10-K 1 d10k.htm FORM 10-K Form 10-K
Table of Contents
Index to Financial Statements

 

 

 

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, 2008

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  x    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.

877,000 shares of the registrant’s common stock were outstanding as of March 30, 2009.

 

 

 


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Index to Financial Statements

CHAPARRAL ENERGY, INC.

Index to Form 10-K

 

Part I

  

Items 1. and 2. Business and Properties

   5

Item 1A. Risk Factors

   24

Item 1B. Unresolved Staff Comments

   33

Item 2. Properties

   33

Item 3. Legal Proceedings

   33

Item 4. Submission of Matters to a Vote of Security Holders

   34

Part II

  

Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

   35

Item 6. Selected Financial Data

   36

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

   37

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

   60

Item 8. Financial Statements and Supplementary Data

   63

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   98

Item 9A. Controls and Procedures

   98

Item 9B. Other Information

   99

Part III

  

Item 10. Directors, Executive Officers and Corporate Governance

   100

Item 11. Executive Compensation

   102

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

   112

Item 13. Certain Relationships and Related Transactions, and Director Independence

   112

Item 14. Principal Accounting Fees and Services

   115

Part IV

  

Item 15. Exhibits and Financial Statement Schedules

   116

Signatures

   119

 

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, management’s plans, strategies, goals and objectives for future operations and growth.

These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of our senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements.

Forward-looking statements may relate to various financial and operational matters, including, among other things:

 

   

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

 

   

the amount, nature and timing of capital expenditures;

 

   

drilling of wells;

 

   

competition and government regulations;

 

   

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

 

   

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

 

   

increases in proved reserves;

 

   

operating costs and other expenses;

 

   

cash flow and anticipated liquidity;

 

   

estimates of proved reserves;

 

   

exploitation or property acquisitions;

 

   

marketing of oil and natural gas; and

 

   

general economic conditions and the other risks and uncertainties discussed in this report.

Undue reliance should not be placed on forward-looking statements, which speak only as of the date of this report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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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.

 

Bcfe

One billion cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf 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.

 

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.

 

Fully developed finding, development and acquisition cost (FD&A)

Total costs incurred plus the increase (decrease) in future development costs divided by total proved reserve acquisitions, extensions and discoveries, improved recoveries, and revisions.

 

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.

 

MBbl

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

 

Mcf

One thousand cubic feet of natural gas.

 

Mcfe

One thousand cubic feet of natural gas equivalents.

 

MMBbl

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

 

MMBtu

One million British thermal units.

 

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MMcf

One million cubic feet of natural gas.

 

MMcfe

One million cubic feet of natural gas equivalents.

 

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.

 

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, using prices and costs in effect at the determination date, 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.

 

Proved reserves

The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 

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.

 

Secondary recovery

The recovery of oil and 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.

 

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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 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, 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 predecessor, Chaparral L.L.C. 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

Chaparral Energy, Inc.

We are an independent oil and natural gas production and exploitation company headquartered in Oklahoma City, Oklahoma. Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include additional areas of Gulf Coast, Ark-La-Tex, North Texas, and the Rocky Mountains.

As of December 31, 2008, we had estimated proved reserves of 680.1 Bcfe (74% proved developed and 45% crude oil) with a PV-10 value of approximately $932.7 million. For the year ended December 31, 2008, our average daily production was 115.9 MMcfe with an estimated reserve life of 16 years. For the year ended December 31, 2008, our oil and gas revenues were $501.8 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 17.

For the period from 2004 to 2008, our proved reserves and production grew at a compounded annual growth rate of 12% and 22%, respectively. We have grown primarily through 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. We currently expect our future growth to continue through a combination of developmental drilling, acquisitions, and exploitation projects, complemented by a modest amount of exploration activities.

For the year ended December 31, 2008, we made capital expenditures of $302.7 million, including $171.0 million for developmental drilling and $45.9 million for acquisitions. The majority of our capital expenditures for developmental drilling in 2008 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.

Due to the current reduced prices for oil and natural gas, we plan to keep our 2009 exploration and development expenditures within cash flow. The 2009 capital budget represents an 83% reduction in capital expenditures from our 2008 levels. Despite this reduction, we expect production for 2009 to remain at levels comparable to 2008 as a result of capital investments made in 2008 and the first quarter of 2009. However, if conditions do not improve and we are unable to expand our capital expenditure budget in 2010, we would expect production to decline at a rate consistent with our production decline curve.

Business Strengths

Consistent track record of reserve additions and production growth. From 2004 to 2008, we have grown proved reserves and production by a compounded annual growth rate of 12% and 22%, respectively. We have achieved this through a combination of drilling and acquisition success. 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 599% per year since 2002. We replaced approximately 1,165%, 372%, and 200% of our production in 2006, 2007, and 2008, respectively.

 

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Our average fully developed FD&A cost over the period 2006 through 2008 was $7.21 per Mcfe. Excluding the effects from downward price revisions and reduced future development costs that occurred during 2008, our three-year average fully developed FD&A cost was $3.73 per Mcfe.

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 2006, 2007 and 2008, our capital expenditures for acquisitions of proved properties were $484.4 million, $41.7 million and $39.2 million, respectively. These acquisition capital expenditures represented approximately 73%, 18%, and 13%, respectively, of our total capital expenditures and approximately 94%, 13%, and 17%, respectively, of our increase in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries for those periods. As part of our plan to keep capital expenditures within cash flow, we have not budgeted any significant amounts for acquisitions in 2009.

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 the December 31, 2008 prices of $44.60 per Bbl of oil and $5.62 per Mcf of gas, we had an inventory of over 644 proved developmental drilling locations. Utilizing management’s estimated prices of $60.00 per Bbl of oil and $6.00 per Mcf of gas, we had an inventory of 1,921 additional potential drilling locations, which combined represent over 16 years of drilling opportunities based on our 2009 drilling rate.

 

     Identified
proved
undeveloped
drilling
locations
   Identified
additional
potential
drilling
locations
   Developed
Acreage
Net
   Undeveloped
Acreage
Net

Mid-Continent

   489    1,026    383,168    66,041

Permian Basin

   34    396    54,447    19,171

Gulf Coast

   7    43    43,231    14,340

Ark-La-Tex

   7    17    14,772    —  

North Texas

   15    364    19,733    6,731

Rocky Mountains

   92    75    14,691    2,611
                   

Total

   644    1,921    530,042    108,894
                   

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 98% on a weighted average basis during 2006, 2007 and 2008. For the year ended December 31, 2008, we spent $176.1 million of developmental drilling and exploration costs to drill 80 (73 net) operated wells and to participate in 246 (6 net) wells operated by others, representing 78% of our additions to reserves. For 2009, we have budgeted $38.0 million to drill more than 40 operated wells and to participate in more than 100 wells operated by others.

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

 

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reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of six engineers that have substantial expertise in CO2 EOR operations, and we also have specific software for modeling CO2 EOR. We own a 29% interest in and operate a large CO2 EOR unit in southern Oklahoma and installed and operate a second CO2 EOR unit with a 54% interest in the Oklahoma panhandle. At December 31, 2008, our proved reserves included six properties where CO2 EOR recovery methods are used, which comprise approximately 6% 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 mid 1980’s before being shut down due to low prevailing oil prices. We initiated polymer injection in this unit in a pilot program in December 2007. In the pilot area, we believe we are seeing production response as production has increased from 90 Bbls of oil per day to 130 Bbls of oil per day. We plan to expand this polymer EOR program and ultimately introduce CO2 injection into this unit.

Experienced management team. Mark A. Fischer, our Chief Executive Officer and founder who beneficially owns 42.5% of our outstanding common stock, has operated in the oil and gas industry for 36 years after starting his career at Exxon as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 29 years of experience in the oil and gas industry. Individuals in our 23-person management team have an average of over 29 years of experience in the oil and gas industry.

Business Strategy

We seek to grow reserves and production profitably through a balanced mix of developmental drilling, acquisitions, enhancements, 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 development drilling program. During the year ended December 31, 2008, we spent approximately $171.0 million on development drilling, which represents 56% 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 development (infill or single stepout) wells. We currently plan to spend $38.0 million, or approximately 75% of our capital expenditures, on developmental drilling in 2009.

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. In 2006, we also made a larger acquisition that complemented our existing properties in our core areas. During the year ended December 31, 2008, we made approximately $39.2 million of proved reserve acquisitions, or 13% of our total capital expenditures. As part of our plan to keep capital expenditures within cash flow, we have not budgeted any significant amounts for acquisitions in 2009.

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 Company 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 17 field offices throughout Oklahoma, Texas and Louisiana. 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 of December 31, 2008, we had an inventory of 806 enhancement projects requiring total estimated capital expenditures of $69.4 million.

Expand CO2 EOR activities. As of December 31, 2008, we have accumulated interests in 61 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria for CO2 EOR operations and we are expanding

 

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our CO2 pipeline system to initiate CO2 injection in certain of these properties. We began CO2 injection in our Perryton Unit in December 2006 and will begin CO2 injection in our Booker Area Units in the second quarter of 2009 and in our NW Camrick Unit in 2010. To support our existing CO2 EOR projects, we currently inject approximately 33.4 MMcf per day of purchased and recycled CO 2. We have 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 and operate the 23-mile Purdy to Velma CO2 pipeline, and a 100% interest in approximately 126 miles of pipeline located between Liberal, Kansas and Booker, Texas. We have installed compression facilities to capture approximately 16 MMcf per day of CO2 from the Arkalon ethanol plant and expect to initiate injection of this CO2 into the Booker area fields in the second quarter of 2009.

Pursue modest exploration program. In the current low-priced commodity environment, we do not plan to spend any significant amount on exploratory activities.

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 gas production to maximize both volumes and wellhead price. As of December 31, 2008, we operated properties comprising approximately 82% 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, 2008, we had commodity price swaps, costless collars, and basis protection swaps in place for approximately 50% of our most recent internally estimated proved developed gas production for 2009 through 2011. We also had commodity price swaps and costless collars in place for approximately 66% of our most recent internally estimated proved developed oil production for 2009 through 2013. While our derivative activities protect our cash flows during periods of commodity price declines, we recorded losses on derivative activities of $8.8 million and $51.9 million for the years ended December 31, 2006 and 2007, respectively, through a period of increasing commodity prices. For the year ended December 31, 2008, we recorded a gain on derivative activities of $50.5 million. In December 2008, we received proceeds of $32.6 million from the monetization of derivative contracts which had original settlement dates from January through June 2009.

Properties

The following table presents our proved reserves and PV-10 value as of December 31, 2008 and average daily production for the year ended December 31, 2008 by our areas of operation.

 

     Proved reserves as of December 31, 2008    Average
daily
production
(MMcfe
per day)
Year ended
December 31,
2008
     Oil
(MBbl)
   Natural
gas
(MMcf)
   Total
(MMcfe)
   Percent
of total
MMcfe
    PV-10
value
($mm)
  

Mid-Continent

   40,449    244,062    486,756    71.5 %   $ 636.7    77.6

Permian Basin

   5,740    66,829    101,269    14.9 %     163.8    18.8

Gulf Coast

   1,551    34,593    43,899    6.5 %     78.7    9.2

Ark-La-Tex

   712    15,828    20,100    3.0 %     18.4    4.8

North Texas

   1,692    4,839    14,991    2.2 %     21.9    3.0

Rocky Mountains

   1,139    6,215    13,049    1.9 %     13.2    2.5
                                

Total

   51,283    372,366    680,064    100 %   $ 932.7    115.9
                                

 

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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 gas properties is geographically diversified, 83% of our 2008 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, 2008, we owned interests in 8,324 gross (2,741 net) producing wells and we operated wells representing approximately 82% 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, 2008, accounted for 72% of our proved reserves and 68% of our PV-10 value. We own a working interest in 5,393 producing wells in the Mid-Continent Area, of which we operate 2,024. The Mid-Continent Area has fifteen of our top twenty largest properties in terms of PV-10 value. During the year ended December 31, 2008, our net average daily production in the Mid-Continent Area was approximately 77.6 MMcfe per day, or 67% 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.

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 MMBbl of oil (primary and secondary). The North Burbank Unit accounted for 47,113 MMcfe of our proved reserves, $27.9 million of our PV-10 value as of December 31, 2008 and 3,316 (2,726 net) MMcfe of our year ended December 31, 2008 production. The producing zones are the Red Fork and Bartlesville and occur at a depth of 3,000 feet. We own 99.25% of the field and are also the operator. As of December 31, 2008, the field was producing 1,510 (1,242 net) Bbls of oil per day from 277 producing wells. There are also 187 active injection wells and 483 temporarily abandoned wells at December 31, 2008. 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 1980-1986 as a project on 1,440 acres. 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 90 Bbls of oil per day to 130 Bbls of oil per day as of December 31, 2008. Since taking over the field on November 1, 2006, we have returned 70 temporarily abandoned wells to production with initial rates of production ranging between 6 and 25 Bbls of oil per day. We believe that this field also may have upside with the injection of CO2.

