurate with the decrease in revenue. In addition, due primarily to changes in the NYMEX forward commodity price curves, our gain on non-hedge derivatives decreased by 91%. Primarily as a result of these factors, we had a net loss of $144.3 million in 2009 compared to a loss of $54.8 million in 2008.

The following are material events that have impacted liquidity or results of operations in 2009 or are expected to impact these items in future periods:

 

•

Current Market Conditions. Our business in 2009 was negatively impacted by constraints in the credit markets and continued commodity price volatility. Prices declined significantly during the fourth quarter of 2008 and into 2009. Although partially offset by our commodity derivatives, lower commodity prices reduced our cash flows from operations as compared to prior years. If commodity prices decline again, our cash flows from operations would be further reduced, which may cause us to alter our business plans.

 

•

Impairment of oil and natural gas properties. In accordance with the full-cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to our PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and natural gas properties of $240.8 million during the first quarter of 2009.

 

•

Monetization of Derivative Assets. During the first quarter of 2009, we monetized certain derivative instruments with original settlement dates from May through October of 2009 for net proceeds of $9.5 million. None of the monetized derivatives were incorporated into the determination of the borrowing base under our Seventh Restated Credit Agreement. During the second quarter of 2009 we monetized additional derivative instruments with original settlement dates from January 2012 through December 2013 for net proceeds of $102.4 million. As a result of this monetization, effective June 8, 2009, the borrowing base was reduced from $600.0 million to $513.0 million, resulting in a payment to the banks of $87.0 million. The remaining proceeds of $15.4 million increased our cash balance.

 

•

Production Tax Credit. During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our return on the investment was the receipt of $2 of tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments were accounted for as a production tax benefit asset and were netted against tax credits realized in other income using the effective yield method over the expected recovery period. During the years ended December 31, 2009, 2008, and 2007, we received cash of $27.2 million, $2.1 million, and $0.7 million, respectively, and recorded pre-tax income of $13.5 million, $0.7 million, and $0.8 million, respectively, from application of these tax credits. This source of cash and income will not be available in future periods.

 

•

Discontinued operations. During the second quarter of 2009, we committed to a plan to sell the assets of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary that provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps, and related services to oil and natural gas operators primarily in Oklahoma, Texas, and Wyoming. During the year ended December 31, 2009, we sold the Electric Submersible Pumps (“ESP”) division and the Chemicals division of GCS in two separate transactions, for which we received cash totaling $25.3 million and recorded a pre-tax gain totaling $10.4 million.

 

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Liquidity and capital resources

Crude oil and natural gas prices have fallen significantly from their peak levels during the second and third quarters of 2008. Lower oil and natural gas prices decrease our revenues. An extended decline in oil or natural gas prices may materially and adversely affect our future business, liquidity or ability to finance planned capital expenditures

We pledge our producing oil and natural gas properties to secure our Credit Agreement. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We utilize the available funds as needed to supplement our operating cash flows as a financing source for our capital expenditures. Our ability to fund our capital expenditures is dependent on the level of product prices and the success of our acquisition and development program in adding to our available borrowing base. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available for our capital expenditures. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and natural gas prices through the use of commodity derivatives.

Historically, our primary sources of liquidity have been cash generated from our operations and debt. At December 31, 2009, we had approximately $73.4 million of cash and cash equivalents and $3.1 million of availability under our Seventh Restated Credit Agreement with a borrowing base of $513.0 million.

On March 23, 2010, we entered into a stock purchase agreement (the “Stock Purchase Agreement”) with CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”). On April 12, 2010, we sold 475,043 shares of our common stock to CCMP for a purchase price of $325.0 million. In connection with the closing of the Stock Purchase Agreement, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. As of April 14, 2010, we had $275.3 million of availability under our Eighth Restated Credit Agreement. See Note 14 to our consolidated financial statements for additional information regarding these transactions.

Covenants set forth in the indentures for our 8 ¹ /2% Senior Notes and the 8 ⁷/8% Senior Notes, including 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 natural gas at specified dates.

 

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Sources and uses of cash

Our net increase in cash is summarized as follows:

 

		Year ended December 31,
(dollars in thousands)		2009				2008				2007
Cash flows provided by operating activities		$	98,675			$	145,831			$	113,070
Cash flows provided by (used in) investing activities			21,904				(262,905	)			(239,069	)
Cash flows provided by (used in) financing activities			(99,274	)			157,499				128,883
Net increase in cash during the period		$	21,305			$	40,425			$	2,884

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas, reduced or increased by associated hedging activities. Cash inflows from oil and natural gas sales net of hedging settlements and cash outflows for operating expenses both decreased sharply from 2008 to 2009 due to the decline in commodity prices after having increased significantly from 2007 to 2008 as commodity prices rose. Operating cash flows also include production tax credits of $13.7 million, $1.0 million, and $0.3 million for the years ended December 31, 2009, 2008, and 2007, respectively. This source of cash received will not be available in future periods. Primarily as a result of the above activity, cash flow from operating activities decreased by 32% from 2008 to 2009 after having increased by 29% from 2007.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the years ended December 31, 2009, 2008, and 2007, cash flows provided by operating activities were approximately 55%, 48%, and 51%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties. In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. Total costs attributable to the loss of well control were approximately $10.6 million. Our insurance policy has covered 100% of these costs, with the $0.6 million insurance retention and deductible being payable by us. We received insurance proceeds of $1.9 million and $8.1 million in 2009 and 2008, respectively, and no further receipts are expected. Insurance proceeds received are recorded as a reduction of oil and natural gas properties on the balance sheet and in the statement of cash flows.

During 2009, 2008, and 2007, the monetization of derivatives provided investing cash inflows of $111.9 million, $32.6 million, and $0, respectively, and the return of our prepaid production tax credits provided investing cash inflows of $13.5 million, $1.1 million, and $0.4 million, respectively. Cash flows provided by investing activities for the year ended December 31, 2009 also included proceeds of $25.3 million from the sale of the ESP and Chemicals divisions of GCS. See the Results of operations section for additional discussion of these transactions.

