10-K 1 d10k.htm FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2007 Form 10-K for the fiscal year ended December 31, 2007
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, 2007

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 Exchange Act.    Yes  ¨    No  x

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 is not contained herein, and will not be contained, to the best of the 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, accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act). (Check one)

 

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 voting stock 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 24, 2008.

 

 

 


Table of Contents
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

   23

Item 1B. Unresolved Staff Comments

   31

Item 2. Properties

   31

Item 3. Legal Proceedings

   31

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

   32

Part II

  

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

   33

Item 6. Selected Financial Data

   34

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

   35

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

   53

Item 8. Financial Statements and Supplementary Data

   55

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

   86

Item 9A. Controls and Procedures

   86

Item 9B. Other Information

   87

Part III

  

Item 10. Directors, Executive Officers and Corporate Governance

   88

Item 11. Executive Compensation

   90

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

   101

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

   102

Item 14. Principal Accountant Fees and Services

   105

Part IV

  

Item 15. Exhibits and Financial Statement Schedules

   106

Signatures

   109

 

i


Table of Contents
Index to Financial Statements

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.

 

1


Table of Contents
Index to Financial Statements

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.

 

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.

 

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 in future development costs divided by total proved reserve acquisitions, extensions and discoveries 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.

 

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.

 

MMcf

One million cubic feet of natural gas.

 

MMcfe

One million cubic feet of natural gas equivalents.

 

NYMEX

The New York Mercantile Exchange.

 

2


Table of Contents
Index to Financial Statements

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 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 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 unique 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.

 

Seismic survey

Also known as a seismograph survey, 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.

 

3


Table of Contents
Index to Financial Statements

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 through 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.

 

4


Table of Contents
Index to Financial Statements

PART I

Unless the context requires otherwise, references in this annual report to “Chaparral”, “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 gas industry in the “Glossary of terms” beginning on page 2.

 

ITEMS 1.    AND 2.    BUSINESS AND PROPERTIES

Chaparral Energy, Inc.

Chaparral is 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. 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 (“Calumet”) for a cash purchase price of approximately $500.0 million. Calumet owned properties principally located in Oklahoma and Texas were complementary to our existing core areas of operations and had estimated proved reserves of approximately 346 Bcfe. Calumet’s proved reserves are relatively long-lived, have relatively low production decline rates and are approximately 96% oil. In addition to increasing our current average net daily production, many of the acquired properties have significant drilling and EOR opportunities.

As of December 31, 2007, we had estimated proved reserves of 987 Bcfe (65% proved developed and 60% crude oil) with a PV-10 value of approximately $2.7 billion. For the year ended December 31, 2007, our average daily production was 111.3 MMcfe. As of December 31, 2007, our estimated reserve life was 24.3 years. For the year ended December 31, 2007, our oil and gas revenues were $366.0 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 pages 16 and 17.

For the period from 2004 to 2007, our proved reserves and production grew at a compounded annual growth rate of 31% and 29%, 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, 2007, we made capital expenditures of $230.2 million, including $106.1 million for development drilling and $49.8 million for acquisitions, of which $15.6 million was a release from escrow and other purchase price allocation adjustments of the prior year’s Calumet acquisition. The majority of our capital expenditures for developmental drilling in 2007 are 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.

Business Strengths

Consistent track record of low-cost reserve additions and production growth. From 2004 to 2007, we have grown reserves and production by a compounded annual growth rate of 31% and 29%, respectively. We have achieved this through a combination of drilling and acquisition success. Our reserve replacement ratio, which reflects our reserve additions in a given period stated as a percentage of our production in the same period, has

 

5


Table of Contents
Index to Financial Statements

averaged 664% per year since 2001. We replaced approximately 822%, 991% and 301%, as further discussed beginning on page 15, of our production in 2005, 2006 and 2007 respectively, at an average fully developed FD&A cost of $3.00 per Mcfe over this three-year period.