South Burbank Unit—Osage County, Oklahoma. 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 4,386 acres. It was discovered in 1934 and unitized in 1935. The South Burbank Unit has produced 56.7 MMBbls of oil from the Burbank Sand from both primary and waterflood 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 deeper Mississippi Chat, which occurs some 50 feet below the shallower Burbank Sand, and to the shallower 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. Four wells have been drilled and completed in the Mississippi Chat and are proving successful with initial potentials as high as 87 Bbls of oil per day. Three wells have been drilled and completed in the shallower Burbank Sand and are also proving successful with initial potentials ranging between 17 and 30 Bbls of oil per day. We drilled five of these wells in this area in 2008. We currently have a Company-owned drilling rig working full time in this area and expect to drill ten wells in 2009. Any well drilled inside the South Burbank Unit is being developed with a pattern and spacing plan that will maximize any future EOR efforts.

 

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Camrick area—Beaver and Texas Counties, Oklahoma and Ochiltree County, Texas. The Camrick area represented approximately 4% of our proved reserves and 3% of our PV-10 value (29,433 MMcfe and $30.2 million, respectively) at December 31, 2008. This area consists of three unitized fields, the Camrick Unit, which covers 9,080 acres, the NW Camrick Unit, which covers 4,080 acres and the Perryton Unit, which covers 2,040 acres. We currently operate these three fields with an average working interest of 54%. Production in the Camrick area is from the Morrow reservoir that occurs at a depth of approximately 6,800 feet. The three units have produced approximately 16.6 MMBbls of primary reserves and approximately 13.1 MMBbls of secondary reserves. There were 47 active producing wells in this area that produced 3,019 (1,475 net) MMcfe during the year ended December 31, 2008. 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 (690 Mcfe) per day in 2001 from 11 wells to approximately 1,435 (775 net) Bbls of oil (8,610 Mcfe) per day as of December 31, 2008 from 47 producing wells. We plan to continue expansion of CO2 injection operations across all of the units.

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma. SWAGSU represented 6% of our proved reserves and 8% of our PV-10 value (38,472 MMcfe and $77.9 million, respectively) at December 31, 2008. 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 260.2 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 1966, 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 34 active producing wells in this unit as of December 31, 2008. We are scheduled to drill five wells in 2009.

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Play accounted for 20,508 MMcfe of our proved reserves and $41.9 million of our PV-10 value as of December 31, 2008. We own approximately 6,600 net acres in the Cleveland Sand Play. The Cleveland Sand occurs at 8,300 feet and is considered a tight gas sand reservoir. As of December 31, 2008, we own interests in 31 Cleveland Sand producing wells. We drilled five wells in 2007 and four wells in 2008. We employed horizontal drilling technology in most of our drilled wells in this area. We expect that future wells will also utilize horizontal technology.

Granite Wash Horizontal Play—Washita County, Oklahoma. The objective target of this play is the Des Moinesian Granite Wash “A”, “B” and “C” 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 utilize a lateral drilled up to 4,000 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 recently drilled a new well, the Roxanne 1-17H, in which we have a 25% working interest, which came on line at rates of 3,906 (793 net) Mcf of natural gas per day and 365 (74 net) Bbls of oil per day. We participated in six wells in this play in 2008 and we expect to drill and/or participate in the drilling of an additional three Granite Wash horizontal wells in 2009.

Anadarko Basin Woodford Shale Play-Western Oklahoma. As of December 31, 2008, we have a significant acreage position in the emerging Woodford Shale Resource Play of western Oklahoma. We own and control approximately 380,000 gross acres and 77,700 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 11,500 feet to 16,000 feet. The horizontal development of this non-conventional resource

 

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play began in 2007 in Canadian County and has expanded to include the nearby counties of Blaine, Grady and Caddo with over 30 Woodford targeted wells drilled to date. Gas in place is estimated to be between 145 to 200 Bcf per section with initial development well density to be four wells per section. The average recovery is expected to be five to eight Bcf per well at an average cost of seven to nine million dollars. Operators in the play have reported initial daily production rates in the range of five to eight MMcf of gas per day per well.

Velma Sims Unit CO2 Flood—Stephens County, Oklahoma. The EVWB Sims Sand 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. This unit accounted for 12,397 MMcfe of our proved reserves and $8.9 million of our PV-10 value as of December 31, 2008. Waterflood operations began in 1972. Hydrocarbon gas injection ended around 1977 and a miscible CO2 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, 2008, we had 47 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 had proved reserves of 1,684 MMcfe and a PV-10 value of $1.2 million at December 31, 2008. 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 14 MMBbls of oil and, as of December 31, 2008, the unit has 64 producing wells and 46 active injection wells. The unit is currently producing 370 (247 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 a depth of 9,000 feet, and has recovered 39 MMBbls of oil to date. This unit represents 8,764 MMcfe of our proved reserves and $7.6 million of our PV-10 value at December 31, 2008. There are currently 26 producing wells and 13 active injection wells, with current production of approximately 236 (137 net) Bbls of oil per day. We operate the field with a working interest of 64%. 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. We plan to initiate CO2 injection in three Booker units in 2009 and in our NW Camrick Unit in 2010. On December 31, 2008, we had in place transportation and supply agreements to provide the necessary CO2 for these projects. We have accumulated 61 properties in Oklahoma, Kansas, New Mexico and Texas that meet the criteria for CO2 EOR operations. We have a 100% ownership in our 86-mile Borger CO2 pipeline, own a 29% interest in the 120-mile Enid to Purdy CO2 pipeline, own a 58% interest in and operate the 23-mile Purdy to Velma CO2 pipeline, and own a 100% interest in approximately 126 miles of pipeline located between Liberal, Kansas and Booker, Texas. We have installed compression facilities to capture approximately 16 MMcf per day of CO2 from the Arkalon ethanol plant and expect to initiate injection of this CO2 into the Booker area fields in the second quarter of 2009. Arrangements to secure additional sources of CO2 are currently in process. The U.S. Department of Energy-Office of Fossil Energy provided a report in April 2005 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, 2008, accounted for 15% of our proved reserves and 18% of our PV-10 value. We own an interest in 1,604 wells in the Permian Basin, of which we operate 337. Three of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2008, our net average daily production in the Permian Basin Area was approximately 18.8 MMcfe per day, or 16% 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 19,840 acres. We operate these wells with a working interest of 100%. The Tunstill Field Play represents 13,787 MMcfe of our proved reserves and $28.4 million of our PV-10 value at December 31, 2008. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 5,200 feet and the Cherry Canyon Sands that occur at depths from 4,300 to 5,200 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. During 2007, we drilled eight wells in this play. We drilled 16 wells in 2008 and plan to drill two wells in 2009.

Haley Area Play—Loving County, Texas. The Haley Area—Bone Springs, Atoka, Strawn and Morrow play encompasses 3,840 gross acres. We own interests in and operate 11 producing wells in this play. The Haley Area represents 28,329 MMcfe of our proved reserves and $43.7 million of our PV-10 value at December 31, 2008. Production has been established from four main intervals: (1) the Bone Springs at a depth of approximately 10,100 to 11,000 feet; (2) the Strawn at a depth of approximately 15,500 feet; (3) the Atoka at a depth of approximately 16,000 feet; and (4) the Morrow at a depth of approximately 17,700 feet. Two of the existing wells are completed in the Atoka, two are completed in the Strawn, four wells are completed in the Morrow and three are completed in the Bone Springs. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Atoka/Strawn/Morrow commingled interval with some initial potentials of 20 to 30 MMcfe per day. We recently drilled the Bowdle 47 No. 2 to test the Morrow and Atoka intervals. This well began selling gas in late November 2008, and is currently producing at approximately 15.5 MMcfe per day gross and 11.2 MMcfe net to our interests. We are currently pipeline limited and pipeline construction is underway that should allow the Bowdle 47 No. 2 to produce at even higher rates. We expect to drill an offset to the Bowdle 47 No. 2 well in the fourth quarter of 2009. We also drilled the F.D. Russell #2 well which encountered several Atoka sands and came on-line in April 2008. This well is currently producing at approximately two MMcf per day.

Gulf Coast

The Gulf Coast Area is the most active of our four growth areas and, as of December 31, 2008, accounted for 6% of our proved reserves and 9% of our PV-10 value. We own an interest in 185 wells in the Gulf Coast Area, of which we operate 121. 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—Nueces County, TX. We own interests in approximately 3,405 net producing acres and 10,020 net non-producing acres. Multiple producing sand intervals are found from depths of 6,500 feet to 8,000 feet. We now operate six active producing wells in this area. As of December 31, 2008, the wells in Nueces County, Texas account for 1,303 MMcfe of our proved reserves and $2.6 million of our PV-10 value. We are currently processing a 51-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.

 

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Ark-La-Tex

As of December 31, 2008, the Ark-La-Tex Area accounted for 3% of our proved reserves and 2% of our PV-10 value. We own an interest in 104 wells in the Ark-La-Tex Area, of which we operate 52. These reserves are characterized by shorter life and higher initial potential. Most of our activity is centered in the Jewitt Field where we are participating with another party and drilled 16 wells in 2008.

North Texas

As of December 31, 2008, the North Texas Area accounted for 2% of our proved reserves and 2% of our PV-10 value. We own an interest in 865 wells in the North Texas Area, of which we operate 108.

Rocky Mountains

As of December 31, 2008, the Rocky Mountains Area accounted for 2% of our proved reserves and 1% of our PV-10 value. We own an interest in 173 wells in the Rocky Mountains Area, of which we operate 39.

Oil and Natural Gas Reserves

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2008. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (68% of PV-10 value) and by Ryder Scott Company, L.P. (7% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on the remaining smaller value properties (25% of PV-10 value).

 

     Net proved reserves
     Oil
(MBbl)
   Natural
gas
(MMcf)
   Total
(MMcfe)
   PV-10 value
(In thousands)

Developed—producing

   31,145    214,016    400,886    $ 641,194

Developed—non-producing

   9,237    49,315    104,737      143,398

Undeveloped

   10,901    109,035    174,441      148,100
                     

Total proved

   51,283    372,366    680,064    $ 932,692
                     

The estimated reserve life as of December 31, 2006, 2007 and 2008 was 28.0, 24.3 and 16.0 years, respectively. The estimated reserve life was calculated by dividing total proved reserves by production volumes for the year indicated. The shorter reserve life of 16 years in 2008 was primarily a result of reduced proven reserves associated with the lower end of year 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)

   2006    2007    2008

Future net revenue

   $ 3,518,020    $ 6,203,720    $ 1,918,270

PV-10 value

     1,494,063      2,671,982      932,692

Standardized measure of discounted future net cash flows

     1,082,209      1,793,980      755,013

Oil price (per Bbl)

   $ 61.06    $ 96.01    $ 44.60

Natural gas price (per Mcf)

   $ 5.64    $ 6.80    $ 5.62

 

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Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

The following table sets forth information at December 31, 2008 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 wells.

 

     Total wells
     Gross    Net

Crude oil

   6,188    2,071

Natural gas

   2,136    670
         

Total

   8,324    2,741
         

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, 2008 by area.

 

     Total wells    Operated
Wells
     Gross    Net   

Mid-Continent

   5,393    2,043    2,024

Permian Basin

   1,604    373    337

Gulf Coast

   185    113    121

Ark-La-Tex

   104    47    52

North Texas

   865    126    108

Rocky Mountains

   173    39    39
              

Total

   8,324    2,741    2,681
              

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2008 by area.

 

     Developed    Undeveloped
     Gross    Net    Gross    Net

Mid-Continent

   898,743    383,168    77,704    66,041

Permian Basin

   78,188    54,447    20,467    19,171

Gulf Coast

   71,959    43,231    22,402    14,340

Ark-La-Tex

   26,920    14,772    —      —  

North Texas

   25,525    19,733    7,827    6,731

Rocky Mountains

   43,518    14,691    3,252    2,611
                   

Total

   1,144,853    530,042    131,652    108,894
                   

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 gas reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find and produce oil or gas in an unproved area, to

 

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find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir beyond one location. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.

 

     2006     2007     2008  
     Gross     Net     Gross     Net     Gross     Net  

Development wells

            

Productive

   189.0     56.1     214.0     51.7     319     74.9  

Dry

   1.0     0.2     3.0     1.2     4.0     2.0  

Exploratory wells

            

Productive

   1.0     1.0     6.0     5.9     3.0     2.2  

Dry

   1.0     0.1     0.0     0.0     0.0     0.0  

Total wells

            

Productive

   190.0     57.1     220.0     57.6     322.0     77.1  

Dry

   2.0     0.3     3.0     1.2     4.0     2.0  
                                    

Total

   192.0     57.4     223.0     58.8     326.0     79.1  
                                    

Percent productive

   99 %   99 %   99 %   98 %   99 %   97 %

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 prices in effect on December 31, 2006, 2007 and 2008), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2006 and 2007 were prepared by Cawley, Gillespie & Associates, Inc. (36% of PV-10 value in 2007), and Lee Keeling & Associates, Inc. (52% of PV-10 value in 2007). Estimates of our net proved oil and natural gas reserves as of December 31, 2008 were prepared by Cawley, Gillespie & Associates, Inc. (68% of PV-10 value), and Ryder Scott Company, L.P. (7% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (12% and 25% of PV-10 value in 2007 and 2008, respectively).