Net cash provided by (used in) financing activities was ($99.3) million, $157.5 million, and $128.9 million, during 2009, 2008, and 2007, respectively. As a result of our monetization of derivatives in the second quarter of 2009, the borrowing base under our Seventh Restated Credit Agreement was reduced from $600.0 million to $513.0 million, and proceeds from the monetization of $87.0 million were paid to the banks. Borrowings under our Seventh Restated Credit Agreement were $147.0 million and $110.0 million in 2008 and 2007, respectively, and were used to finance our capital expenditures. On January 18, 2007, we issued $325.0 million aggregate principal amount of 8 ⁷/8% Senior Notes maturing on February 1, 2017. The net proceeds from the issuance of the notes were used to pay down outstanding amounts under our Seventh Restated Credit Agreement.

 

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Capital expenditures

Our actual costs incurred for the year ended December 31, 2009 and our current 2010 budgeted capital expenditures for oil and natural gas properties are detailed in the table below:

 

(dollars in thousands)		Year ended December  31, 2009(1)			2010 budgeted  capital expenditures
Development activities:
Developmental drilling(2)		$	77,826		$	163,000
Enhancements			34,767			12,000
Tertiary recovery			15,047			63,000
Acquisitions:
Proved properties			14,552			20,000
Unproved properties			3,781			—
Exploration activities			4,942			10,000
Total		$	150,915		$	268,000

 

(1)	Includes $1.3 million of additions relating to increases in our asset retirement obligations.

(2)	Includes $3.6 million of costs related to the construction of a compressor station and CO2 pipeline in 2009.

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $2.6 million for acquisition and construction of new office and administrative facilities and equipment during 2009.

Our oil and natural gas property capital expenditures for 2009 represent a 50% reduction from our 2008 levels. Despite this reduction, production for 2009 increased to 7,638 MBoe as a result of capital investments made in 2008 and the first quarter of 2009. Our actual costs incurred for the year ended December 31, 2009 and our current 2010 budgeted capital expenditures for oil and natural gas properties summarized by area are detailed in the table below:

 

(dollars in thousands)		2009 capital expenditures(1)			Percent of total			2010 budgeted capital expenditures			Percent of total
Mid-Continent(2)		$	117,820		78	%		$	209,000		78	%
Permian Basin			17,390		11	%			34,000		13	%
Gulf Coast			11,881		8	%			14,000		5	%
Ark-La-Tex			2,306		2	%			1,000		0	%
North Texas			1,262		1	%			4,000		2	%
Rocky Mountains			256		0	%			6,000		2	%
		$	150,915		100	%		$	268,000		100	%

 

(1)	Includes $1.3 million of additions relating to increases in our asset retirement obligations.

(2)	Includes $3.6 million of costs related to the construction of a compressor station and CO2 pipeline in 2009.

A majority of our oil and natural gas capital expenditure budget for development drilling in 2010 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells. A number of high impact wells that we expect will support our production throughout 2010 are currently being drilled and should be completed and on line during the first and second quarters of 2010. Six of these wells are located in the Texas Panhandle Atoka Wash and one is located in the Haley Area of Loving County, Texas. However, we cannot accurately predict the timing or level of future production.

We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2010 may be higher or lower than our budgeted amounts. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.

As of December 31, 2009, we had cash and cash equivalents of $73.4 million and long-term debt obligations of $1.2 billion.

 

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Credit Agreements

At December 31, 2009, we were a party to a Seventh Restated Credit Agreement, which was scheduled to mature on October 31, 2010, and was collateralized by our oil and natural gas properties. As a result of our derivative monetization during the second quarter of 2009, the borrowing base was reduced from $600.0 million to $513.0 million effective June 8, 2009. At December 31, 2009, we had $507.0 million outstanding under our Seventh Restated Credit Agreement and all of our borrowings were Eurodollar loans. The borrowing base, which was reaffirmed effective November 23, 2009, was $513.0 million as of December 31, 2009. We believe we were in compliance with all covenants under the Seventh Restated Credit Agreement as of December 31, 2009.

On April 12, 2010, in connection with the closing of our Stock Purchase Agreement with CCMP, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement.

The terms of the Eighth Restated Credit Agreement are described below. The terms of the Seventh Restated Credit Agreement were substantially similar to those contained in the Eighth Restated Credit Agreement. All discussions of interest rates and ratios as of dates prior to April 12, 2010 relate to the Seventh Restated Credit Agreement. Availability under our Credit Agreement is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. If we issue Additional Permitted Debt, as defined in the Eighth Restated Credit Agreement, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued. As of April 14, 2010, we had $275.3 million of availability under our Eighth Restated Credit Agreement.

The agreement has certain negative and affirmative covenants that require, among other things, maintaining a specified current ratio and debt service ratio.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

Interest on Eurodollar loans is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the Credit Agreement, plus a margin where the margin varies from 2.500% to 3.500% depending on the utilization percentage of the conforming borrowing base. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate, as defined in our Credit Agreement, plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our Credit Agreement, plus 1%; plus a margin where the margin varies from 1.625% to 2.625%, depending on the utilization percentage of the borrowing base.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

Interest was paid at least every three months during 2009 and 2008. The effective rate of interest on the entire outstanding balance was 6.081% and 5.299% as of December 31, 2009 and 2008, respectively, and was based upon LIBOR.

 

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

 

•

incur additional indebtedness;

 

•

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

 

•

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

 

•

make investments in or loans to others;

 

•

change our line of business;

 

•

enter into operating leases;

 

•

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

 

•

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

 

•

enter into transactions with affiliates;

 

•

issue preferred stock;

 

•

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

 

•

enter into or terminate certain swap agreements;

 

•

amend our organizational documents; and

 

•

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

Our Credit Agreement requires us to maintain a current ratio, as defined in our Credit Agreement, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2009 and 2008, our current ratio as computed using GAAP was 1.38 and 1.34, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.51 and 1.19, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:

 

(dollars in thousands)		December 31, 2009				December 31, 2008
Current assets per GAAP		$	161,682			$	218,363
Plus—Availability under Credit Agreement			3,145				3,270
Less—Short-term derivative instruments			(18,226	)			(51,412	)
Less—Deferred tax asset on derivative instruments and asset retirement obligations			(1,079	)			—
Current assets as adjusted		$	145,522			$	170,221
Current liabilities per GAAP		$	117,529			$	163,123
Less—Short term derivative instruments			(20,677	)			—
Less—Deferred tax liability on derivative instruments and asset retirement obligations			—				(19,755	)
Less—Short-term asset retirement obligation			(300	)			(300	)
Current liabilities as adjusted		$	96,552			$	143,068
Current ratio for loan compliance			1.51				1.19

 

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The monetization of derivatives in the fourth quarter of 2008 and the first and second quarters of 2009 allowed us to exceed our required current ratio by a higher margin.