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 2005, 2006 and 2007, our capital expenditures for acquisitions of proved properties were $216.7 million, $484.4 million and $41.7 million, respectively. These acquisition capital expenditures represented approximately 65%, 73% and 18%, respectively, of our total capital expenditures and approximately 80%, 94% and 13%, respectively, of our increase in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries for those periods. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

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. As of December 31, 2007, we had an inventory of over 1,475 proved developmental drilling locations and 4,780 additional potential drilling locations, shown in the following table which combined represent over 18 years of drilling opportunities based on our 2008 drilling rate.

 

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

Net

Mid-Continent

   905    3,645    379,072    60,059

Permian Basin

   92    732    51,291    21,461

Gulf Coast

   11    69    44,718    11,887

Ark-La-Tex

   12    45    15,277    —  

North Texas

   352    193    19,445    5,676

Rocky Mountains

   103    96    15,201    9,794
                   

Total

   1,475    4,780    525,004    108,877
                   

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See “Risk factors” beginning on page 23. We have experienced a high historical drilling success rate of approximately 98% on a weighted average basis during 2005, 2006 and 2007. For the year ended December 31, 2007, we spent $106.1 million to drill 56 (52 net) operated wells and to participate in 167 (7 net) wells operated by others, representing 36% of our increases in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries. For 2008, we have budgeted $118.0 million to drill more than 130 operated wells and to participate in more than 200 wells operated by others. To support our drilling program, we have entered into agreements which allow access to approximately 43,000 square miles of non-proprietary 3-D seismic data, conducted four proprietary 3-D seismic shoots and received permits for one additional proprietary 3-D survey.

 

6


Table of Contents
Index to Financial Statements

Enhanced oil recovery expertise and assets. Beginning in 2000, we expanded our operations to include CO2 EOR. CO2 EOR involves the injection of CO2, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of 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, 2007, our proved reserves included four 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 an 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 plan to expand this polymer EOR program and ultimately introduce CO2 injection into this unit.

Experienced management team. Mark A. Fischer, our CEO 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 28 years of experience in the oil and gas industry. Individuals in our 23-person management team have an average of over 25 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, 2007, we spent approximately $106.1 million on development drilling, which represents 46% 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 $118.0 million, or approximately 56% of our capital expenditures, on developmental drilling in 2008.

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 2005 and 2006 we have also made larger acquisitions that complemented our existing properties in our core areas. During the year ended December 31, 2007, we made acquisitions of approximately $49.8 million, or 22% of our total capital expenditures for such period. Our 2008 acquisition capital budget for oil and gas properties is $35.0 million, or 17% of our total capital expenditure budget.

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 Chaparral 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, 2007, we had an inventory of 818 developed enhancement projects requiring total estimated capital expenditures of $43.8 million.

Expand CO2 EOR activities. We have accumulated interests in 54 properties in Oklahoma and Texas that meet our criteria for CO2 EOR operations and are expanding our CO2 pipeline system to initiate CO2 injection in

 

7


Table of Contents
Index to Financial Statements

certain of these properties. We began CO2 injection in our Perryton Unit in December 2006 and plan to begin CO2 injection in our NW Camrick Unit in late 2008. To support our existing CO2 EOR projects, we currently inject approximately 38.5 MMcf per day of purchased and recycled CO2. 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 in the panhandle of Oklahoma and southwestern Kansas that will enhance our CO2 plans in this area.

Pursue modest exploration program. In the current high-priced commodity environment, we believe a modest exploration program can provide a rate of return comparable or superior to property acquisitions in certain areas. We currently plan to spend $10.0 million, or approximately 5% of our 2008 capital expenditures, on exploration 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, 2007, we operated properties comprising approximately 84% of our proved reserves.

Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our proved developed production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of December 31, 2007, we had swaps in place for approximately 73% and 23% of our most recent internally estimated proved developed gas production for 2008 and 2009, respectively. We also had swaps in place for approximately 77% of our most recent internally estimated proved developed oil production for 2008 through 2011. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in losses on oil and gas hedging activities of $68.3 million, $4.2 million and $28.1 million for the years ended December 31, 2005, 2006 and 2007, respectively, through a period of increasing commodity prices. The years ended December 31, 2006 and 2007 also include non-hedge derivative losses of $4.7 and $23.8 million, respectively.

Oklahoma Ethanol L.L.C.