 

     As of December 31,  

Proved Reserves

   2006     2007     2008  

Oil (Mbbl)

     88,378       99,104       51,283  

Natural gas (MMcf)

     375,311       392,269       372,366  

Natural gas equivalent (MMcfe)

     905,579       986,893       680,064  

Proved developed reserve percentage

     69 %     65 %     74 %

PV-10 value (in thousands)

   $ 1,494,063     $ 2,671,982     $ 932,692  

Estimated reserve life (in years)(1)

     28.0       24.3       16.0  

Cost incurred (in thousands):

      

Property acquisition costs

      

Proved properties(2)

   $ 484,404     $ 41,724     $ 39,201  

Unproved properties

     4,731       8,032       6,677  
                        

Total acquisition costs

     489,135       49,756       45,878  

Development costs(3)

     170,987       165,177       251,690  

Exploration costs

     7,015       15,287       5,108  
                        

Total

   $ 667,137     $ 230,220     $ 302,676  
                        

Annual reserve replacement ratio(4)

     1,165 %     372 %     200 %

Three-year average fully developed FD&A cost ($/Mcfe)(5)

   $ 2.37     $ 3.00     $ 7.21  

 

(1) Calculated by dividing net proved reserves by net production volumes for the year indicated.
(2) Includes $464.9 million of costs related to the acquisition of Calumet Oil Company (“Calumet”) in 2006, and $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 $16.1 million of costs related to the construction of a compressor station and CO2 pipeline in 2008.

(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 17 of the notes to our consolidated financial statements. In calculating reserves replacement, we do not use unproved reserve

 

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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,  
     2006     2007     2008  
     Reserves
replaced
    Percent
of total
    Reserves
replaced
    Percent
of total
    Reserves
replaced
    Percent
of total
 

Purchases of minerals in place

   1,093 %   93.8 %   46 %   12.5 %   35 %   17.2 %

Extensions and discoveries

   52 %   4.4 %   214 %   57.4 %   155 %   77.6 %

Improved recoveries

   20 %   1.8 %   112 %   30.1 %   10 %   5.2 %
                                    

Total

   1,165 %   100.0 %   372 %   100.0 %   200 %   100 %
                                    

 

(5) Calculated as costs incurred, plus the change in future development costs, divided by total reserve additions as shown below (in Mcfe unless otherwise noted):

 

     2006     2007     2008(6)  

Purchases of minerals in place

     354,004       18,850       14,569  

Extensions and discoveries

     16,736       86,788       65,813  

Revisions

     (56,423 )     (28,684 )     (348,118 )

Improved recoveries

     6,653       45,423       4,380  
                        

Total reserve additions

     320,970       122,377       (263,356 )
                        

Costs incurred

   $ 667,137     $ 230,220     $ 302,676  

Changes in future development costs

     236,700       337,438       (476,201 )
                        

Total

   $ 903,837     $ 567,658     $ (173,525 )
                        

Three-year average fully developed FD&A cost ($/Mcfe)

   $ 2.37     $ 3.00     $ 7.21  

 

(6) Excluding the reduction in reserve quantities resulting from downward price revisions and the reduction in future development costs that occurred during the year, our three-year average fully developed FD&A cost was $3.73 per Mcfe.

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,
     2006    2007    2008

Production:

        

Oil (MBbls)

     1,906      3,356      3,773

Gas (MMcf)

     20,949      20,504      19,795
                    

Combined (MMcfe)

     32,385      40,640      42,433

Average daily production:

        

Oil (Bbls)

     5,222      9,195      10,309

Gas (Mcf)

     57,395      56,175      54,085
                    

Combined (Mcfe)

     88,727      111,345      115,939

Average prices (before effect of hedges):

        

Oil (per Bbl)

   $ 61.65    $ 69.85    $ 92.47

Gas (per Mcf)

     6.29      6.41      7.72
                    

Combined (per Mcfe)

   $ 7.69    $ 9.00    $ 11.82

Average costs per Mcfe:

        

Lease operating

   $ 2.21    $ 2.57    $ 2.84

Production taxes

   $ 0.58    $ 0.65    $ 0.80

Depreciation, depletion, and amortization

   $ 1.61    $ 2.10    $ 2.37

General and administrative

   $ 0.45    $ 0.54    $ 0.53

 

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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, 2008 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, 2008 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

   $ 636.7    $ 111.5    $ 525.2

Permian Basin

     163.8      37.9      125.9

Gulf Coast

     78.7      19.7      59.0

Ark-La-Tex

     18.4      2.3      16.1

North Texas

     21.9      4.8      17.1

Rocky Mountains

     13.2      1.5      11.7
                    

Total

   $ 932.7    $ 177.7    $ 755.0
                    

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, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) non-cash deferred compensation expense (gain), (8) gain or loss on disposed assets, and (9) impairment charges.

 

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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 mirrors the Consolidated EBITDAX ratio 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 generally accepted accounting principles and, accordingly, it may not be a comparable measurement to those used by other companies. The following table provides a reconciliation of net income (loss) to adjusted EBITDA for the specified periods:

 

     Year Ended December 31,  
     2006     2007     2008  

Net income (loss)

   $ 23,806     $ (4,793 )   $ (54,750 )

Interest expense

     45,246       87,656       86,038  

Income tax expense (benefit)

     14,817       (2,745 )     (34,386 )

Depreciation, depletion, and amortization

     52,299       85,842       101,973  

Unrealized (gain) loss on ineffective portion of hedges

     (18,761 )     8,343       (12,549 )

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

     4,592       23,031       (89,554 )

Interest income

     (555 )     (755 )     (409 )

Non-cash deferred compensation expense (gain)

     82       831       (306 )

Gain on disposed assets

     (132 )     (712 )     (177 )

Loss on impairment of oil and gas properties

     —         —         281,393  

Loss on impairment of ethanol plant

     —         —         2,900  
                        

Adjusted EBITDA

   $ 121,394     $ 196,698     $ 280,173  
                        

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 has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.

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

Markets

The marketing of oil and natural gas produced by us 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;

 

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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 gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of 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.

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;

 

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impose substantial liabilities for pollution resulting from our operation; 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 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 gas industry could have a significant impact on our operating costs.

We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may affect our properties or operations. For the years ended December 31, 2007 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 2009 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 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 natural gas and oil projects.

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 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 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

 

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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 joint and several liability, without regard to fault or legality of conduct, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies 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 or under 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.

Air Emissions

The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In 2007, the U.S. Supreme Court issued a decision that EPA has authority to regulate greenhouse gas emissions pursuant to the Clean Air Act. Massachusetts v. EPA, 549 U.S. 497 (2007). Additionally, the 2007 Omnibus Spending bill mandated that EPA promulgate regulations requiring mandatory monitoring and reporting of greenhouse gas emissions by June 2009 pursuant to authority provided by the Clean Air Act. EPA proposed its mandatory greenhouse gas monitoring and reporting rule in 2009. These regulations, if promulgated, will require mandatory monitoring and reporting of greenhouse gas emissions from natural gas processing and transmission compression facilities, including fugitive methane emissions and carbon dioxide emissions from flares used to control fugitive methane emissions, exceeding regulatory emission threshold criteria. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital

 

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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 that we are in substantial compliance with the current requirements of the Clean Air Act.

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 certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and 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 Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and 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 gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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

Drilling and Production

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

 

   

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.

 

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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 gas to point-of-sale locations.

Natural Gas Pipeline Safety

The Department of Transportation, specifically the Pipeline and Hazardous Materials Safety Administration, regulates transportation of natural and other gas by pipeline and imposes minimum federal safety standards pursuant to the pipeline safety laws codified at 49 U.S.C. 60101, et seq. and the hazardous material transportation laws codified at 49 U.S.C. 5101, et seq. We believe that we are currently in substantial compliance with the requirements of these various regulatory requirements mandating federal minimum safety criteria for transporting natural and other gas and hazardous materials via pipeline.

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

 

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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.

Title to properties

We believe that we have satisfactory title to all of our owned assets. As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to undeveloped leasehold acreage rights acquired through oil and 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 gas properties, we conduct due diligence as to title for the specific interest we are acquiring. Our interests in natural gas and oil 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, 2008, we had 859 full-time employees, including 14 geologists and geophysicists, 29 reservoir, production, and drilling engineers and 15 land professionals. Of these, 307 work in our Oklahoma City office and 552 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.

 

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.

 

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Worldwide demand for oil and natural gas appears to be declining, which could materially reduce our profitability and cash flow.

Based on a number of economic indicators, it appears that growth in global economic activity has slowed substantially. At the present time, the rate at which the global economy will slow has become increasingly uncertain. A slowing of global economic growth will likely reduce demand for oil and natural gas, increase spare productive capacity and result in lower oil and natural gas prices, which will reduce our cash flow from operations.

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 amount of our cash flow we have available for capital expenditures and 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:

 

   

the level of consumer demand for oil and natural gas;

 

   

the domestic and foreign supply of oil and natural gas;

 

   

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

 

   

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

 

   

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

 

   

domestic and foreign governmental regulations and taxes;

 

   

the price and availability of alternative fuel sources;

 

   

weather conditions;

 

   

financial and commercial market uncertainty;

 

   

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

 

   

worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Oil and natural gas prices have declined significantly over the past year and may continue to decline. Our profitability is directly related to the prices we receive for the sale of the oil and natural gas we produce. In early July 2008, commodity prices reached levels in excess of $140.00 per Bbl for crude oil and $13.00 per Mcf for natural gas. Market prices currently are in the range of $50.00 per Bbl for crude oil and $4.00 per Mcf for natural gas, a decline of approximately 64% and 69%, respectively, from earlier highs. As a result, our revenue from oil and gas sales is expected to decline significantly in 2009 as compared with 2008. Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that 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, our Senior Notes, or make planned capital expenditures.

 

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Price declines at the end of 2008 resulted in a write down 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 net income and stockholders’ equity.

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 future net revenues attributable to proved oil and natural gas reserves discounted at 10%, 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 prices for oil and natural gas at that date as adjusted for our cash flow hedge positions.

During the fourth quarter of 2008, we recorded a non-cash 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 prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas.

Prices have remained volatile subsequent to December 31, 2008. This and other factors, without other mitigating circumstances, could cause a future further write down of capitalized costs and a non-cash charge against future earnings.

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, 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 believe that we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results most likely will vary from our estimates. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions 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 development 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 from the development and production of oil and 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 as of the date of the estimates. 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, 2008 future cash flows used realized prices based on a Henry Hub spot price of $5.62 per Mcf for natural gas and a WTI Cushing spot price of $44.60 per Bbl for oil.

A significant portion of total proved reserves as of December 31, 2008 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2008, approximately 26% 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

 

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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.

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

As of December 31, 2008, 6% 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 in the production levels we anticipate. 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.

Our level of indebtedness may adversely affect our operations and limit our growth. We may have difficulty making debt service payments on our indebtedness as such payments become due.

As of December 31, 2008, our total debt was $1,271.6 million. Our maximum commitment amount and the borrowing base under our Seventh Restated Credit Agreement (the “Credit Agreement”) was redetermined to be $600.0 million as of December 24, 2008. Covenants set forth in the indentures for our 8 1/2% Senior Notes and the 8 7/8 % 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. Based on the commodity prices for crude oil and natural gas at year end, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $320.0 million.

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

 

   

a significant portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

 

   

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

 

   

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;

 

   

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

 

   

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

 

   

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

If an event of default occurs under our Credit Agreement or our Senior Notes, the lenders or noteholders may declare the principal, premium, if any, accrued and unpaid interest, and liquidated damages, if any, on such indebtedness to be due and payable.

 

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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 redetermined to be $600.0 million as of December 24, 2008, 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 every six months. 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 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 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 condition.

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. We face intense competition from both major and other independent oil and natural gas companies:

 

   

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

 

   

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

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

Significant capital expenditures are required to replace our reserves.

Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations 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 an economic basis 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.

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 26% of our total estimated proved reserves (by volume) at December 31, 2008 were

 

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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, 2008 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 17.0%, 11.4% and 10.8% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

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 drilled by us 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 produced economically. 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:

 

   

unexpected drilling conditions;

 

   

title problems;

 

   

pressure or lost circulation in formations;

 

   

equipment failures or accidents;

 

   

adverse weather conditions;

 

   

compliance with environmental and other governmental requirements; and

 

   

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

We are subject to complex laws and regulations, including environmental and safety regulations, that 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:

 

   

land use restrictions;

 

   

drilling bonds and other financial responsibility requirements;

 

   

spacing of wells;

 

   

reporting or other limitations on emissions of greenhouse gases;

 

   

unitization and pooling of properties;

 

   

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

 

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well stimulation processes;

 

   

produced water disposal;

 

   

safety precautions;

 

   

operational reporting; and

 

   

taxation.