Prior to the amendment described below, the Seventh Restated Credit Agreement required us to maintain a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our Seventh Restated Credit Agreement, of not greater than 5.00 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007. As of March 31, 2007, we did not meet this ratio.

Effective May 11, 2007, the Seventh Restated Credit Agreement was amended to replace the Total Debt to EBITDAX ratio with a Consolidated Senior Total Debt to Consolidated EBITDAX ratio. For purposes of the amended ratio, Consolidated Senior Total Debt consisted of all outstanding loans under the Seventh Restated Credit Agreement, letters of credit and obligations under capital leases, as defined in the First Amendment to our Seventh Restated Credit Agreement. The amended Seventh Restated Credit Agreement required us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Seventh Restated Credit Agreement, of not greater than:

 

•

2.75 to 1.0 for the annualized periods commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007, June 30, 2007 and September 30, 2007 and for the four consecutive fiscal quarters ending on December 31, 2007; and

 

•

2.50 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2008 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.

The Seventh Restated Credit Agreement, as amended effective May 21, 2009, required us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX Ratio, as defined in the Fifth Amendment to our Seventh Restated Credit Agreement, of not greater than:

 

•

2.50 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2009; and

 

•

3.00 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2009, September 30, 2009, December 31, 2009, and March 31, 2010.

For purposes of the amended ratio, Consolidated Senior Total Debt consisted of all outstanding loans under the Seventh Restated Credit Agreement, letters of credit and obligations under capital leases, minus cash on hand in excess of accounts payable and accrued liabilities that are more than 90 days past the invoice date, as defined in the Fifth Amendment to our Seventh Restated Credit Agreement.

The Eighth Restated Credit Agreement requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX ratio, as defined in the Eight Restated Credit Agreement, of not greater than:

 

•

4.50 to 1.0 for the annualized periods commencing on April 1, 2010 and ending on the last day of the fiscal quarter ending on June 30, 2010, September 30, 2010, and December 31, 2010;

 

•

4.25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2011, June 30, 2011, and September 30, 2011; and

 

•

4.00 to 1.0 for the four consecutive fiscal quarters ending on December 31, 2011 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.

The Credit Agreement also specifies events of default, including:

 

•

our failure to pay principal or interest under the Credit Agreement when due and payable;

 

•

our representations or warranties proving to be incorrect, in any material respect, when made or deemed made;

 

•

our failure to observe or perform certain covenants, conditions or agreements under the Credit Agreement;

 

•

our failure to make payments on certain other material indebtedness when due and payable;

 

•

the occurrence of any event or condition that requires the redemption or repayment of, or an offer to redeem or repay, certain other material indebtedness prior to its scheduled maturity;

 

•

the commencement of a voluntary or involuntary proceeding seeking liquidation, reorganization or other relief, or the appointment of a receiver, trustee, custodian or other similar official for us or our subsidiaries, and the proceeding or petition continues undismissed for 60 days or an order approving the foregoing is entered;

 

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•

our inability, admission or failure generally to pay our debts as they become due;

 

•

the entry of a final, non-appealable judgment for the payment of money in excess of $5.0 million that remains undischarged for a period of 60 consecutive days;

 

•

a Change of Control (as defined in the Credit Agreement); and

 

•

the occurrence of a default under any permitted bond document, which such default continues unremedied or is not waived prior to the expiration of any applicable grace or cure under any permitted bond document.

If the outstanding borrowings under our Credit Agreement 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 natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.

Senior Notes

Senior Notes at December 31, 2009 and December 31, 2008 consisted of the following:

 

		December 31,
		2009				2008
8.5% Senior Notes due 2015		$	325,000			$	325,000
8.875% Senior Notes due 2017(1)			325,000				325,000
Discount on Senior Notes due 2017			(2,123	)			(2,325	)
		$	647,877			$	647,675

 

(1)	Upon completion of a qualified equity offering prior to February 1, 2012, we are entitled to redeem up to 35% of the aggregate principal amount of the 8 7 /8% Senior Notes from the proceeds, so long as:

 

•

we pay to the holders of such notes a redemption price of 108.875% of the principal amount of the 8  7/8% Senior Notes, plus accrued and unpaid interest to the date of redemption; and

 

•

at least 65% of the aggregate principal amount of the 8  7/8% Senior Notes remains outstanding after each such redemption, other than 8 7 /8% Senior Notes held by us or our affiliates.

As part of the indenture, we entered into a registration rights agreement in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for an issue of registered notes within 270 days of the closing date. The exchange offer was not completed within the 270-day period ending October 15, 2007 as required by the registration rights agreement. As a result, we accrued liquidated damages of $0.3 million during the year ended December 31, 2007. On February 29, 2008, we completed the exchange offer, and liquidated damages ceased to accrue as of that date. Total liquidated damages paid in 2008 were $0.4 million.

The Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries, as defined in the indentures.

On and after the fifth anniversary of the issue date, we may redeem some or all of the Senior Notes at any time at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption.

Prior to the fifth anniversary of the issue date, the Senior Notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indentures.

 

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

 

•

incur additional indebtedness;

 

•

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

 

•

make investments;

 

•

incur liens;

 

•

create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us;

 

•

engage in transactions with our affiliates;

 

•

sell assets, including capital stock of our subsidiaries; and

 

•

consolidate, merge or transfer assets.

As of December 31, 2009, we are not able to incur additional secured debt as a result of the ACNTA test under the Senior Notes.

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

Alternative capital resources

We have historically used cash flow from operations and debt financing as our primary sources of capital. As done on April 12, 2010, and as may be done in the future, we may use additional sources such as asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.

 

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Contractual obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2009:

 

(Dollars in thousands)(1)		Less than 1 year			1-3 years			3-5 years			More than 5 years			Total
Debt:
Revolving credit line—including estimated interest(2)		$	532,695		$	—		$	—		$	—		$	532,695
Senior notes, including estimated interest			56,469			112,938			112,938			735,414			1,017,759
Other long-term notes including estimated interest			5,548			6,627			2,739			15,552			30,466
Capital leases including estimated interest			265			134			—			—			399
Abandonment obligations			300			600			600			35,965			37,465
Derivative obligations			20,677			30,163			—			—			50,840
Purchase commitments			4,876			3,641			—			—			8,517
Total		$	620,830		$	154,103		$	116,277		$	786,931		$	1,678,141

 

(1)	As of December 31, 2009, we had no off-balance sheet arrangements.