In April 2007, Oklahoma Ethanol L.L.C. agreed to construct and operate an ethanol plant in Blackwell, Oklahoma. The ethanol plant is estimated to produce a minimum of 50 million gallons of denatured ethanol annually. The ethanol plant is estimated to also generate approximately 8 MMcf per day of CO2, and we will have the option to acquire all or part of this CO2 for use in our EOR projects. The start up and construction costs for this joint venture are estimated to be between $115 million and $125 million, with Chaparral having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $69 million to $75 million in secured indebtedness with recourse limited to our interests in this entity to fund construction costs and for related start-up working capital. We expect construction to commence in late 2008 with completion in 2010, and that our equity contribution will be approximately $30 million to $33 million.

 

8


Table of Contents
Index to Financial Statements

Properties

The following table presents proved reserves and PV-10 value as of December 31, 2007 and average daily production for the year ended December 31, 2007 by our areas of operation.

 

     Proved reserves as of December 31, 2007    Average
daily
production
(MMcfe
per day)

Year ended
December 31,
2007
     Oil
(MBbl)
   Natural
gas

(MMcf)
   Total
(MMcfe)
   Percent
of total
MMcfe
    PV-10
value
($mm)
  

Mid-Continent

   83,061    259,022    757,388    76.7 %   $ 2,041.2    72.1

Permian Basin

   8,069    59,894    108,308    11.0 %     306.8    17.2

Gulf Coast

   2,201    38,324    51,530    5.2 %     139.6    10.4

Ark-La-Tex

   1,170    21,670    28,690    2.9 %     62.5    5.2

North Texas

   2,326    4,644    18,600    1.9 %     65.3    3.8

Rocky Mountains

   2,277    8,715    22,377    2.3 %     56.6    2.6
                                

Total

   99,104    392,269    986,893    100.0 %   $ 2,672.0    111.3
                                

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, 80% of our 2007 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, 2007 we owned interests in 8,627 gross (3,049 net) producing wells and we operated wells representing 84% 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, 2007, accounted for 77% of our proved reserves and 76% of our PV-10 value. We own an interest in 5,747 producing wells in the Mid-Continent, of which we operate 2,238. Our 11 largest properties in terms of PV-10 value, are located in this area. During the year ended December 31, 2007, our net average daily production in the Mid-Continent Area was approximately 72.1 MMcfe per day, or 65% 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 and is 23,080 acres in size and has a cumulative production of 316 MMBbl of oil (primary and secondary). The North Burbank Unit accounted for 204,622 MMcfe of our proved reserves, $438.7 million of our PV-10 value as of December 31, 2007 and 1,564 MMcfe of our year ended December 31, 2007 production. The producing zone is Red Fork and Bartlesville and occurs at a depth of 3,000 feet. We own 99.25% of the field and we are also the operator. As of December 31, 2007, the field was producing 1,450 Bbl per day from 240 producing wells. There are also 157 active injection wells and 544 temporarily abandoned wells at this time. Upside potential exist in restoring a majority of the temporarily abandoned wells to production and in expanding 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 per day to 1,200 Bbl 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 have already reinstituted a polymer flood on 485 acres adjacent to Block A on a 19 well pattern. Since taking over the field on November 1, 2006, we have already returned 32 temporarily abandoned wells to production with initial rates of production ranging between 6-25 Bbls per day. We believe that this field also may have upside with the injection of CO2.

 

9


Table of Contents
Index to Financial Statements

Camrick area—Beaver and Texas Counties, Oklahoma. The Camrick area represents approximately 5% of our proved reserves and 7% of our PV-10 value of our proved reserves (46,024 MMcfe and $198.6 million, respectively) at December 31, 2007. 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 MMBbl of primary reserves and approximately 13.1 MMBbl of secondary reserves. There are approximately 46 active producing wells in this area that produced 2,731 MMcfe during the year ended December 31, 2007. Currently CO2 injection operations are continuing in the Phase I and II areas of the Camrick Unit and the Perryton Unit. CO2 injection has improved the gross production in the Camrick Area from approximately 115 Bbls (690 Mcfe) per day in 2001 from 11 wells to approximately 1,578 Bbls (9,468 Mcfe) per day at the year end December 31, 2007 from 46 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 represents 3% of our proved reserves and PV-10 value or our proved reserves (34,968 MMcfe and $90.6 million, respectively) at December 31, 2007. 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 39.9 MMBbls of oil and 255.1 Bcf of natural gas since its discovery in 1946 and produced 1,202 MMcfe during the year ended December 31, 2007. 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 approximately 28 active producing wells in this unit. We are scheduled to drill 14 wells in 2008.