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

 

   

personal injuries;

 

   

property and natural resource damages;

 

   

oil spills and releases or discharges of hazardous materials;

 

   

well reclamation costs;

 

   

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

 

   

other environmental damages; and

 

   

reporting or other issues arising from greenhouse gas emissions.

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. Additionally, 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.

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

To reduce our exposure to decreases in the price of oil and natural gas, we may use fixed-price swaps, collars and option contracts traded on the NYMEX, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions or other similar transactions. As of December 31, 2008, we had entered into swaps for 25,590 MMcf of our natural gas production for 2009 through 2011 at average monthly prices ranging from $6.97 to $8.03 per Mcf of natural gas. We also entered into collars for 6,540 MMcf of our natural gas production for 2009 through 2010 at $10.00 per Mcf. As of December 31, 2008, we had entered into swaps for 7,196 MBbl of our crude oil production for 2009 through 2013 at average monthly prices ranging from $63.17 to $124.66 per Bbl of oil. We also entered into collars for 1,666 MBbl of our crude oil production for 2009 through 2013 ranging from $100.00 to $110.00 per Bbl of oil. As of December 31, 2008, we had basis protection swaps for 29,790 MMcf of our natural gas production for 2009 through the first quarter of 2011 at average monthly prices ranging from $0.88 to $1.02 per Mcf. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2008 was an asset of approximately $205.7 million. Derivative instruments expose us to risk of financial loss in some circumstances, including when:

 

   

our production is less than expected;

 

   

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

 

   

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

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, 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,

 

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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 loss from oil and 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 is 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 is 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.

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. Although we currently do not, and do not anticipate that we will in the future, enter into derivative contracts that require an initial deposit of cash collateral, our working capital could be impacted if we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

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 gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices. However, 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 preclosing 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. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our 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.

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

We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our Chief Executive Officer, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. These persons include the executive officers listed in Item 10 under “Directors, Executive Officers and Corporate Governance.” Our ability to hire and retain our officers and key employees 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.

 

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If Mark A. Fischer ceases to be our Chairman, Chief Executive Officer, or President in connection with a change of control, such event could also result in a change of control event occurring under our Credit Agreement, the indenture governing our outstanding Senior Notes or our Phantom Plan.

Oil and natural gas drilling and producing 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:

 

   

injury or loss of life;

 

   

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

 

   

pollution or other environmental damage;

 

   

clean-up responsibilities;

 

   

regulatory investigations and administrative, civil and criminal penalties; and

 

   

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

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease prior to the date we acquire them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities. Moreover, in the future, we may not be able to obtain such insurance coverage at premium levels that justify its purchase.

Costs of environmental liabilities could exceed our estimates.

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

 

   

the uncertainties in estimating clean up costs;

 

   

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

 

   

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

 

   

future changes to environmental laws and regulations.

Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties.

We are subject to financing and interest rate exposure risks.

Our future success depends on our ability to access capital markets and obtain financing at cost-effective rates. Our ability to access financial markets and obtain cost-effective rates in the future are dependent on a number of factors, many of which we cannot control, including changes in:

 

   

our credit ratings;

 

   

interest rates;

 

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the structured and commercial financial markets;

 

   

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

 

   

tax rates due to new tax laws.

All of the outstanding borrowings under our Credit Agreement as of December 31, 2008 were subject to market rates of interest as determined from time to time by the banks. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $600.0 million, equal to our borrowing base at December 31, 2008, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $6.0 million.

The soundness of financial institutions could place our cash deposits at risk.

Current market conditions also elevate the concern over our cash accounts. Our cash investments and deposits with any financial institution that exceed the amount insured by the Federal Deposit Insurance Corporation are at risk in the event one of these financial institutions should fail.

The concentration of accounts for our oil and 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 concentration of sales of oil and natural gas commensurate 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 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.

 

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 14, “Commitments and Contingencies,” to the Consolidated Financial Statements. Such information is incorporated herein by reference.

 

ITEM 3.    LEGAL PROCEEDINGS

Pursuant to the securities purchase agreement dated as of September 16, 2006, as amended, relating to the acquisition of Calumet, we recorded a receivable due from the sellers related to the post-closing purchase price adjustment for working capital. On August 9, 2007, we received a communication from the sellers disputing the calculation of the purchase price adjustment. We believe the receivable was calculated in accordance with the securities purchase agreement and intend to diligently

 

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defend our position. On September 13, 2007, we filed a petition in the District Court of Tulsa County, State of Oklahoma, against John Milton Graves Trust u/t/a 6/11/2004, et al, seeking a declaratory judgment confirming this position, and amended our petition on December 1, 2008 to clarify that we are also seeking recovery of the purchase price adjustment amount under a breach of contract theory. The sellers responded by filing a counterclaim seeking approximately $4.4 million related to an election under the federal tax code. Discovery in the lawsuit is proceeding, and mediation is scheduled in the second quarter of 2009. As of December 31, 2007 and 2008, the recorded receivable was approximately $14.4 million and was recorded in other assets on the consolidated balance sheet. As of December 31, 2007 and 2008, the recorded payable related to the election under the federal tax code was $4.4 million and was included in accounts payable and accrued liabilities on the consolidated balance sheet.

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.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On October 16, 2008, our stockholders adopted certain resolutions by written consent related to our expected merger with Edge Petroleum Corporation. The resolutions approved the adoption of certain of Edge’s equity incentive plans and the adoption of a long-term incentive plan for the Company. These resolutions were contingent upon the closing of the merger. Because the merger was terminated and never closed, these resolutions never became effective.

 

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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 March 30, 2009, we had 877,000 shares of common stock outstanding held by three 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, 2008 were 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 amounts)

   2004     2005     2006     2007     2008  

Operating results data:

          

Revenues

          

Oil and gas sales

   $ 113,546     $ 201,410     $ 249,180     $ 365,958     $ 501,761  

Loss from oil and gas hedging activities

     (21,350 )     (68,324 )     (4,166 )     (28,140 )     (76,417 )

Service company sales

     —         —         —         20,611       34,272  
                                        

Total revenues

     92,196       133,086       245,014       358,429       459,616  
                                        

Costs and expenses

          

Lease operating

     26,928       42,147       71,663       104,469       120,487  

Production taxes

     8,272       14,626       18,710       26,216       33,815  

Depreciation, depletion and amortization

     17,533       31,423       52,299       85,431       100,528  

Loss on impairment of oil & gas properties

     —         —         —         —         281,393  

Loss on impairment of ethanol plant

     —         —         —         —         2,900  

General and administrative

     5,985       9,808       14,659       21,838       22,370  

Service company expenses

     —         —         —         18,852       31,656  
                                        

Total costs and expenses

     58,718       98,004       157,331       256,806       593,149  
                                        

Operating income (loss)

     33,478       35,082       87,683       101,623       (133,533 )
                                        

Non-operating income (expense)

          

Interest expense

     (6,162 )     (15,588 )     (45,246 )     (87,656 )     (86,038 )

Non-hedge derivative gains (losses)

     —         —         (4,677 )     (23,781 )     126,941  

Termination fee

     —         —         —         —         3,500  

Merger costs

     —         —         —         —         (1,400 )

Other income

     279       665       792       2,276       1,394  
                                        

Net non-operating income (expense)

     (5,883 )     (14,923 )     (49,131 )     (109,161 )     44,397  
                                        

Income (loss) before income taxes and minority interest

     27,595       20,159       38,552       (7,538 )     (89,136 )

Income tax expense (benefit)

     9,880       7,309       14,817       (2,745 )     (34,386 )

Minority interest

     —         —         (71 )     —         —    
                                        

Net income (loss)

   $ 17,715     $ 12,850     $ 23,806     $ (4,793 )   $ (54,750 )
                                        

Net income (loss) per share (basic and diluted)

   $ 22.86     $ 16.58     $ 29.74     $ (5.47 )   $ (62.43 )
                                        

Weighted average number of shares used in calculation of basic and diluted earnings per share

     775,000       775,000       800,500       877,000       877,000  

Cash flow data:

          

Net cash provided by operating activities

   $ 46,870     $ 55,744     $ 89,154     $ 113,443     $ 146,914  

Net cash used in investing activities

     (92,141 )     (325,068 )     (703,804 )     (239,442 )     (263,988 )

Net cash provided by financing activities

     54,061       257,080       621,855       128,883       157,499  
     As of December 31,  

(Dollars in thousands expect per share amounts)

   2004     2005     2006     2007     2008  

Financial position data:

          

Cash and cash equivalents

   $ 13,842     $ 1,598     $ 8,803     $ 11,687     $ 52,112  

Total assets

     308,827       647,379       1,331,435       1,530,898       1,712,836  

Total debt

     176,622       446,544       976,272       1,114,237       1,271,589  

Retained earnings

     48,692       58,126       80,883       76,090       21,340  

Accumulated other comprehensive income (loss), net of income taxes

     (12,107 )     (47,967 )     (3,946 )     (73,839 )     82,133  

Total equity

     36,586       10,167       177,864       103,178       204,400  

Cash dividends per common share

     —       $ 4.40     $ 1.35       —         —    

 

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

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report.

Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

Overview

We are an independent oil and natural gas company engaged in the production, acquisition and exploitation 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. As of December 31, 2008, we had estimated proved reserves of 680.1 Bcfe, with a PV-10 value of $932.7 million. Our reserves were 74% proved developed reserves and 45% crude oil. Our estimated proved reserves have decreased significantly since December 31, 2007 due to a decrease in price from $96.01 per Bbl and $6.80 per Mcf in 2007 to $44.60 per Bbl and $5.62 per Mcf, in 2008. As of December 31, 2007, we had estimated proved reserves of 986.9 Bcfe with a PV-10 value of $2.7 billion, of which 65% were proved developed reserves and 60% 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 gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles 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 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 17.0%, 11.4% and 10.8% 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 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 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 gas reserves; and

 

   

operating results for oil and gas activities.

We believe the most significant, subjective or complex estimates we make in preparation of our financial statements are:

 

   

the amount of estimated future net revenues from oil and gas sales;

 

   

the quantity of our proved oil and gas reserves;

 

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the timing and amount of future drilling, development and abandonment activities;

 

   

the value of our derivative positions;

 

   

the realization of deferred tax assets; and

 

   

the full cost ceiling limitation.

We base our estimates on historical experience and various assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates.

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. Due to the recent turmoil in the market and the sharp decline in oil and natural gas prices during the fourth quarter of 2008, we plan to keep our capital expenditures within our cash flow for 2009.

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

 

   

Current Market Conditions. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit market crisis includes our revolving credit facility, counterparty risks related to our trade credit and derivative instruments, and risks related to our cash investments.

Our cash accounts and deposits with any financial institution that exceed the amount insured by the Federal Deposit Insurance Corporation are at risk in the event one of these financial institutions should fail. As of December 31, 2008, cash with a recorded balance totaling $49.1 million was held at JP Morgan Chase Bank, N.A.

We sell our crude oil, natural gas and natural gas liquids to a variety of purchasers. Some of these parties may experience liquidity problems. Nonperformance by a trade creditor could result in losses. We also have significant net derivative assets that are held by affiliates of our lenders. As of December 31, 2008, approximately 88% of our net derivative asset of $205.7 million was held by JP Morgan Chase Bank, N.A., Calyon Credit Agricole CIB, and The Royal Bank of Scotland plc.

Our oil and gas sales revenues are derived from the sale of oil, natural gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and the demand for, oil and natural gas. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and natural gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil producing countries, and governmental regulation, legislation and policies.

Oil and natural gas prices declined significantly during the fourth quarter of 2008, which will reduce our cash flows from operations in future periods in which prices remain at or below the current levels. The commodity price swaps and costless collars that cover approximately 66% of our expected PDP oil production through December 2013 and approximately 50% of our expected PDP natural gas production through December 2011 will, however, become more valuable if prices continue to decline.

 

   

Credit Facility. Our current credit facility is a revolving credit facility in the amount of $600.0 million. At December 31, 2008, we had $594.0 million outstanding under the revolving credit facility and $2.7 million was utilized by outstanding letters of credit. The borrowing base is subject to redetermination on May 1, 2009. If the outstanding borrowings under the Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess.

 

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The revolving credit facility is scheduled to mature on October 31, 2010. Should current credit market volatility be prolonged, future extensions of our credit facility may contain terms that are less favorable than those of our current credit facility. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability, and we may not meet the required Current Ratio, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

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. Based on the commodity prices for crude oil and natural gas at year end, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $320.0 million.