(2)

On April 12, 2010, we sold 475,043 shares of our common stock to CCMP for a purchase price of $325.0 million. In connection with the closing of the sale, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement. As of April 14, 2010, we had $275.3 million of availability under our Eighth Restated Credit Agreement. See Note 14 to our consolidated financial statements for additional information regarding these transactions.

We have long-term contracts to purchase up to all of the CO₂ manufactured at two existing ethanol plants. Under one contract, we own the rights to purchase or otherwise take all of the plant’s CO₂ production, which is an average of approximately four MMcf per day. The contract’s ten-year term will begin upon our first purchase. We are currently purchasing approximately eight to ten MMcf per day of CO₂ under the second contract, and we expect to purchase an average of approximately 15 to 19 MMcf per day over the fifteen-year contract term, which began on May 1, 2009. There were no significant purchases under either of these contracts in 2009, 2008, or 2007. Pricing under both contracts is variable over time and both contracts have renewal language.

We have rights under two additional contracts that require us to purchase CO₂ for EOR projects. Under one of these contracts, we may purchase a variable amount of CO₂, up to 20 MMcf per day. We have historically taken approximately 10 MMcf per day under this contract, and we project we would purchase an average of approximately 16 MMcf per day over the remainder of the initial term of the contract, which expires in February 2011. Purchases under this contract were $0.8 million, $0.9 million, and $0.3 million during 2009, 2008, and 2007, respectively. The contract automatically renews for an additional ten years unless terminated by the other party in the event we fail to match a higher competing offer for the CO₂, or unless otherwise terminated by us. Under the second of these contracts, we currently purchase an average of approximately six MMcf per day of CO₂ and we have nominated to purchase ten MMcf per day of CO ₂ through 2011. Purchases under this contract, which include transportation charges, were $2.3 million, $2.3 million, and $1.5 million during 2009, 2008, and 2007, respectively. The contract expires in 2016. We may terminate or permanently reduce our purchase rate under this second additional contract at the end of any calendar year with 13 months notice. Pricing under both of these contracts is dependent on certain variable factors, including the price of oil.

 

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Results of operations

Overview

Production has increased in each of the last three years. However, oil and natural gas price volatility has had a significant impact on our revenues and cash flows from operations. Average sales prices and oil and natural gas sales decreased by 46% and 42%, respectively, from 2008 to 2009 after having increased by 31% and 37%, respectively, from 2007 to 2008. In addition, we recorded non-cash pre-tax ceiling test impairments of our oil and natural gas properties of $240.8 million and $281.4 million in 2009 and 2008, respectively. As a result of these and other transactions discussed below, our net loss increased $89.6 million from 2008 to 2009 and $50.0 million from 2007 to 2008.

 

		Year ended December 31,
		2009				2008				2007
Production (MBoe)			7,638				7,072				6,773
Oil and natural gas sales (in thousands)		$	292,387			$	501,761			$	365,958
Net loss (in thousands)		$	(144,318	)		$	(54,750	)		$	(4,793	)
Net loss per share (basic and diluted)		$	(164.56	)		$	(62.43	)		$	(5.47	)
Cash flow from operations (in thousands)		$	98,675			$	145,831			$	113,070

Revenues and production

The following table presents information about our oil and natural gas sales before the effects of hedging:

 

		Year ended December 31,						Percent increase			Year ended December 31,			Percent increase
		2009			2008			(decrease)			2007			(decrease)
Oil and natural gas sales (dollars in thousands)
Oil		$	213,207		$	348,907		(38.9	)%		$	234,428		48.8	%
Natural gas			79,180			152,854		(48.2	)%			131,530		16.2	%
Total		$	292,387		$	501,761		(41.7	)%		$	365,958		37.1	%
Production
Oil (MBbls)			3,874			3,773		2.7	%			3,356		12.4	%
Natural gas (MMcf)			22,584			19,795		14.1	%			20,504		(3.5	)%
MBoe			7,638			7,072		8.0	%			6,773		4.4	%
Average sales prices (excluding derivative settlements)
Oil per Bbl		$	55.04		$	92.47		(40.5	)%		$	69.85		32.4	%
Natural gas per Mcf		$	3.51		$	7.72		(54.5	)%		$	6.41		20.4	%
Boe		$	38.28		$	70.95		(46.0	)%		$	54.03		31.3	%

Oil and natural gas revenues decreased $209.4 million, or 42%, to $292.4 million during 2009 due to a 46% decrease in the average price per Boe, partially offset by an 8% increase in sales volumes. Oil and natural gas revenues increased $135.8 million, or 37%, to $501.8 million during 2008 due to a 31% increase in the average price per Boe and a 4% increase in sales volumes.

 

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

 

		Year ended December 31,
		2009 vs. 2008							2008 vs. 2007
(dollars in thousands)		Sales increase (decrease)				Percentage increase (decrease) in sales			Sales increase (decrease)				Percentage increase (decrease) in sales
Change in oil sales due to:
Prices		$	(145,040	)		(41.6	)%		$	85,350			36.4	%
Production			9,340			2.7	%			29,129			12.4	%
Total increase (decrease) in oil sales		$	(135,700	)		(38.9	)%		$	114,479			48.8	%
Change in natural gas sales due to:
Prices		$	(95,210	)		(62.3	)%		$	25,872			19.7	%
Production			21,536			14.1	%			(4,548	)		(3.5	)%
Total increase (decrease) in natural gas sales		$	(73,674	)		(48.2	)%		$	21,324			16.2	%

Oil and natural gas production for 2009 increased primarily due to our drilling program and enhancements of our existing properties, much of which was accomplished in 2008 and the first quarter of 2009. Oil production for 2008 increased primarily due to the addition of volumes from acquisitions, our expanded drilling program, and enhancements of our existing properties. Production volumes by area were as follows (MBoe):

 

		Year ended December 31,				Percent increase			Year ended December 31,		Percent increase
		2009		2008		(decrease)			2007		(decrease)
Mid-Continent		5,014		4,733		5.9	%		4,389		7.8	%
Permian Basin		1,600		1,145		39.7	%		1,047		9.4	%
Gulf Coast		461		564		(18.3	)%		631		(10.6	)%
Ark-La-Tex		260		291		(10.7	)%		317		(8.2	)%
North Texas		164		184		(10.9	)%		230		(20.0	)%
Rocky Mountains		139		155		(10.3	)%		159		(2.5	)%
Total		7,638		7,072		8.0	%		6,773		4.4	%

We have focused our capital expenditures in the Mid-Continent and Permian areas. As a result, production in our four growth areas has declined and is expected to continue to decline, since our planned capital expenditures for 2010 are also focused in our core areas of the Mid-Continent and Permian Basin.