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Play accounted for 11,029 MMcfe of our proved reserves, $31.3 million of our PV-10 value of our proved reserves as of December 31, 2007 and 939 MMcfe of our year ended December 31, 2007 production. 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. We currently have interests in 25 Cleveland Sand producing wells, and we drilled three wells in each of 2005 and 2006. We drilled five wells in 2007 and have scheduled an additional 10 wells in 2008. We have employed horizontal drilling technology in most of our drilled wells in this area. We expect that future wells will utilize horizontal technology.

Velma Sims Unit CO2 Flood—Stephens County, Oklahoma. The EVWB Sims Sand Unit which covers approximately 1,300 acres was discovered in 1949 and was 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 15,777 MMcfe of our proved reserves, $47.7 million of our PV-10 value as of December 31, 2007 and 709 MMcfe of our year ended December 31, 2007 production. 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. We currently have 47 active producing wells in this unit.

Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit which is 2,235 acres was discovered in 1915 and unitized in 1977. This unit had proved reserves of 30,116 MMcfe and a PV-10 value of $109.2 million at December 31, 2007. We operate this unit with a working interest of 80.2%. 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 the unit currently has 63 producing wells and 46 active injection wells. The unit is currently producing 433 Bbls per day. We have completed a 4 well pilot drilling program to increase density drill the Fox Deese Springer Unit from its current 10 acre spacing to 5 acre spacing. Production from all

 

10


Table of Contents
Index to Financial Statements

four wells has added about 86 Bbls of oil per day to the unit production along with about 30 Bbls of oil per day from the Sims reservoir still under a retrievable bridge plug. This Sims reservoir is prospective in much of the field. With the successful completion of this pilot program, we believe this could open up 86 additional drilling locations in the area and have five wells planned as part of our 2008 drilling program. None of the Sims reserves were booked as PUD reserves at year end 2007. Additional potential exists in waterflood pattern modification and CO2 EOR recovery.

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 17,598 MMcfe of our proved reserves and $70.9 million of our PV-10 value at December 31, 2007. There are currently 27 producing wells and 15 active injection wells, with current production of approximately 267 Bbls per day. 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. Additional potential exists in deeper Ellenburger, as an Ellenburger well tested approximately 193 Bbls per day in 1964 in the adjacent East Sivells Bend Unit and one well in our unit tested 104 Bbls per day for a short time. 3D 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. Two wells are scheduled to be drilled in 2008 in this unit.

CO2 EOR—Various counties, Oklahoma and Texas. We have initiated CO2 injection in our Perryton Unit in December 2006 and anticipate initiating CO2 injection in our NW Camrick Unit in late 2008 and three Booker Inland units in 2008. We have in place transportation and supply agreements to provide the necessary CO2 for these projects. Including properties recently purchased in the Calumet acquisition, we have accumulated 54 properties in Oklahoma and Texas that meet our criteria for CO2 EOR operations. We have a 100% ownership and operate 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 we own 100% interest in approximately 126 miles of pipeline located in the panhandle of Oklahoma and southwestern Kansas. 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.

Permian Basin

The Permian Basin Area is the second of our two core areas and, as of December 31, 2007, accounted for 11% of our proved reserves and 11% of our PV-10 value. We own an interest in 1,497 wells in the Permian Basin, of which we operate 383. Three of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2007, our net average daily production in the Permian Basin Area was approximately 17.2 MMcfe per day, or 15% of our total net average daily production. Similar to the Mid-Continent Area, it is characterized by its 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 18,197 MMcfe of our proved reserves, $55.3 million of our PV-10 value at December 31, 2007 and 1,322 MMCfe of our year ended December 31, 2007 production. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 4,200 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 2006, we drilled ten wells in this play. We drilled eight wells in 2007 and have plans to drill 19 wells in 2008.