 

   

Impairment of oil and gas properties. In accordance with the full-cost method of accounting, the net capitalized costs of oil and 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 gas properties of $281.4 million as a result of a decline in oil and 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 gas. Based on these year-end prices, the effect of derivative contracts accounted for as cash flow hedges increased the full cost ceiling by $192.1 million, thereby reducing the ceiling test write down by the same amount. The qualifying cash flow hedges as of December 31, 2008, which consisted of commodity price swaps, covered 6,254 MBbls of oil production for the period from January 2009 through December 2013.

Prices have remained volatile subsequent to December 31, 2008. If prices remain at these low levels, we may be required to record additional write downs under the full cost ceiling test in the first quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of each period, the incremental proved reserves added during each period and additional capital spent.

 

   

Monetization of Derivative Assets. During 2008, we monetized certain derivative instruments with original settlement dates from January through June of 2009. Net proceeds received from this monetization were $32.6 million. As of December 31, 2008, we have a net derivative asset of $205.7 million.

 

   

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 expected return on the investment will be the receipt of $2 of tax credits for every $1 invested to be recouped from our Oklahoma production taxes. The investments are accounted for as a production tax benefit asset and will be netted against tax credits realized in other income using the effective yield method over the expected recovery period. As of December 31, 2008, we had received $2.8 million of proceeds from the tax credits. Subsequent to December 31, 2008, we have received an additional $21.8 million of proceeds.

 

   

Capital Expenditure Budget. To keep our 2009 exploration and development expenditures within cash flow, the 2009 capital budget represents an 83% reduction in capital expenditures from our 2008 levels. Despite this reduction, we expect production for 2009 to remain at levels comparable to 2008 as a result of capital investments made in 2008 and the first quarter of 2009. However, if conditions do not improve and we are unable to expand our capital expenditure budget in 2010, we would expect production to decline at a rate consistent with our production decline curve.

 

   

Insurance proceeds. In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. We currently estimate that the total costs attributable to the loss of well control will be approximately $12.5 million. We anticipate that our insurance policy will cover 100% of these costs up to a maximum of $35.0 million, with the $0.6 million insurance retention and deductible being

 

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payable by us. As of December 31, 2008, we received $8.1 million for costs incurred through August 9, 2008, and recorded the insurance proceeds as a reduction of oil and gas properties on the balance sheet and in the statement of cash flows. We have submitted to our insurer additional claims totaling approximately $3.7 million for costs incurred through August 9, 2008.

 

   

Private equity sale. On September 29, 2006, we sold an aggregate of 102,000 shares of our common stock to Chesapeake Energy Corporation for an aggregate purchase price of $102.0 million. Proceeds from the sale after commissions and expenses were approximately $100.9 million and were used for general corporate and working capital purposes and acquisitions of oil and gas properties.

 

   

Acquisition of Calumet Oil Company and affiliates. On October 31, 2006, we acquired all of the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates for a cash purchase price of approximately $500.0 million. Calumet owned properties principally located in Oklahoma and Texas, areas which are complementary to our core areas of operations.

 

   

Green Country Supply Acquisition. On April 16, 2007, we acquired all of the outstanding shares of stock of Green Country Supply, Inc., or GCS, for $23.6 million. GCS was owned by the former shareholders of Calumet Oil Company and provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas and Wyoming.

 

 

 

8 7/8% Senior Notes due 2017. 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 Credit Agreement.

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 gas prices decrease our revenues. An extended decline in oil or gas prices may materially and adversely affect our future business, liquidity or ability to finance planned capital expenditures. Lower oil and gas prices may also reduce the amount of our borrowing base under our Credit Agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders.

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and issuance of equity. At December 31, 2008, we had approximately $52.1 million of cash and cash equivalents and $3.3 million of availability under our revolving credit line with a borrowing base of $600.0 million.

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. Based on the commodity prices for crude oil and natural gas at year end, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $320.0 million.

We believe that we will have sufficient funds available through our cash from operations to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months. We may adjust our planned capital expenditures depending on the timing and amount of any equity funding received and the availability of acquisition opportunities that meet our investment criteria.

We generally have had a working capital deficit as our capital expenditures have historically exceeded our cash flow; however, as a result of the current commodity pricing and its impact on our ability to utilize our revolving credit in 2009, we drew down substantially all our remaining availability under our Credit Agreement

 

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prior to December 31, 2008. Prior to year-end, we also monetized certain derivative instruments with original settlement dates from January through June of 2009, which generated net proceeds of $32.6 million. We have changed our cash management activities to target a minimum balance of cash on hand, which we expect to maintain in highly liquid investments.

We pledge our producing oil and gas properties to secure our revolving credit line. The banks establish a borrowing base by making an estimate of the collateral value of our oil and 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 gas prices decrease from the amounts used in estimating the collateral value of our oil and 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 gas prices through the use of commodity derivatives.

Sources and uses of cash. The net increase in cash is summarized as follows:

 

     Year Ended December 31,  

(dollars in thousands)

   2006     2007     2008  

Cash flows provided by operating activities

   $ 89,154     $ 113,443     $ 146,914  

Cash flows used in investing activities

     (703,804 )     (239,442 )     (263,988 )

Cash flows provided by financing activities

     621,855       128,883       157,499  
                        

Net increase in cash during the period

   $ 7,205     $ 2,884     $ 40,425  
                        

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. For the year ended December 31, 2008, cash flow from operating activities increased by approximately 30% from the prior year. This increase was due primarily to an increase in oil and gas sales revenue partially offset by higher operating expense and increased settlement losses on hedging activities.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the year ended December 31, 2008, the net cash provided from operations was approximately 56% of our net cash used in investing activities. Cash flow from operating activities and debt financing were primarily used during the year ended December 31, 2008 to fund $264.0 million in cash expenditures for investing activities.

Capital expenditures. For the year ended December 31, 2008, we incurred actual costs as summarized by area in the following table:

 

(Dollars in thousands)

   For the year ended
December 31, 2008(1)
   Percent
of total
 

Mid-Continent(2)

   $ 197,778    65 %

Permian Basin

     65,714    22 %

Gulf Coast

     22,795    7 %

Ark-La-Tex

     5,232    2 %

North Texas

     9,185    3 %

Rocky Mountains

     1,972    1 %
             
   $ 302,676    100 %
             

 

(1) Includes $0.7 million of additions relating to increases in our asset retirement obligations.

(2)

Includes $16.1 million of costs related to the construction of a compressor station and CO2 pipeline.

 

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In addition to the capital expenditures for oil and gas properties, we spent approximately $36.7 million for acquisition and construction of new office and administrative facilities and equipment during 2008.

Our actual costs incurred for the year ended December 31, 2008 and our current 2009 budgeted capital expenditures for oil and gas properties are detailed in the table below:

 

(Dollars in thousands)

   For the year ended
December 31, 2008(1)
   2009 budgeted capital
expenditures

Development activities:

     

Developmental drilling(2)

   $ 170,986    $ 38,000

Enhancements

     55,350      6,000

EOR

     25,354      5,000

Acquisitions:

     

Proved properties

     39,201      2,000

Unproved properties

     6,677      —  

Exploration activities

     5,108      —  
             

Total

   $ 302,676    $ 51,000
             

 

(1) Includes $0.7 million of additions relating to increases in our asset retirement obligations.

(2)

Includes $16.1 million of costs related to the construction of a compressor station and CO2 pipeline which were not included in the budget.

Our 2009 budgeted capital expenditures for oil and gas properties summarized by area are detailed in the table below:

 

(Dollars in thousands)

   2009 drilling
capital
expenditures
   Percent
of total
 

Mid-Continent

   $ 38,000    74 %

Permian Basin

     12,000    24 %

Other

     1,000    2 %
             
   $ 51,000    100 %
             

A majority of our capital expenditure budget for development drilling in 2009 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. The 2009 capital budget represents an 83% reduction in capital expenditures from our 2008 levels. Despite this reduction, we expect production for 2009 to remain at levels comparable to 2008 as a result of capital investments made in 2008 and the first quarter of 2009. However, if conditions do not improve and we are unable to expand our capital expenditure budget in 2010, we would expect production to decline at a rate consistent with our production decline curve.

We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2009 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.

Our existing credit facility. As of December 31, 2008, we had $594.0 million outstanding under our Credit Agreement and the borrowing base was $600.0 million. We believe we are in compliance with all covenants under the Credit Agreement as of December 31, 2008.

 

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In October 2006, we entered into a Seventh Restated Credit Agreement, which is scheduled to mature on October 31, 2010. 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 every six months. The borrowing base, which was redetermined effective December 24, 2008, is $600.0 million as of December 31, 2008.

Interest is paid on $594.0 million based upon LIBOR as of December 31, 2008 (effective rate of 5.299%). The credit line is collateralized by our oil and gas properties. The agreement has certain negative and affirmative covenants that require, among other things, maintaining financial covenants for current and debt service ratios and financial reporting.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans. At December 31, 2008, all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, defined effective December 24, 2008, as the greater of 2% or 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 2.000% to 3.750% depending on the utilization percentage of the conforming borrowing base. At December 31, 2008, the LIBOR rate, as defined, was 2.000%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 3.299% resulting in an effective interest rate of 5.299% for Eurodollar borrowings. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Effective December 24, 2008, 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 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 1.125% to 2.875%, 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.

Our borrowing base is subject to redetermination on May 1, 2009. 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 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days.

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 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;

 

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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 certain swap agreements; 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, 2007 and 2008, our current ratio as computed using GAAP was 0.69 and 1.34, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.49 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,
2007
    December 31,
2008
 

Current assets per GAAP

   $ 120,704     $ 218,363  

Plus—Availability under Credit Agreement

     76,311       3,270  

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

     (19,123 )     —    

Less—Short-term derivative instruments

     —         (51,412 )
                

Current assets as adjusted

   $ 177,892     $ 170,221  
                

Current liabilities per GAAP

   $ 174,980     $ 163,123  

Less—Short-term derivative instruments

     (54,307 )     —    

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

     —         (19,755 )

Less—Short-term asset retirement obligation

     (1,000 )     (300 )
                

Current liabilities as adjusted

   $ 119,673     $ 143,068  
                

Current ratio for loan compliance

     1.49       1.19  
                

Our Credit Agreement is scheduled to mature on October 31, 2010. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability, and we may not meet the required Current Ratio, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

Prior to the amendment described below, the Credit Agreement required us to maintain a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our 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;

 

   

4.75 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on June 30, 2007;

 

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4.50 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on September 30, 2007;

 

   

4.25 to 1.0 for the four consecutive fiscal quarters ending on December 31, 2007; and

 

   

4.00 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 quarter thereafter.

As of March 31, 2007, we did not meet the 5.00 to 1.0 Consolidated Total Debt to Consolidated EBITDAX ratio as required by the Credit Agreement. Effective May 11, 2007, the Credit Agreement was amended to replace the Total Debt to EBITDAX ratio with a Consolidated Senior Total Debt to Consolidated EBITDAX ratio. For the purposes of the amended ratio, Consolidated Senior Total Debt consists of all outstanding loans under the Credit Agreement, letters of credit and obligations under capital leases, as defined in the First Amendment to our Credit Agreement. The amended Credit Agreement requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our 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.

Based on our borrowings under our Credit Agreement of $594.0 million, to meet our required Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we will be required to achieve Consolidated EBITDAX, as defined in our Credit Agreement, of approximately $240.0 million for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters during the year ended December 31, 2009. We had Consolidated EBITDAX of approximately $280.2 million for the year ended December 31, 2008. Due to the significant decline in oil and gas prices, we may not generate the required $240.0 million of Consolidated EBITDAX in 2009. If we are not able to modify the referenced ratio or otherwise increase Consolidated EBITDAX, such as through the monetization of additional derivatives, we would not meet the covenants under our Credit Agreement, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

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 an 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;

 

   

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;

 

   

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

 

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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 our borrowing base amount is reduced by the banks, or if we expect to be unable to meet our required Current Ratio, or our required Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we could reduce our debt amount by monetizing additional derivative contracts, selling nonproducing oil and gas assets, selling non-oil and gas assets, selling producing oil and gas assets or raising equity. There is no assurance, however, that we will be able to sell our assets or equity at commercially reasonable terms or that any sales would generate enough cash to adequately reduce the borrowing base or that we will be able to meet our future obligations to the banks.

Our 8 1/2% Senior Notes due 2015. On December 1, 2005, we issued $325.0 million aggregate principal amount of 8 1/2% Senior Notes maturing on December 1, 2015. The 8 1/2% 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 8 1/2% 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 indenture.

On and after December 1, 2010, we may redeem some or all of the 8 1/2% Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption.

Prior to December 1, 2010, the 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 indenture.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indenture governing the 8 1/2% Senior Notes. The provisions of the indenture 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, 2008, we are not able to incur additional secured debt as a result of the ACNTA test under the 8 1/2% Senior Notes.