The increase in production in the Permian area is primarily due to the Bowdle 47 No. 2, which began selling natural gas in late November 2008 and accounted for approximately 9% of total production for 2009. We expect production from this well to decline by approximately 52% in 2010. We are currently drilling an offset, the Bowdle 47 No. 4, which is expected to come online in the second quarter of 2010. If successful, this well, combined with several other high impact wells that we are currently drilling or participating in, will support our production levels throughout 2010. However, we cannot accurately predict the timing or level of future production.

 

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Derivative activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges. All of our derivative instruments are considered to be economic hedges regardless of whether they are designated as cash flow hedges for accounting purposes.

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

 

		Year ended December 31,
		2009				2008				2007
Oil (per Bbl):
Before derivative settlements		$	55.04			$	92.47			$	69.85
After derivative settlements		$	56.36			$	71.95			$	61.35
Post-settlement to pre-settlement price			102.4	%			77.8	%			87.8	%
Natural gas (per Mcf):
Before derivative settlements		$	3.51			$	7.72			$	6.41
After derivative settlements		$	5.32			$	7.38			$	6.80
Post-settlement to pre-settlement price			151.6	%			95.6	%			106.1	%

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

 

		As of December 31,
(dollars in thousands)		2009				2008			2007
Oil swaps		$	(68,551	)		$	111,416		$	(155,782	)
Natural gas swaps			30,340				13,312			4,709
Oil collars			12,290				57,716			—
Natural gas collars			14,065				21,682			—
Natural gas basis differential swaps			(14,964	)			1,618			539
Net derivative asset (liability)		$	(26,820	)		$	205,744		$	(150,534	)

During the fourth quarter of 2008, we determined that our natural gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding natural gas swaps. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income (loss), and the ineffective portion would have been included in the gain (loss) from oil and natural gas hedging activities, which is a component of revenue.

 

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In addition, we monetized certain oil and natural gas swaps and collars in 2009 and 2008. Certain swaps that were monetized had previously been accounted for as cash flow hedges. As of December 31, 2009 and 2008, accumulated other comprehensive income (loss) (“AOCI”) included $83.4 million and $23.7 million, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and natural gas hedging activities when the hedged production is sold.

The effects of derivative activities on our results of operations and cash flows were as follows:

 

		Year ended December 31,
		2009								2008								2007
(dollars in thousands)		Non-cash fair value adjustment				Cash receipts (payments)				Non-cash fair value adjustment				Cash receipts (payments)				Non-cash fair value adjustment				Cash receipts (payments)
Gain (loss) from oil and natural gas hedging activities:
Oil swaps		$	14,114			$	(2,349	)		$	7,770			$	(73,170	)		$	(6,636	)		$	(28,528	)
Natural gas swaps			7,638				—				4,779				(15,796	)			(1,707	)			8,731
Gain (loss) from oil and natural gas hedging activities		$	21,752			$	(2,349	)		$	12,549			$	(88,966	)		$	(8,343	)		$	(19,797	)
Non-hedge derivative gains (losses):
Oil swaps and collars		$	(30,791	)		$	7,490			$	80,297			$	(4,258	)		$	(24,416	)		$	—
Natural gas swaps and collars			9,455				46,100				24,144				3,086				—				—
Natural gas basis differential contracts			(16,582	)			(5,189	)			1,079				5,970				1,385				(750	)
Derivative monetizations			(111,188	)			111,874				(15,966	)			32,589				—				—
Non-hedge derivative gains (losses)		$	(149,106	)		$	160,275			$	89,554			$	37,387			$	(23,031	)		$	(750	)
Total gains (losses) from derivative activities		$	(127,354	)		$	157,926			$	102,103			$	(51,579	)		$	(31,374	)		$	(20,547	)

Due to the low oil prices prevalent during 2009, we received payments on oil derivatives of $5.1 million; however, we recognized non-cash losses on oil derivatives of $16.6 million in 2009 primarily due to the significant improvement in the NYMEX forward strip oil price as of December 31, 2009 compared to December 31, 2008. This includes gains of $14.5 million reclassified into earnings that are associated with derivatives for which hedge accounting was discontinued in 2008.

Due primarily to the low natural gas prices prevalent throughout 2009 and to lower average NYMEX forward strip gas prices as of December 31, 2009 compared to December 31, 2008, we recognized a gain on gas derivatives of $63.2 million in 2009. This includes gains of $7.7 million reclassified into earnings that are associated with derivatives for which hedge accounting was discontinued in 2008. Losses on natural gas basis differential contracts were $21.8 million during 2009, primarily due to lower differentials indicated by the forward commodity price curves as well as low differentials throughout 2009.

In addition, during the first quarter of 2009, we monetized natural gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. During the second quarter of 2009, we monetized additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. As a result of these monetizations, gains of $0.7 million were recognized in earnings, and gains of $81.9 million were deferred through AOCI.

Due primarily to the high commodity prices prevalent during the first nine months of 2008, we made payments on oil and natural gas derivatives of $77.4 million and $12.7 million, respectively. However, these losses were offset by non-cash gains on oil and natural gas derivatives of $88.1 million and $28.9 million, respectively, which resulted from the decline in the NYMEX forward strip oil and natural gas prices as of December 31, 2008 compared to December 31, 2007, and which included gains of $57.7 million and $21.7 million, respectively, on costless collars covering 1,666 MBbls of oil at a weighted average floor of $103.75 per Bbl and 6,540 BBtu of natural gas at a floor of $10.00 per MMBtu that were entered into during 2008 and remained outstanding as of December 31, 2008. Gains on natural gas basis differential swaps were $7.0 million in 2008, primarily due to high differentials during 2008.

In addition, during the fourth quarter of 2008, we monetized oil and natural gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. As a result of this monetization, gains of $16.6 million were recognized in earnings, and gains of $17.9 million were deferred through AOCI.