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 10 producing wells in this play. The Haley Area represents 16,737 MMcfe of our proved reserves, $41.7 million of our PV-10 value at December 31, 2007 and

 

11


Table of Contents
Index to Financial Statements

1,491 MMcfe of our year ended December 31, 2007 production. Production has been established from four main intervals: the Bone Springs at a depth of approximately 10,100–11,000 feet, the Atoka at a depth of approximately 16,000 feet, the Strawn at a depth of approximately 15,500 feet and 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, three 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. During 2007, we drilled two wells in this area. The Haley 38-3 is currently producing approximately 45 Bbl per day and 95 Mcf per day from the Bone Springs. The Haley 38-4 is currently producing approximately 46 Bbls per day and 49 Mcf per day from the Bone Springs. Additional developmental Bone Springs wells will follow. We are currently drilling the Bowdle Estate 47-2 to test the Morrow, which offsets an Anadarko well that is producing from the Morrow at 20 Mmcf per day. We also drilled the F.D. Russell #2 well which encountered several Atoka sands and is currently in the completion process.

Gulf Coast

The Gulf Coast is the most active of our four growth areas and, as of December 31, 2007, accounted for 5% of our proved reserves and 5% of our PV-10 value. We own an interest in 305 wells in the Gulf Coast area, of which we operate 209. 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 compliments our long-life reserves and adds a dimension for increasing our near-term cash flow.

Mustang Island & Mesquite Bay—Nueces County, TX. We own interest in approximately 9,018 net producing acres. Multiple producing sand intervals are found from depths of 6,500 feet to 8,000 feet. We now operate 10 active producing wells in this area. As of December 31, 2007, the wells in Nueces County, Texas account for 7,845 MMcfe of our proved reserves, $36.6 million of our PV-10 value and 219 MMcfe of our year ended December 31, 2007 production. We are currently processing a 60 sq. mile proprietary 3D 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.

Vivian Borchers Area—Lavaca County, Texas. We control approximately 1,300 acres in the Vivian Borchers Area. As of December 31, 2007, the wells in Lavaca County, Texas accounted for 1,762 MMcfe of our proved reserves, $4.8 million of our PV-10 value and 100 MMcfe of our year ended December 31, 2007 production. Multiple Frio and Miocene pay zones occur at depths shallower than 4,000 feet. Based on 3-D seismic reprocessing, we have successfully drilled and completed three wells to depths of approximately 4,000 feet. These wells had initial test rates as high as 900 Mcf of natural gas per day. In addition, we have several deep 3-D seismic based Wilcox tests planned for the area. We recently drilled the Vivian Borchers #2-14 to a depth of 13,000 ft., developed production from 12,116 to 12,582 ft. and as of January 2008 we are producing the well at 1,351 Mcf per day and 24 Bbls condensate per day. We have licensed 200 square miles of 3D seismic data and are currently evaluating it for additional prospects, similar to those mentioned above. As prospects are identified, we expect to propose and budget additional leasing and drilling activity.

Ark-La-Tex

As of December 31, 2007, the Ark-La-Tex area accounted for 3% of our proved reserves and 2% of our PV-10 value. We own an interest in 135 wells in the Ark-La-Tex area, of which we operate 71. These reserves are characterized by shorter life and higher initial potential.

North Texas

As of December 31, 2007, the North Texas area accounted for 2% of our proved reserves and 2% of our PV-10 value. We own an interest in 758 wells in the North Texas area, of which we operate 138. One of our four proprietary 3-D seismic surveys has been completed in this area.

 

12


Table of Contents
Index to Financial Statements

Rocky Mountains

As of December 31, 2007, the Rocky Mountains area accounted for 2% of our proved reserves and 2% of our PV-10 value. We own an interest in 185 wells in the Rocky Mountains area, of which we operate 48. Unlike our core areas, this area is not as well developed and holds potential for material upside growth.