If we experience a change of control (as defined in the indenture governing the 8 1/2% Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the 8 1/2% Senior Notes the opportunity to sell to us their 8 1/2 % Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Our 8 7/8% Senior Notes due 2017. On January 18, 2007, we issued $325.0 million aggregate principal amount of 8 7/8% Senior Notes maturing on February 1, 2017. The 8 7/8% Senior Notes are our senior unsecured

 

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obligations, rank equally in right of payment with all of our existing and future senior indebtedness, including our existing 8 1/2% Senior Notes, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8 7/8% 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 indenture.

On and after February 1, 2012, we may redeem some or all of the 8 7/8% Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption.

In addition, 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.

Finally, prior to February 1, 2012, the 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 indenture.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indenture governing the 8 7/8% Senior Notes. The provisions of the indenture 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, 2008, we are not able to incur additional secured debt as a result of the ACNTA test under the 8 7/8% Senior Notes.

If we experience a change of control (as defined in the indenture governing the 8 7/8% Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the 8 7/8% Senior Notes the opportunity to sell to us their 8 7/8 % Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

As part of the indenture, we entered into a registration rights agreement in which we agreed to file a registration statement with the Securities and Exchange Commission related to an offer to exchange the notes for an issue of registered notes within 270 days of the closing date. If we failed to complete the exchange offer within 270 days after the closing date, we would be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate increased an additional 0.25% for each additional 90 days, up to a total of 1.0%. The exchange

 

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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.

Alternative capital resources. We have historically used cash flow from operations, debt financing and private issuance of common stock as our primary sources of capital. 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.

Contractual obligations. The following table summarizes our contractual obligations and commitments as of December 31, 2008:

 

(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

   $ 31,476    $ 625,476    $ —      $ —      $ 656,952

Senior notes, including estimated interest

     56,469      112,938      112,938      796,587      1,078,932

Other long-term notes including estimated interest

     7,558      10,089      4,520      18,260      40,427

Capital leases including estimated interest

     259      304      —        —        563

Abandonment obligations

     300      600      600      31,875      33,375

Derivative obligations

     —        3,388      —        —        3,388

Purchase Commitments

     2,847      3,969      —        —        6,816
                                  

Total

   $ 98,909    $ 756,764    $ 118,058    $ 846,722    $ 1,820,453
                                  

 

(1) As of December 31, 2008, we had no off-balance sheet arrangements.

We have long-term contracts to purchase up to all of the CO2 manufactured at two existing ethanol plants. Based on plant capacity, it is estimated that we will purchase an average of approximately 4.2 MMcf per day over the ten-year contract term which will begin upon our first purchase, under one contract, and under the second contract an average of approximately 13.75 MMcf per day over the fifteen-year contract term which begins in 2009. Pricing under both contracts is variable over time and both contracts have the possibility of renewal. We have rights under two additional contracts that require us to purchase CO2 for EOR projects. Under one contract we may purchase a variable amount of CO2, up to 20.0 MMcf per day. We have historically taken less CO2 than the maximum allowed in the contract and based on our current level, we project we would purchase an average of approximately 16.0 MMcf per day over the remainder of the initial term of the contract, which expires in 2011. The contract automatically renews for an additional ten years unless terminated by us. We may also purchase a variable amount of CO2 under the second contract and we are currently purchasing an average of approximately 5.0 MMcf per day and project our purchases to remain at that level through 2009. The contract expires in 2016. We may terminate this contract at the end of any calendar year with 13 months notice. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

 

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Comparison of Year Ended December 31, 2008 to Year Ended December 31, 2007

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

 

     Year ended December 31,    Percentage
Increase
(Decrease)
 
           2007                2008         

Oil and gas sales (dollars in thousands)

        

Oil

   $ 234,428    $ 348,907    48.8 %

Gas

     131,530      152,854    16.2 %
                

Total

   $ 365,958    $ 501,761    37.1 %

Production

        

Oil (MBbls)

     3,356      3,773    12.4 %

Gas (MMcf)

     20,504      19,795    (3.5 )%
                

MMcfe

     40,640      42,433    4.4 %

Average sales prices (excluding hedging)

        

Oil per Bbl

   $ 69.85    $ 92.47    32.4 %

Gas per Mcf

     6.41      7.72    20.4 %
                

Mcfe

   $ 9.00    $ 11.82    31.3 %

Oil and gas revenues increased $135.8 million, or 37.1%, to $501.8 million during 2008 due to a 4.4% increase in sales volumes and a 31.3% increase in the average price per Mcfe. Oil and natural gas prices declined significantly during the fourth quarter of 2008. Based on our forecasted production, if oil and natural gas prices remain at current levels or decline further, our revenues in 2009 will be significantly lower than the amounts reported in 2008.

Oil sales increased 48.8% from $234.4 million to $348.9 million during the year ended December 31, 2008. This increase was due to a 12.4% increase in production volumes to 3,773 MBbls and a 32.4% increase in average oil prices to $92.47 per Bbl. Natural gas sales revenues increased 16.2% from $131.5 million for the year ended December 31, 2007 to $152.9 million for the year ended December 31, 2008. This increase was due to a 20.4% increase in average gas prices to $7.72 per Mcf, partially offset by a 3.5% decrease in production volumes to 19,795 MMcf. Oil production for the year ended December 31, 2008 increased due primarily to the addition of volumes from acquisitions, our expanded drilling program, and enhancements of our existing properties.

Production volumes by area were as follows (MMcfe):

 

     Year ended December 31,    Percent
Increase
(Decrease)
 
           2007                2008         

Mid Continent

   26,331    28,397    7.8 %

Permian Basin

   6,284    6,871    9.3 %

Gulf Coast

   3,787    3,383    (10.7 )%

Ark-La-Tex

   1,905    1,746    (8.3 )%

North Texas

   1,382    1,106    (20.0 )%

Rocky Mountains

   951    930    (2.2 )%
            

Totals

   40,640    42,433    4.4 %
            

 

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Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and 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. The effects of hedging on our net revenues for the years ended December 31, 2007 and 2008 are as follows:

 

     Year ended December 31,  

(dollars in thousands)

         2007                 2008        

Gain (loss) from oil and gas hedging activities:

    

Hedge settlements

   $ (19,797 )   $ (88,966 )

Hedge ineffectiveness

     (8,343 )     12,549  
                

Total

   $ (28,140 )   $ (76,417 )
                

Our loss on hedge settlements was $89.0 million compared to a loss of $19.8 million in 2007, primarily due to high overall commodity prices during the first nine months of 2008. The loss on hedge settlements was partially offset by hedge ineffectiveness, which was a gain of $12.5 million in 2008 compared to a loss of $8.3 million in 2007. This was primarily due to lower NYMEX forward strip oil prices at December 31, 2008 compared to December 31, 2007, combined with higher average contractual prices.

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 $5.8 million cumulative change in fair value attributable to the natural gas swaps that had been accounted for as cash flow hedges and were outstanding as of December 31, 2008 has been deferred in other comprehensive income (loss), and will be recognized as a gain from oil and gas hedging activities when the hedged production is sold. 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, and the ineffective portion would have been included in the loss from oil and gas hedging activities, which is a component of revenue.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts that qualify for hedge accounting. The following table presents information about the effects of hedging on realized prices:

 

     Average Price    Hedged to
Non-Hedged
Price
 
     Without Hedge    With Hedge(1)   

Oil (per Bbl):

        

Year ended December 31, 2007

   $ 69.85    $ 61.35    87.8 %

Year ended December 31, 2008

     92.47      73.08    79.0 %

Gas (per Mcf):

        

Year ended December 31, 2007

   $ 6.41    $ 6.84    106.7 %

Year ended December 31, 2008

     7.72      6.92    89.6 %

 

(1) Average realized prices only include the effects of hedging contracts that qualify and are designated for hedge accounting. Had we included the effects of contracts not so designated, our average realized price for oil would have been $61.35 and $71.95 per Bbl for 2007 and 2008, respectively, and our average realized price for gas would have been $6.80 and $7.38 per Mcf for 2007 and 2008, respectively.

 

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Costs and Expenses. The following table presents information about our operating expenses for each of the years ended December 31, 2007 and 2008:

 

     Amount     Per Mcfe  
     Year ended
December 31,
   Percent
Increase
    Year ended
December 31,
   Percent
Increase
(Decrease)
 

(dollars in thousands)

   2007    2008      2007    2008   

Lease operating expenses

   $ 104,469    $ 120,487    15.3 %   $ 2.57    $ 2.84    10.5 %

Production taxes

     26,216      33,815    29.0 %     0.65      0.80    23.1 %

Depreciation, depletion and amortization

     85,431      100,528    17.7 %     2.10      2.37    12.9 %

General and administrative

     21,838      22,370    2.4 %     0.54      0.53    (1.9 )%

Lease operating expenses—Increase was generally 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 continued upward pressure on service costs, labor and materials resulting from the sustained strength of commodity prices during the first nine months of 2008. Included in the figures are a $4.7 million increase in electricity and fuel costs and a $2.4 million increase in workover activity. We expect lease operating expenses to decrease in the future if oil and gas prices remain at their current levels or decline further. However, the timing of the expected cost decline is uncertain, and we do not expect it to be proportional to the decline in our average realized prices.

Production taxes (which include ad valorem taxes)—Increase was primarily due to 31.3% higher average realized prices, and an increase of 4.4% increase in production volumes.

Depreciation, depletion and amortization—Increase was due primarily to an increase in DD&A on oil and gas properties of $12.6 million. For oil and gas properties, $3.9 million of the increase was due to higher production volumes in 2008 and $8.7 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production on oil and gas properties increased $0.21 to $2.15 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

Impairment of oil and natural gas properties— In accordance with the full-cost method of accounting, the net capitalized costs of oil and 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. Based on these year-end prices, the effect of derivative contracts accounted for as cash flow hedges increased the full-cost ceiling by $192.1 million, thereby reducing the ceiling test write down by the same amount. The qualifying cash flow hedges as of December 31, 2008, which consisted of commodity price swaps, covered 6,254 MBbls of oil production for the period from January 2009 through December 2013.

Prices have remained volatile subsequent to December 31, 2008. If prices remain at these low levels, we may be required to record additional write-downs under the full cost ceiling test in the first quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and natural gas prices at the end of 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, is no longer able to participate in the joint venture, and we now own 100% of Oklahoma Ethanol LLC. The City of Blackwell has also been unable to obtain financing for the railroad upgrades and

 

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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 expense is net of $11.2 million in 2008 and $10.8 million in 2007 capitalized as part of our exploration and development activities.

Interest expense. Interest expense decreased by $1.6 million, or 1.8%, compared to 2007, primarily as a result of lower interest rates paid, somewhat offset by increased levels of borrowings. The following table presents interest expense:

 

(dollars in thousands)

   2007    2008

Revolver Interest

   $ 27,387    $ 23,574

8 1/2% Senior Notes, due 2015

     28,285      28,348

8 7/8% Senior Notes, due 2017

     28,413      29,578

Other Interest

     3,571      4,538
             
   $ 87,656    $ 86,038
             

Non-hedge derivative gains (losses). Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:

 

     Year ended December 31,

(dollars in thousands)

         2007                 2008      

Non-hedge derivative gains (losses):

    

Non-qualified commodity price swaps

   $ (24,416 )   $ 29,367

Non-designated costless collars

     —         90,525

Natural gas basis differential contracts

     635       7,049
              

Total

   $ (23,781 )   $ 126,941
              

During 2008, we entered into costless collars with a weighted average floor of $104.36 covering 1,846 MBbls of oil from July 2008 through December 2013. We also entered into costless collars with a weighted average floor of $10.00 covering 7,520 BBtu of gas from November 2008 through December 2010. Due to the decline in the NYMEX forward strip oil and gas prices, we recognized a gain on the collars of $90.5 million for the year ended December 31, 2008.

In December 2008, we monetized oil and gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. Certain swaps that were settled had previously been accounted for as cash flow hedges. The $17.9 million cumulative change in fair value attributable to the swaps that had been accounted for as cash flow hedges has been deferred in other comprehensive income (loss), and will be recognized as a gain from oil and gas hedging activities when the hedged production is sold.

Primarily as a result of the above transactions, we had non-hedge derivative gains of $126.9 million for the year ended December 31, 2008 compared to non-hedge derivative losses of $23.8 million in 2007.

Termination fee and acquisition costs. 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

 

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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.

Service company revenues and operating expenses. Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, Inc., which was acquired during the second quarter of 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services. Operating expenses consist of costs of sales related to product sales and general and administrative expenses. We recognized $34.3 million in service company revenue in the year ended December 31, 2008, with corresponding service company expense of $31.7 million, for a net profit of $2.6 million. Service company revenue before intercompany eliminations was $72.9 million and a pre-tax net profit of $5.6 million in the year ended December 31, 2008. We recognized $20.6 million in service company revenue in the year ended December 31, 2007 with corresponding service company expense of $18.8 million, for a net profit of $1.8 million. Service company revenue before intercompany eliminations was $37.7 million and a pre-tax net profit of $2.7 million in the year ended December 31, 2007.