 

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Primarily as a result of higher average NYMEX forward strip oil prices during 2007 compared to 2006 and strong oil prices during 2007, losses on oil swaps were $59.5 million in 2007. These losses were partially offset by gains on natural gas swaps and natural gas basis differential swaps of $7.0 million and $0.6 million, respectively.

As a result of the above transactions, total gains (losses) on derivative activities recognized in our statements of operations were $30.6 million, $50.5 million, and ($51.9) million in 2009, 2008, and 2007, respectively.

Lease operating expenses

 

		Year ended									Year ended
(dollars in thousands)		December 31,						Percent			December 31,			Percent
		2009			2008			decrease			2007			increase
Lease operating expenses		$	94,155		$	120,547		(21.9	)%		$	104,469		15.4	%
Lease operating expenses per Boe		$	12.33		$	17.05		(27.7	)%		$	15.42		10.6	%

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. Our lease operating expenses decreased by 22% from 2008 to 2009 after having increased by 15% from 2007 to 2008, which is consistent, though not commensurate, with the changes in commodity prices during the same periods. Commodity prices have recently started to improve, and if this upward trend continues, we expect absolute and per Boe operating costs to increase as well.

Due primarily to higher production mostly associated with the Bowdle 47 No. 2 well, the shut-in of uneconomic wells, and our efforts to reduce production costs, lease operating expenses for 2009 decreased by $26.4 million, or $4.72 per Boe, compared to 2008. Per unit expenses were lower for all categories of lease operating expenses due to downward pressure on service costs, labor, and materials resulting from the low commodity prices prevalent throughout 2009. Electricity and fuel costs and workover costs decreased by $4.4 million and $8.3 million, respectively, for operated properties from 2008 to 2009.

During 2008, lease operating expenses increased $16.1 million, or $1.63 per Boe, compared to 2007, primarily due to increases in the number of net producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Per unit expenses were higher for all categories of lease operating expenses due to upward pressure on service costs, labor and materials resulting from the strength of commodity prices during the first nine months of 2008. Electricity and fuel costs and workover costs increased by $4.0 million and $1.8 million, respectively, for operated properties from 2007 to 2008.

Production taxes (which include ad valorem taxes)

 

		Year ended									Year ended
		December 31,						Percent			December 31,			Percent
(dollars in thousands)		2009			2008			decrease			2007			increase
Production taxes		$	20,341		$	33,815		(39.8	)%		$	26,216		29.0	%
Production taxes per Boe		$	2.66		$	4.78		(44.4	)%		$	3.87		23.5	%

Production taxes generally change in proportion to oil and natural gas sales. The decrease in production taxes from 2008 to 2009 was primarily due to the 46% decrease in average realized prices, partially offset by an 8% increase in production volumes. The increase in production taxes from 2007 to 2008 was due primarily to the 31% increase in average realized prices and the 4% increase in production volumes.

 

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Depreciation, depletion and amortization (“DD&A”) and losses on impairment

 

		Year ended						Percent			Year ended
		December 31,						increase			December 31,			Percent
(dollars in thousands)		2009			2008			(decrease)			2007			increase
Total DD&A:
Oil and natural gas properties		$	92,561		$	91,316		1.4	%		$	78,717		16.0	%
Property and equipment			8,510			6,644		28.1	%			4,322		53.7	%
Accretion of asset retirement obligation			2,927			2,712		7.9	%			2,392		13.4	%
Total DD&A		$	103,998		$	100,672		3.3	%		$	85,431		17.8	%
DD&A per Boe:
Oil and natural gas properties		$	12.12		$	12.91		(6.1	)%		$	11.62		11.1	%
Other fixed assets			1.50			1.33		12.8	%			0.99		34.3	%
Total DD&A per Boe		$	13.62		$	14.24		(4.4	)%		$	12.61		12.9	%

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $1.2 million from 2008 to 2009. Higher production volumes increased DD&A by $7.3 million, which was offset by a $6.1 million reduction in DD&A due to a lower rate per equivalent unit of production. Our DD&A rate per equivalent unit of production decreased $0.79 to $12.12 per Boe primarily due to the decrease in capitalized costs resulting from the ceiling test impairments recorded in the fourth quarter of 2008 and the first quarter of 2009, combined with lower estimated future development costs for proved undeveloped reserves. DD&A on oil and natural gas properties increased $12.6 million from 2007 to 2008. Higher production volumes increased DD&A by $3.5 million, and an increase in the rate per equivalent unit of production increased DD&A by $9.1 million. Our DD&A rate per equivalent unit of production increased $1.29 to $12.91 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.

Our DD&A expense for property and equipment increased in both 2008 and 2009 primarily due to drilling rigs that were acquired and placed into service in 2008 and the expansion of our corporate office space during 2008.

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

Impairment of oil and natural gas properties. In accordance with the full-cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties.

During the fourth quarter of 2008, we recorded a ceiling test impairment of oil and natural gas properties of $281.4 million as a result of a decline in oil and natural gas prices at the measurement date. The impairment was calculated based on December 31, 2008 spot prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. The effect of derivative contracts accounted for as cash flow hedges, based on the December 31, 2008 spot prices, increased the full-cost ceiling by $192.1 million, thereby reducing the ceiling test write down by the same amount.

During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to our PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and natural gas properties of $240.8 million during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169.0 million, thereby reducing the ceiling test write down by the same amount.

 

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As of December 31, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties by $294.2 million, and no additional ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $61.18 per Bbl of oil and $3.87 per Mcf of gas for the year ended December 31, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these average prices, increased the full cost ceiling by $25.5 million. The qualifying cash flow hedges as of December 31, 2009, which consisted of commodity price swaps, covered 3,741 MBbls of oil production for the period from January 2010 through December 2011. See Note 4 to our consolidated financial statements for a further discussion of hedging activity.

A decline in oil and natural gas prices subsequent to December 31, 2009 could result in additional ceiling test write downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

Impairment of ethanol plant. We owned a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. Oklahoma Ethanol LLC retained a financial advisor to arrange project financing to fund construction costs and for related start-up working capital. Because financing did not close by September 15, 2008, the minority owner, Oklahoma Sustainable Energy LLC, was no longer able to participate in the joint venture, and we now own 100% of Oklahoma Ethanol LLC. The City of Blackwell was also unable to obtain financing for the railroad upgrades and storage facilities that would be necessary to support ethanol production. During the third quarter of 2008, we determined that we would be unlikely to obtain equity capital or new project financing for an ethanol plant. We accordingly recorded an impairment charge of $2.9 million, which was the amount of our investment in the ethanol plant.