Oil and Natural Gas Reserves

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2007. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (36% of PV-10 value) and by Lee Keeling & Associates, Inc. (52% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (12% of PV-10 value).

 

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

Developed—producing

   48,451    220,134    510,840    $  1,481,935

Developed—non-producing

   13,117    49,445    128,147    350,836

Undeveloped

   37,536    122,690    347,906    839,211
                   

Total proved

   99,104    392,269    986,893    $2,671,982
                   

The estimated reserve life as of December 31, 2005, 2006 and 2007 was 24.4, 28.0 and 24.3 years, respectively. The estimated reserve life was calculated by dividing total proved reserves by production volumes for the year indicated.

The following table sets forth the estimated future net revenues from proved reserves, the PV-10, the standardized measure of discounted future net cash flows and the prices used in projecting them over the past three years.

 

(Dollars in thousands, except prices)

   2005    2006    2007

Future net revenue

   $ 3,597,300    $ 3,518,020    $ 6,203,720

PV-10 value

     1,602,610      1,494,063      2,671,982

Standardized measure of discounted future net cash flows

     1,067,888      1,082,209      1,793,980

Oil price (per Bbl)

   $ 61.04    $ 61.06    $ 96.01

Natural gas price (per Mcf)

   $ 10.08    $ 5.64    $ 6.80

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, 2007 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 an interest, and net wells is the sum of our working interest in all wells.

 

     Total wells
     Gross    Net

Crude oil

   5,813    2,252

Natural gas

   2,814    797
         

Total

   8,627    3,049
         

 

13


Table of Contents
Index to Financial Statements

The following table details our gross and net interest in producing wells in which we have an interest and the number of wells we operated at December 31, 2007 by area.

 

     Total wells    Operated
Wells
     Gross    Net   

Mid-Continent

   5,747    2,191    2,238

Permian Basin

   1,497    402    383

Gulf Coast

   305    197    209

Ark-La-Tex

   135    72    71

North Texas

   758    141    138

Rocky Mountains

   185    46    48
              

Total

   8,627    3,049    3,087
              

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2007 by area.

 

     Developed    Undeveloped
     Gross    Net    Gross    Net

Mid-Continent

   901,522    379,072    69,970    60,059

Permian Basin

   88,616    51,291    22,521    21,461

Gulf Coast

   76,084    44,718    19,911    11,887

Ark-La-Tex

   27,817    15,277    —      —  

North Texas

   26,391    19,445    6,187    5,676

Rocky Mountains

   44,238    15,201    20,349    9,794
                   

Total

   1,164,668    525,004    138,938    108,877
                   

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 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.

 

     2005     2006     2007  
     Gross     Net     Gross     Net     Gross     Net  

Development wells

            

Productive

   171.0     52.0     189.0     56.1     214.0     51.7  

Dry

   2.0     0.8     1.0     0.2     3.0     1.2  

Exploratory wells

            

Productive

   11.0     6.0     1.0     1.0     6.0     5.9  

Dry

   1.0     0.4     1.0     0.1     0.0     0.0  

Total wells

            

Productive

   182.0     58.0     190.0     57.1     220.0     57.6  

Dry

   3.0     1.2     2.0     0.3     3.0     1.2  
                                    

Total

   185.0     59.2     192.0     57.4     223.0     58.8  
                                    

Percent productive

   98 %   98 %   99 %   99 %   99 %   98 %

 

14


Table of Contents
Index to Financial Statements

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, 2005, 2006 and 2007), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2005, 2006 and 2007 were prepared by Cawley, Gillespie & Associates (36% of PV-10 value in 2007) and Lee Keeling & Associates, Inc. (52% of PV-10 value in 2007). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (12% of PV-10 value).