Comparison of Year Ended December 31, 2007 to Year Ended December 31, 2006

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

 

     Year ended December 31,    Percentage
Increase
(Decrease)
 
           2006                2007         

Oil and gas sales (dollars in thousands)

        

Oil

   $ 117,504    $ 234,428    99.5 %

Gas

     131,676      131,530    (0.1 )%
                

Total

   $ 249,180    $ 365,958    46.9 %

Production

        

Oil (MBbls)

     1,906      3,356    76.1 %

Gas (MMcf)

     20,949      20,504    (2.1 )%
                

MMcfe

     32,385      40,640    25.5 %

Average sales prices (excluding hedging)

        

Oil per Bbl

   $ 61.65    $ 69.85    13.3 %

Gas per Mcf

     6.29      6.41    1.9 %
                

Mcfe

   $ 7.69    $ 9.00    17.0 %

Oil sales increased 99.5% from $117.5 million to $234.4 million during the year ended December 31, 2007. This increase was due to a 76.1% increase in production volumes to 3,356 MBbls and a 13.3% increase in average oil prices to $69.85 per barrel. Natural gas sales revenues decreased 0.1% from $131.7 million for the year ended December 31, 2006 to $131.5 million for the year ended December 31, 2007. This decrease was due to a 2.1% decrease in production volumes to 20,504 MMcf, partially offset by a 1.9% increase in average gas prices to $6.41 per Mcf. Oil production for the year ended December 31, 2007 increased due primarily to the addition of volumes from acquisitions, our expanded drilling program and enhancements of our existing properties.

 

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Production volumes by area were as follows (MMcfe):

 

     Year ended December 31,    Percent
Increase
(Decrease)
 
         2006            2007       

Mid Continent

   19,499    26,331    35.0 %

Permian Basin

   5,497    6,284    14.3 %

Gulf Coast

   3,348    3,787    13.1 %

Ark-La-Tex

   1,724    1,905    10.5 %

North Texas

   1,119    1,382    23.5 %

Rocky Mountains

   1,198    951    (20.6 )%
            

Totals

   32,385    40,640    25.5 %
            

The effects of hedging on our net revenues for the years ended December 31, 2006 and 2007 are as follows:

 

     Year ended December 31,  

(dollars in thousands)

         2006                 2007        

Gain (loss) from oil and gas hedging activities:

    

Hedge settlements

   $ (22,927 )   $ (19,797 )

Hedge ineffectiveness

     18,761       (8,343 )
                

Total

   $ (4,166 )   $ (28,140 )
                

Our loss from oil and gas hedging settlements in 2007 decreased $3.1 million due to improved hedge positions in relation to commodity prices from 2007 compared to 2006. Additionally as a result of higher NYMEX forward strip oil prices at December 31, 2007 compared to December 31, 2006, hedge ineffectiveness resulted in a loss of $8.3 million in 2007 compared to a gain of $18.8 million in 2006.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts that qualify for hedge accounting. The following table presents information about the effects of hedging on realized prices:

 

     Average Price    Hedged to
Non-Hedged
Price
 
     Without Hedge    With Hedge(1)   

Oil (per Bbl):

        

Year ended December 31, 2006

   $ 61.65    $ 46.99    76.2 %

Year ended December 31, 2007

     69.85      61.35    87.8 %

Gas (per Mcf):

        

Year ended December 31, 2006

   $ 6.29    $ 6.52    103.7 %

Year ended December 31, 2007

     6.41      6.84    106.7 %

 

(1) Average realized prices only include the effects of hedging contracts that qualify and are designated for hedge accounting. Had we included the effects of contracts not so designated, our average realized price for gas would have been $6.52 and $6.80 per Mcf for 2006 and 2007, respectively.

 

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Costs and Expenses. The following table presents information about our operating expenses for each of the years ended December 31, 2006 and 2007:

 

     Amount     Per Mcfe  
     Year ended
December 31,
   Percent
Increase
    Year ended
December 31,
   Percent
Increase
 

(dollars in thousands)

   2006    2007      2006    2007   

Lease operating expenses

   $ 71,663    $ 104,469    45.8 %   $ 2.21    $ 2.57    16.3 %

Production taxes

     18,710      26,216    40.1 %     0.58      0.65    12.1 %

Depreciation, depletion and amortization

     52,299      85,431    63.4 %     1.61      2.10    30.4 %

General and administrative

     14,659      21,838    49.0 %     0.45      0.54    20.0 %

Lease operating expenses—Increase was generally due to increases in the number of net producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Approximately $22.3 million of the increase were expenses attributable to the properties acquired in the Calumet acquisition. Per unit expenses were higher for all categories of lease operating expenses due to continued upward pressure on service costs, labor and materials resulting from the sustained strength of commodity prices. Included in the figures are $8.9 million of costs associated with workovers in 2007 compared to $9.5 million in 2006.

Production taxes (which include ad valorem taxes)—Increase was due primarily to a 25.5% increase in production volumes and a 17.0% increase in average realized prices.

Depreciation, depletion and amortization—Increase was due primarily to an increase in DD&A on oil and gas properties of $31.6 million. For oil and gas properties, $16.0 million of the increase was due to higher production volumes in 2007 and $15.6 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production on oil and gas properties increased by $0.49 to $1.94 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses—Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity, including the Calumet acquisition. In addition, we increased our compensation plan, including an increase in our officer bonus program and decreased the vesting period related to the Phantom Plan in efforts to meet market demand and recruit and maintain essential personnel. Approximately $0.3 million of the increase was due to the revision in the Phantom Plan. G&A expense also includes $0.6 million of expenses associated with Pointe Vista Development and Oklahoma Ethanol. G&A expense is net of $10.8 million in 2007 and $8.3 million in 2006 capitalized as part of our exploration and development activities.

Interest expense. Interest expense increased by $42.4 million, or 93.7%, compared to 2006, primarily as a result of increased levels of borrowings and higher interest rates paid. The following table presents interest expense:

 

(dollars in thousands)

   2006    2007

Revolver Interest

   $ 16,372    $ 27,387

8 1/2% Senior Notes, due 2015

     28,223      28,285

8 7/8% Senior Notes, due 2017

     —        28,413

Other Interest

     651      3,571
             
   $ 45,246    $ 87,656
             

Non-hedge derivative losses. Non-hedge derivative losses were $23.8 million for the year ended December 31, 2007 and are comprised of losses of $24.4 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, and $0.6 million of gains related to natural gas basis differential swaps. Non-hedge derivative losses were $4.7 million for the year

 

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ended December 31, 2006 and are comprised of losses of $3.8 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, and $0.9 million of losses related to natural gas basis differential swaps.

Service company revenues and operating expenses. Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, which was acquired during the second quarter of 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services. Operating expenses consist of costs of sales related to product sales and general and administrative expenses. We recognized $20.6 million in service company revenue in the year ended December 31, 2007 with corresponding service company expense of $18.8 million, for a net profit of $1.8 million. Service company revenue before intercompany eliminations was $37.7 million and a pre-tax net profit of $2.7 million in the year ended December 31, 2007. There were no service company revenues or expenses during 2006.

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 a discussion of additional accounting policies and estimates made by management.

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and gas produced from our oil and 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 Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activity, as amended, (“SFAS 133”). 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. Pursuant to SFAS 133, 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 “Loss from oil and 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 “Loss from oil and 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

 

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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 SFAS No. 157, Fair Value Measurements (“SFAS 157”). 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 in accordance with SFAS 157. We determine fair value for our oil and 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 in accordance with SFAS 157. 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 gas properties.

 

   

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

 

   

Proved oil and gas reserves quantities. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance.

Our proved reserve information included in this report is based on estimates prepared by Cawley, Gillespie & Associates, Inc., Ryder Scott Company, L.P., and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 75% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2008, and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

 

   

Depreciation, depletion and amortization. The quantities of proved oil and 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 gas reserves and production, which are converted to a common unit of measure based on the relative energy content.

 

   

Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and 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 unevaluated properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues are those in effect as of the last day of the quarter. If oil and gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that additional write downs of our oil and gas properties could occur in the future.

 

   

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, 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

 

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drilling a well or are assessed quarterly for possible impairment. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

 

   

Future development and abandonment costs. Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and gas properties and related facilities. We develop estimates of future development costs and abandonment 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.

In accordance with Statement on Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, we record a liability for the discounted 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. The present value calculation requires us to make numerous assumptions and judgments, including 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. 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. We provide for income taxes in accordance with Statement on Financial Accounting Standards No. 109, Accounting for Income Taxes and FASB Interpretation No. 48, Accounting for Uncertainty in 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.

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. Generally we 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 December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also

 

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establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. We intend to adopt SFAS 141(R) effective January 1, 2009 and apply its provisions prospectively.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (“SFAS 160”). SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We are currently assessing the impact, if any, of the adoption of SFAS 160.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 addresses concerns that the existing disclosure requirements in SFAS 133 do not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. Accordingly, this statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We are currently assessing the impact, if any, of the adoption of SFAS 161.

In December 2008, the Securities and Exchange Commission (“SEC”) issued Release No. 33-8995, Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure requirements also require companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently, the SEC requires that reserve volumes be determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the first day of each month for the prior twelve-month period rather than year-end prices. The new requirements will also allow companies to disclose their probable and possible reserves to investors, and will require them to report the independence and qualifications of their reserves preparer or auditor. The new rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We will adopt the provisions of the new rule in connection with our December 31, 2009 Form 10-K filing. We are currently evaluating the impact of the rule on our financial statements.

Effects of inflation and pricing

While the general level of inflation affects certain of our costs, factors unique to the oil and gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and 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 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 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 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 gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and 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 year ended December 31, 2008 production, our gross revenues from oil and gas sales would change approximately $2.0 million for each $0.10 change in gas prices and $3.8 million for each $1.00 change in oil prices.

To mitigate a portion of this exposure, 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 offset, 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 pursuant to SFAS 133. 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 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 believe that these instruments qualify as hedges pursuant to SFAS 133; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

In anticipation of the Calumet acquisition, we entered into additional commodity swaps to provide protection against a decline in the price of oil. We do not believe that these instruments qualify as hedges pursuant to SFAS 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses. Also, as a result of the acquisition, Chaparral assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. As of December 31, 2008, the hedges assumed as part of the Calumet acquisition have been settled.

 

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Our outstanding oil and gas derivative instruments as of December 31, 2008 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
to be
received
   Percent of
PDP
production(1)
 

1Q 2009

   159    $ 72.06    21    $ 66.78    30    $ 110.00 -$169.15    23.7 %

2Q 2009

   153      71.09    —        —      30      110.00 -  169.15    21.5 %

3Q 2009

   480      68.81    90      66.57    60      110.00 -  164.28    76.4 %

4Q 2009

   471      68.25    90      66.18    60      110.00 -  164.28    77.6 %

1Q 2010

   420      67.40    102      65.80    60      110.00 -  168.55    75.3 %

2Q 2010

   420      67.10    90      65.47    60      110.00 -  168.55    76.0 %

3Q 2010

   408      66.43    90      65.10    60      110.00 -  168.55    80.2 %

4Q 2010

   402      65.95    90      64.75    60      110.00 -  168.55    81.2 %

1Q 2011

   309      64.40    99      64.24    51      110.00 -  152.71    69.2 %

2Q 2011

   309      64.06    90      63.93    51      110.00 -  152.71    69.4 %

3Q 2011

   309      63.71    90      63.61    51      110.00 -  152.71    70.9 %

4Q 2011

   309      63.33    90      63.30    51      110.00 -  152.71    72.6 %

1Q 2012

   281      124.66    —        —      157      100.00 -  135.25    72.2 %

2Q 2012

   275      124.63    —        —      154      100.00 -  135.25    72.6 %

3Q 2012

   271      124.61    —        —      152      100.00 -  135.25    72.9 %

4Q 2012

   265      124.60    —        —      149      100.00 -  135.25    72.8 %

1Q 2013

   262      124.44    —        —      110      100.00 -  133.50    66.5 %

2Q 2013

   256      124.44    —        —      110      100.00 -  133.50    66.7 %

3Q 2013

   250      124.45    —        —      107      100.00 -  133.50    66.1 %

4Q 2013

   245      124.47    —        —      103      100.00 -  133.50    65.7 %
                          
   6,254       942       1,666      
                          

 

     Natural Gas Swaps    Natural Gas Collars    Percent of
PDP
production(1)
 
     Non-hedge    Non-hedge   
     Volume
BBtu
   Weighted
average
fixed price
to be
received
   Volume
BBtu
   Weighted
average

range
to be
received
  

1Q  2009

   750    $ 7.74    600    $ 10.00 -$14.06    18.6 %

2Q  2009

   750      7.47    600      10.00 -  14.06    19.4 %

3Q  2009

   3,390      7.19    990      10.00 -  13.85    67.3 %

4Q  2009

   3,300      7.66    990      10.00 -  13.85    69.9 %

1Q  2010

   2,550      7.78    840      10.00 -  11.53    58.3 %

2Q  2010

   2,550      7.08    840      10.00 -  11.53    62.2 %

3Q  2010

   2,550      7.30    840      10.00 -  11.53    68.1 %

4Q  2010

   2,550      7.72    840      10.00 -  11.53    72.0 %

1Q  2011

   1,800      7.89    —        —      40.1 %

2Q  2011

   1,800      7.02    —        —      42.0 %

3Q  2011

   1,800      7.19    —        —      43.7 %

4Q  2011

   1,800      7.54    —        —      45.5 %
                  
   25,590       6,540      
                  

 

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     Natural Gas Basis
Protection Swaps
     Non-hedge
     Volume
BBtu
   Weighted
average
fixed price
to be paid

1Q 2009

   5,220    $ 1.02

2Q 2009

   5,160      0.90

3Q 2009

   4,620      0.91

4Q 2009

   4,440      0.94

1Q 2010

   4,350      0.96

2Q 2010

   1,500      0.88

3Q 2010

   1,500      0.88

4Q 2010

   1,500      0.91

1Q 2011

   1,500      0.93
       
   29,790   
       

 

(1) Based on our most recent internally estimated PDP production for such periods.