General and administrative expenses (“G&A”) and litigation settlement

 

		Year ended								Percent			Year ended				Percent
		December 31,								increase			December 31,				increase
(dollars in thousands)		2009				2008				(decrease)			2007				(decrease)
Gross G&A expenses		$	34,565			$	33,552			3.0	%		$	32,652			2.8	%
Capitalized exploration and development costs			(10,824	)			(11,180	)		(3.2	)%			(10,814	)		3.4	%
Net G&A expenses		$	23,741			$	22,372			6.1	%		$	21,838			2.4	%
Average G&A cost per Boe		$	3.11			$	3.16			(1.6	)%		$	3.22			(1.9	)%
Full-time employees as of December 31			689				859			(19.8	)%			726			18.3	%

G&A expenses increased $1.4 million from 2008 to 2009, primarily due to higher deferred compensation costs. Due to a reduction in the fair value of our phantom stock during 2008, we recognized a deferred compensation gain which reduced G&A expenses by $0.3 million. The fair value of our phantom stock increased during 2009, and deferred compensation expense increased G&A expenses by $1.0 million in 2009. G&A expenses increased $0.5 million from 2007 to 2008, primarily due to an increase in our office staff and related requirements caused by the increase in our level of activity. On a per Boe basis, G&A decreased by 2% in both 2009 and 2008 as higher production more than offset the increase in costs.

Litigation settlement—Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This case was related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”).

Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7.1 million, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $0.4 million contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.

As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14.4 million, and was included in other assets on the consolidated balance sheet. As of December 31, 2008, the recorded payable related to the Tax Election was $4.4 million, and was included in accounts payable and accrued liabilities on the consolidated balance sheet. As a result of the settlement, as of December 31, 2009, the receivable related to the Working Capital Adjustment and the Tax Election payable were eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2.9 million.

 

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Other income and expenses

Interest expense. Interest expense increased by $4.1 million, or 5%, from 2008 to 2009 primarily as a result of increased levels of borrowings accompanied by slightly higher interest rates. Interest expense decreased by $1.6 million, or 2%, from 2007 to 2008 primarily as a result of lower interest rates, partially offset by increased levels of borrowings. The following table presents interest expense:

 

		Year ended December 31,
(dollars in thousands)		2009			2008			2007
Revolver interest		$	26,950		$	23,574		$	27,387
8 1/2 % Senior Notes due 2015			28,415			28,348			28,285
8 7/8 % Senior Notes due 2017			29,601			29,578			28,413
Bank fees and other interest			5,136			4,538			3,571
Total interest expense		$	90,102		$	86,038		$	87,656
Average long-term borrowings		$	1,216,540		$	1,178,243		$	1,057,142

Merger costs and termination fee. On October 9, 2009, we entered into an Agreement and Plan of Reorganization with United Refining Energy Corp. (“United”) under which we would merge with United, a publicly held Special Purpose Acquisition Company, in a reverse merger. The merger was to be accounted for as a reverse recapitalization, whereby we would be the continuing entity for financial reporting purposes and would be deemed, for accounting purposes, to be the acquirer of United. On December 11, 2009, United announced that the merger did not receive the stockholder vote required for approval, and the Agreement and Plan of Reorganization was terminated. As a result, costs of $2.2 million associated with the merger were expensed.

On July 14, 2008, we entered into an Agreement and Plan of Merger (“Merger Agreement”) with Edge Petroleum Corporation (“Edge”), whereby Edge would merge with and into our wholly owned subsidiary, Chaparral Exploration, L.L.C. During the fourth quarter of 2008, the parties concluded that it was highly unlikely that all of the closing conditions set forth in the Merger Agreement would be met, and therefore the merger would not be consummated on or prior to December 31, 2008, the date on which either party could, subject to the terms of the Merger Agreement, terminate the Merger Agreement unilaterally. As a result, we and Edge executed a Merger Termination Agreement on December 16, 2008, and costs of $1.4 million associated with the merger were expensed.

On July 14, 2008, we entered into a Stock Purchase Agreement with Magnetar Financial LLC (“Magnetar”), which provided for Magnetar and its affiliates to purchase 1.5 million shares of our Series B convertible preferred stock for an aggregate purchase price of $150.0 million. On December 16, 2008, we executed a Termination and Settlement Agreement (the “Magnetar Termination Agreement”) with Edge and Magnetar, which terminated the Stock Purchase Agreement. Pursuant to the Magnetar Termination Agreement, Magnetar paid a total of $5.0 million, of which $1.5 million was paid to Edge at our direction to reimburse Edge for certain expenses, and $3.5 million was paid to us and recorded as a termination fee.

Production tax credits. During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments were accounted for as a production tax benefit asset and were netted against tax credits realized in other income using the effective yield method over the expected recovery period. Other income for 2009, 2008, and 2007 includes Oklahoma production tax credits of $13.5 million, $0.7 million, and $0.8 million, respectively. This source of income will not be available in future periods.

 

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Income taxes

 

		Year ended December 31,
(dollars in thousands)		2009				2008				2007
Current income tax benefit		$	23			$	28			$	16
Deferred income tax benefit			89,872				35,273				3,370
Total income tax benefit		$	89,895			$	35,301			$	3,386
Effective tax rate			37.3	%			38.6	%			36.4	%
Total net deferred tax asset (liability)		$	64,212			$	(62,395	)		$	1,632

Our income tax provision was based on an estimated statutory rate of approximately 39% in 2009, 2008 and 2007. Our effective tax rate has generally been less than our estimated statutory rate due to the impact of our deduction for statutory depletion and other adjustments.

As of December 31, 2009, our federal and state net operating loss carryforwards were approximately $235.4 million and $214.9 million, respectively, and will begin to expire in 2010. As of December 31, 2009, approximately $103.3 million of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized.

Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

Discontinued operations

Discontinued operations consist of third-party revenue and operating expenses of GCS, which was acquired on April 16, 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services to oil and natural gas operators primarily in Oklahoma, Texas, and Wyoming. Operating expenses consist of costs of sales related to product sales and general and administrative expenses.

During the second quarter of 2009, we committed to a plan to sell the assets of GCS, and on May 14, 2009, we entered into an agreement to sell the assets of the ESP division of GCS to Global Oilfield Services, Inc. (“Global”) for a cash price of approximately $24.6 million after working capital adjustments as provided in the agreement. We paid off notes payable attributed to certain assets sold to Global in the amount of $1.6 million, and recorded a pre-tax gain associated with the sale of $9.1 million.