 

     As of December 31,  

Proved Reserves

   2005     2006     2007  

Oil (Mbbl)

     33,913       88,378       99,104  

Natural gas (MMcf)

     414,384       375,311       392,269  

Natural gas equivalent (MMcfe)

     617,862       905,579       986,893  

Proved developed reserve percentage

     69 %     69 %     65 %

PV-10 value (in thousands)

   $ 1,602,610     $ 1,494,063     $ 2,671,982  

Estimated reserve life (in years)(1)

     24.4       28.0       24.3  

Cost incurred (in thousands):

      

Property acquisition costs

      

Proved properties(2)

   $ 216,742     $ 484,404     $ 41,724  

Unproved properties

     5,543       4,731       8,032  
                        

Total acquisition costs

     222,285       489,135       49,756  

Development costs

     103,479       170,987       165,177  

Exploration costs

     7,274       7,015       15,287  
                        

Total

   $ 333,038     $ 667,137     $ 230,220  
                        

Annual reserve replacement ratio(3)

     822 %     991 %     301 %

Three-year average fully developed FD&A cost ($/Mcfe)(4)

   $ 1.82     $ 2.37     $ 3.00  

 

(1) Calculated by dividing net proved reserves by net production volumes for the year indicated.
(2) Includes $152,945 and $464,860 of costs related to the acquisitions of CEI Bristol and Calumet in 2005 and 2006, respectively.
(3) Calculated by dividing the sum of reserve additions from all sources (revisions, extensions and discoveries, improved recoveries, and acquisitions) by the production for the corresponding period. The values for these reserves 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 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,  
     2005     2006     2007  
     Reserves
replaced
    Percent
of total
    Reserves
replaced
    Percent
of total
    Reserves
replaced
    Percent
of total
 

Purchases

   683 %   83.1 %   1,093 %   110.3 %   46 %   15.4 %

Extensions and discoveries

   89 %   10.8 %   52 %   5.2 %   214 %   70.9 %

Revisions

   (30 )%   (3.6 )%   (174 )%   (17.6 )%   (71 )%   (23.4 )%

Improved recoveries

   80 %   9.7 %   20 %   2.1 %   112 %   37.1 %
                                    

Total

   822 %   100.0 %   991 %   100.0 %   301 %   100.0 %
                                    

 

15


Table of Contents
Index to Financial Statements
(4) Calculated as total costs incurred, plus the increase in future development costs, divided by total proved reserve acquisitions, extensions and discoveries, and revisions as shown below (in Mcfe unless otherwise noted):

 

     2005     2006     2007  

Purchases of minerals in place

     173,176       354,004       18,850  

Extensions and discoveries

     22,531       16,736       86,788  

Revisions

     (7,516 )     (56,423 )     (28,684 )

Improved recoveries

     20,262       6,653       45,423  
                        

Total reserve additions

     208,453       320,970       122,377  
                        

Costs incurred

   $ 333,038     $ 667,137     $ 230,220  

Changes in future development costs

     154,042       236,700       337,438  
                        

Total costs incurred

   $ 487,080     $ 903,837     $ 567,658  
                        

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

   $ 1.82     $ 2.37     $ 3.00  

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,
     2005    2006    2007

Production:

        

Oil (MBbl)

     1,449      1,906      3,356

Natural Gas (MMcf)

     16,660      20,949      20,504
                    

Combined (MMcfe)

     25,354      32,385      40,640

Average daily production:

        

Oil (Bbls)

     3,970      5,222      9,195

Natural gas (Mcf)

     45,644      57,395      56,175
                    

Combined (Mcfe)

     69,464      88,727      111,345

Average prices (before effect of hedges):

        

Oil (per Bbl)

   $ 53.76    $ 61.65    $ 69.85

Natural Gas (per Mcf)

     7.41      6.29      6.41
                    

Combined (per Mcfe)

     7.94      7.69      9.00

Average costs per Mcfe:

        

Lease operating

   $ 1.66    $ 2.21    $ 2.57

Production tax

   $ 0.58    $ 0.58    $ 0.65

Depreciation, depletion, and amortization

   $ 1.24    $ 1.61    $ 2.11

General and administrative

   $ 0.39    $ 0.45    $ 0.54

Non-GAAP Financial Measure and Reconciliation

The PV-10 value (PV-10) is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at December 31, 2007 before deducting future income taxes, discounted at 10%. We believe that the presentation of the PV-10 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 corporate future 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,

 

16


Table of Contents
Index to Financial Statements

PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 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 as of December 31, 2007 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

   $ 2,041.2    $ 631.5    $ 1,409.7

Permian Basin

     306.8      116.1      190.7

Gulf Coast

     139.6      62.6      77.0

Ark-La-Tex

     62.5      22.6      39.9

North Texas

     65.3      26.1      39.2

Rocky Mountains

     56.6      19.1      37.5
                    

Total

   $ 2,672.0    $ 878.0    $ 1,794.0
                    

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;

 

   

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.