Subsequent to December 31, 2008, we entered into the following derivative instruments:

 

     Crude Oil Swaps    Natural Gas Swaps    Natural Gas Basis
Protection Swaps
     Hedge    Non-hedge    Non-hedge
     Volume
MBbl
   Weighted
average
fixed price
to be
received
   Volume
BBtu
   Weighted
average
fixed price
to be
received
   Volume
BBtu
   Weighted
average
fixed price
to be
paid

1Q 2009

   —      $ —      2,000    $ 5.60    —      $ —  

2Q 2009

   240      54.02    3,000      5.73    —        —  

3Q 2009

   28      57.99    300      6.46    —        —  

4Q 2009

   19      60.86    300      7.04    —        —  

1Q 2010

   —        —      600      7.50    —        —  

2Q 2010

   —        —      600      6.91    750      0.72

3Q 2010

   —        —      600      7.14    750      0.72

4Q 2010

   —        —      600      7.55    950      0.68

1Q 2011

   —        —      600      7.98    1,050      0.66

2Q 2011

   —        —      600      7.05    —        —  

3Q 2011

   —        —      600      7.21    —        —  

4Q 2011

   —        —      600      7.56    —        —  
                       
   287       10,400       3,500   
                       

On March 27, 2009, we monetized natural gas swaps of 1,100 BBtu per month for May and June 2009, and 700 BBtu per month for July through October 2009, resulting in cash proceeds of approximately $9.5 million. These swaps were with two different counterparties, and were put into place after our last borrowing base redetermination; therefore, they were not incorporated into the determination of the borrowing base.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of December 31, 2008 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established by the Federal Reserve Board. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $600.0 million, equal to our borrowing base at December 31, 2008, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $6.0 million.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to financial statements

 

     Page

Chaparral Energy, Inc. consolidated financial statements:

  

Report of independent registered public accounting firm

   64

Consolidated balance sheets as of December 31, 2007 and 2008

   65

Consolidated statements of operations for the years ended December 31, 2006, 2007 and 2008

   66

Consolidated statements of stockholders’ equity and comprehensive income (loss) for the years ended December  31, 2006, 2007 and 2008

   67

Consolidated statements of cash flows for the years ended December 31, 2006, 2007 and 2008

   68

Notes to consolidated financial statements

   70

 

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Report of independent registered public accounting firm

Board of Directors

Chaparral Energy, Inc.

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. and subsidiaries as of December 31, 2007 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chaparral Energy, Inc. and subsidiaries as of December 31, 2007 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

 

/s/    GRANT THORNTON LLP        

Oklahoma City, Oklahoma

March 31, 2009

 

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Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

 

     December 31,  

(dollars in thousands, except per share data)

   2007     2008  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 11,687     $ 52,112  

Accounts receivable, net

     65,292       69,562  

Production tax benefit

     813       13,685  

Inventories

     19,480       27,143  

Deferred income taxes

     19,128       —    

Prepaid expenses

     4,304       4,449  

Derivative instruments

     —         51,412  
                

Total current assets

     120,704       218,363  

Property and equipment—at cost, net

     50,747       72,891  

Oil & gas properties, using the full cost method:

    

Proved

     1,457,822       1,751,096  

Unproved (excluded from the amortization base)

     25,327       16,865  

Work in progress (excluded from the amortization base)

     19,274       31,893  

Accumulated depreciation, depletion, amortization and impairment

     (200,577 )     (573,233 )
                

Total oil & gas properties

     1,301,846       1,226,621  

Funds held in escrow

     5,224       2,350  

Derivative instruments

     —         157,720  

Other assets

     52,377       34,891  
                
   $ 1,530,898     $ 1,712,836  
                

Liabilities and stockholders’ equity

    

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 68,241     $ 92,777  

Accrued payroll and benefits payable

     9,299       9,215  

Accrued interest payable

     14,741       15,408  

Revenue distribution payable

     21,471       19,827  

Current maturities of long-term debt and capital leases

     6,921       6,200  

Derivative instruments

     54,307       —    

Deferred income taxes

     —         19,696  
                

Total current liabilities

     174,980       163,123  

Long-term debt and capital leases, less current maturities

     459,826       617,714  

8 1/2% Senior Notes, due 2015

     325,000       325,000  

8 7/8% Senior Notes, due 2017

     322,490       322,675  

Derivative instruments

     96,227       3,388  

Deferred compensation

     2,017       762  

Asset retirement obligations

     29,684       33,075  

Deferred income taxes

     17,496       42,699  

Commitments and contingencies (note 14)

    

Stockholders’ equity:

    

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

     —         —    

Common stock, $.01 par value, 3,000,000 shares authorized; 877,000 shares issued and outstanding as of December 31, 2007 and 2008, respectively

     9       9  

Additional paid in capital

     100,918       100,918  

Retained earnings

     76,090       21,340  

Accumulated other comprehensive income (loss), net of taxes

     (73,839 )     82,133  
                
     103,178       204,400  
                
   $ 1,530,898     $ 1,712,836  
                

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

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

 

     Year Ended December 31,  

(dollars in thousands, except per share data)

   2006     2007     2008  

Revenues:

      

Oil and gas sales

   $ 249,180     $ 365,958     $ 501,761  

Loss from oil and gas hedging activities

     (4,166 )     (28,140 )     (76,417 )

Service company sales

     —         20,611       34,272  
                        

Total revenues

     245,014       358,429       459,616  

Costs and expenses:

      

Lease operating

     71,663       104,469       120,487  

Production taxes

     18,710       26,216       33,815  

Depreciation, depletion and amortization

     52,299       85,431       100,528  

Loss on impairment of oil & gas properties

     —         —         281,393  

Loss on impairment of ethanol plant

     —         —         2,900  

General and administrative

     14,659       21,838       22,370  

Service company expenses

     —         18,852       31,656  
                        

Total costs and expenses

     157,331       256,806       593,149  
                        

Operating income (loss)

     87,683       101,623       (133,533 )

Non-operating income (expense):

      

Interest expense

     (45,246 )     (87,656 )     (86,038 )

Non-hedge derivative gains (losses)

     (4,677 )     (23,781 )     126,941  

Termination fee

     —         —         3,500  

Merger costs

     —         —         (1,400 )

Other income

     792       2,276       1,394  
                        

Net non-operating income (expense)

     (49,131 )     (109,161 )     44,397  
                        

Income (loss) before income taxes and minority interest

     38,552       (7,538 )     (89,136 )

Income tax expense (benefit)

     14,817       (2,745 )     (34,386 )

Minority interest

     (71 )     —         —    
                        

Net income (loss)

   $ 23,806     $ (4,793 )   $ (54,750 )
                        

Net income (loss) per share (basic and diluted)

   $ 29.74     $ (5.47 )   $ (62.43 )

Weighted average number of shares used in calculation of basic and diluted earnings per share

     800,500       877,000       877,000  

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

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity

and comprehensive income (loss)

 

(dollars in thousands)

  Common stock   Additional
paid in
capital
  Retained
earnings
    Accumulated
other
comprehensive
income (loss)
    Total  
  Shares   Amount        

Balance at January 1, 2006

  775,000   $ 8   $ —     $ 58,126     $ (47,967 )   $ 10,167  

Issuance of common stock

  102,000     1     100,918     —         —         100,919  

Dividends

  —       —       —       (1,049 )     —         (1,049 )

Net income

  —       —       —       23,806       —         23,806  

Other comprehensive income, net

           

Unrealized gain on hedges, net of taxes of $18,916

  —       —       —       —         29,949       29,949  

Reclassification adjustment for hedge losses included in net income, net of taxes of $8,855

  —       —       —       —         14,072       14,072  
                 

Total comprehensive income

              67,827  
     

Balance at December 31, 2006

  877,000     9     100,918     80,883       (3,946 )     177,864  

Net loss

  —       —       —       (4,793 )     —         (4,793 )

Other comprehensive loss, net

           

Unrealized loss on hedges, net of taxes of $51,745

  —       —       —       —         (82,032 )     (82,032 )

Reclassification adjustment for hedge losses included in net loss, net of taxes of $7,658

  —       —       —       —         12,139       12,139  
                 

Total comprehensive loss

              (74,686 )
     

Balance at December 31, 2007

  877,000     9     100,918     76,090       (73,839 )     103,178  

Net loss

  —       —       —       (54,750 )     —         (54,750 )

Other comprehensive income, net

           

Unrealized gains on hedges, net of taxes of $64,045

  —       —       —       —         101,347       101,347  

Reclassification adjustment for hedge losses included in net loss, net of taxes of $34,341

  —       —       —       —         54,625       54,625  
                 

Total comprehensive income

              101,222  
     

Balance at December 31, 2008

  877,000   $ 9   $ 100,918   $ 21,340     $ 82,133     $ 204,400  

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

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

 

     Year Ended December 31,  

(dollars in thousands)

   2006     2007     2008  

Cash flows from operating activities

      

Net income (loss)

   $ 23,806     $ (4,793 )   $ (54,750 )

Adjustments to reconcile net income (loss) to net cash provided by operating activities

      

Depreciation, depletion & amortization

     52,299       85,431       100,528  

Service company depreciation, depletion & amortization

     —         411       1,445  

Loss on impairments

     —         —         284,293  

Deferred income taxes

     14,839       (2,729 )     (34,358 )

Unrealized (gain) loss on ineffective portion of hedges

     (18,761 )     8,343       (12,549 )

Change in fair value of non-hedge derivative instruments

     4,681       23,781       (126,941 )

Gain on sale of assets

     (132 )     (712 )     (177 )

Other

     1,266       1,404       2,750  

Change in assets & liabilities, net of assets and liabilities of business acquired

      

Accounts receivable

     (13,213 )     (13,660 )     (2,516 )

Inventories

     (444 )     3,568       (8,278 )

Prepaid expenses and other assets

     376       (1,079 )     1,373  

Accounts payable and accrued liabilities

     16,659       8,426       (1,957 )

Revenue distribution payable

     7,696       4,221       (1,643 )

Deferred compensation

     82       831       (306 )
                        

Net cash provided by operating activities

     89,154       113,443       146,914  

Cash flows from investing activities

      

Purchase of property and equipment and oil and gas properties

     (201,256 )     (220,651 )     (304,568 )

Acquisition of a business, net of cash acquired

     (466,656 )     (21,569 )     —    

Proceeds from dispositions of property and equipment and oil and gas properties

     5,820       526       1,808  

Cash in escrow

     (21,795 )     (2,156 )     1,385  

Proceeds from sale of a business

     —         3,158       —    

Purchase of prepaid production tax asset

     (15,000 )     —         —    

Settlement of non-hedge derivative instruments

     (85 )     (750 )     37,387  

Other

     (4,832 )     2,000       —    
                        

Net cash used in investing activities

     (703,804 )     (239,442 )     (263,988 )

Cash flows from financing activities

      

Proceeds from long-term debt

     629,936       119,865       162,511  

Repayment of long-term debt

     (100,199 )     (304,240 )     (5,692 )

Proceeds from equity issuance

     100,919       —         —    

Proceeds from senior notes

     —         322,329       —    

Principal payments under capital lease obligations

     (148 )     (171 )     (244 )

Dividends

     (1,049 )     —         —    

Settlement of derivative instruments acquired

     876       (1,898 )     184  

Fees paid related to financing activities

     (8,107 )     (7,002 )     (1,360 )

Proceeds from termination fee

     —         —         3,500  

Fees paid related to IPO and merger activities

     (373 )     —         (1,400 )
                        

Net cash provided by financing activities

     621,8