On December 11, 2009, we entered into an agreement with Reef Services, LLC (“Reef”) under which we exchanged the assets of the Chemicals division of GCS for the assets of the Reef Acid Division and cash of $0.7 million. The assets received consist primarily of acid trucks and related equipment and have an estimated fair value of approximately $3.0 million. This transaction is considered a non-monetary exchange accounted for at fair value. We paid off notes payable attributed to certain assets sold to Reef in the amount of $0.3 million, and recorded a pre-tax gain associated with the exchange of $1.3 million.

The operating results of GCS have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below:

 

										April 16, 2007
		Year ended December 31,								through December 31,
(dollars in thousands)		2009				2008				2007
Revenues		$	11,142			$	33,821			$	20,611
Operating expenses			(10,983	)			(31,450	)			(18,852	)
Gain on sale			10,449				—				—
Income before income taxes			10,608				2,371				1,759
Income tax provision			3,959				915				641
Income from discontinued operations		$	6,649			$	1,456			$	1,118

 

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There were no assets held for sale or liabilities associated with discontinued operations as of December 31, 2009. At December 31, 2008, the assets and liabilities of GCS are classified as assets held for sale and liabilities associated with discontinued operations, respectively, on our consolidated balance sheet.

Critical accounting policies and estimates

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

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

Derivative instruments. Certain of our oil and natural gas derivative contracts are designed to be treated as cash flow hedges under GAAP. This policy significantly impacts the timing of revenue or expense recognized from this activity, as our contracts are adjusted to their fair value at the end of each month. The effective portion of the hedge gain or loss, meaning the portion of the change in the fair value of the contract that offsets the change in the expected future cash flows from our forecasted sales of production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) from oil and natural gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the effective portion of change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in stockholders’ equity. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) from oil and natural gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment, or have not been designated as cash flow hedges, are marked to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.

We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and natural gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. In certain less liquid markets, forward prices are not as readily available. In these circumstances, swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3 in accordance with the fair value hierarchy defined by the Financial Accounting Standards Board (“FASB”). We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2. We determine fair value for our oil and natural gas collars using an option pricing model which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for our collars, we have determined that all of our collars’ fair value measurements are categorized as Level 3. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.

Oil and natural gas properties.

 

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

 

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Proved oil and natural gas reserves quantities. Proved oil and natural gas reserves are the quantities of crude oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance.

 

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Our proved reserve information included in this report is based on estimates prepared by Cawley, Gillespie & Associates, Inc., Ryder Scott Company, L.P., and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 82% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2009, and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

 

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Depreciation, depletion and amortization. The quantities of proved oil and natural gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based on the relative energy content.

 

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Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and natural gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10%, adjusted for the impact of derivatives accounted for as cash flow hedges, plus the lower of cost or fair market value of unproved properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues exclude escalations based upon future conditions. If oil and natural gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that write downs of our oil and natural gas properties could occur in the future.

 

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

 

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

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

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

Income taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

 

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Valuation allowance for NOL carryforwards. In computing our income tax expense, we assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss, or NOL, carryforwards. For federal income tax purposes these NOL carryforwards expire 15 to 20 years from the year of origination. We generally assess our ability to fully utilize these carryforwards by estimating expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report and by analyzing the expected reversal of existing deferred tax liabilities. These computations are imprecise due to the extensive use of estimates and assumptions. Each quarter we assess our ability to utilize NOL carryforwards. We will record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such asset will not be realized.

Recent accounting pronouncements

In January 2010, the FASB issued new authoritative guidance regarding “Improving Disclosures about Fair Value Measurements and Disclosures” that requires additional disclosure of transfers in and out of Level 1 and 2 measurements and the reasons for the transfers, and a gross presentation of activity within the Level 3 roll forward. The guidance also includes clarifications to existing disclosure requirements on the level of disaggregation and disclosures regarding inputs and valuation techniques. The guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. We will adopt the guidance on January 1, 2010, except for requirements regarding the gross presentation of Level 3 roll forward information, which we will adopt on January 1, 2011. Because this guidance only requires additional disclosures, it is not expected to have a significant impact on our financial statements.

In December 2008, the SEC issued its Modernization of Oil and Gas Reporting, which revises reserves requirements for oil and natural gas companies. The most significant amendments to the requirements include the following:

 

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economic producibility of reserves and discounted cash flows is now estimated using an average price for oil and natural gas based upon the first day of each month for the prior twelve months rather than prices on the last day of the reporting period;

 

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proved reserves may be estimated through the use of new technologies if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes;

 

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reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years;

 

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additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process and the internal controls used to assure the objectivity of the reserves estimate; and

 

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probable and possible reserves may be disclosed separately on a voluntary basis.

In January 2010, the Financial Accounting Standards Board also issued guidance regarding Oil and Gas Reserve Estimation and Disclosures to provide consistency with the new SEC rules. The new guidance amends existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules.

We adopted the new SEC reserves requirements and GAAP reserves guidance as a change in accounting principle that is inseparable from a change in estimate, and applied the guidance prospectively effective December 31, 2009. See Note 16 to our financial statements for a discussion of the impact of these changes on our reserves.

See Note 1 to the financial statements for a discussion of additional accounting pronouncements adopted during 2009.

Effects of inflation and pricing

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

 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and natural gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities.

Based on our production for the year ended December 31, 2009, our gross revenues from oil and natural gas sales would change approximately $2.3 million for each $0.10 change in natural gas prices and $3.9 million for each $1.00 change in oil prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into commodity price swaps, costless collars, and basis protection swaps. For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. Our collars have not been designated as hedges. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. We do not designate these instruments as hedges; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

Our outstanding oil and natural gas derivative instruments as of December 31, 2009 are summarized below:

 

		Crude oil swaps										Crude oil collars
		Hedge					Non-hedge					Non-hedge
		Volume MBbl		Weighted average fixed price to be received			Volume MBbl		Weighted average fixed price to be received			Volume MBbl		Weighted average range			Percent of PDP production(1)
1Q 2010		520		$	68.13		102		$	65.80		60		$	110.00 - $168.55		78.2	%
2Q 2010		516			68.06		90			65.47		60			110.00 -   168.55		79.0	%
3Q 2010		499