 

17


Table of Contents
Index to Financial Statements

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;

 

   

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.

 

18


Table of Contents
Index to Financial Statements

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, 2006 and 2007, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. In connection with our Calumet acquisition in October 2006, we identified certain properties with potential minor remediation needs. Management continues to evaluate potential environmental liabilities and the recording of the purchase price allocation. 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 2008 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, or 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, or 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, or 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 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, or 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

 

19


Table of Contents
Index to Financial Statements

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 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 costs in order to comply with new 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 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

 

20


Table of Contents
Index to Financial Statements

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 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.

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

 

21


Table of Contents
Index to Financial Statements

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 Gathering Regulations

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

 

22


Table of Contents
Index to Financial Statements

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, 2007, we had 726 full-time employees, including 12 geologists and geophysicists, 26 reservoir, production, and drilling engineers and 12 land professionals. Of these, 265 work in our Oklahoma City office and 461 are 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.

Oil and natural gas prices are volatile. A decline in oil and natural gas prices could adversely affect our financial position, 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;

 

23


Table of Contents
Index to Financial Statements
   

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. 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.

We could incur a write-down of the carrying values of our properties in the future depending on oil and natural gas prices, 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 unit-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. A significant decline in oil and natural gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown 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 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, 2007 future cash flows used realized prices based on a Henry Hub spot price of $6.80 per MMBtu for natural gas and a WTI Cushing spot price of $96.01 per Bbl for oil.

 

24


Table of Contents
Index to Financial Statements

A significant portion of total proved reserves as of December 31, 2007 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2007, approximately 35% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and EOR operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct.

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, 2007, 14% of our proved reserves were based on EOR methods including the injection of CO2 and polymers, a synthetic chemical. Some of these properties have not been injected with CO2 or with polymers having the identical chemical composition as polymers used in historical production, and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or 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 material adverse affect 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, 2007, our total debt was $1,114.2 million. Our maximum commitment amount and the borrowing base under our Seventh Restated Credit Agreement was $525.0 million as of November 1, 2007. We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future.

 

   

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 will 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 of, premium, if any, accrued and unpaid interest, and liquidated damages, if any, on such indebtedness to be due and payable.

 

25


Table of Contents
Index to Financial Statements

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

Availability under our new Seventh Restated Credit Agreement is subject to a borrowing base, which was $525.0 million as of November 1, 2007, 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 results.

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 35% of our total estimated proved reserves (by volume) at December 31, 2007 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will

 

26


Table of Contents
Index to Financial Statements

require significant capital expenditures and successful drilling and EOR operations. Our historical December 31, 2007 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 13.5%, 10.8% and 8.1% 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.

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

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted.

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

 

27


Table of Contents
Index to Financial Statements

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;

 

   

unitization and pooling of properties;

 

   

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

 

   

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; and

 

   

other environmental damages.

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. 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 New York Mercantile Exchange, or 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, 2007, we had entered into swaps for 17,840 MMcf of our natural gas production for 2008 through 2009 at average monthly prices ranging from $7.79 to $9.15 per Mcf of natural gas. As of December 31, 2007, we had entered into swaps for 8,509 MBbl of our crude oil production for 2008 through 2011 at average monthly prices ranging from $63.16 to $70.33 per Bbl of oil. As of December 31, 2007, we had basis protection swaps for 11,240 Mcf for 2008 through 2009 at average monthly prices ranging from $0.81 to $1.16 per mcf. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2007 was a liability of approximately $150.5 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 contract obligations; or

 

   

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

 

28


Table of Contents
Index to Financial Statements

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 as a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will be offset against the change in fair value of the hedged assets, liabilities or firm commitments through income, or will be 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, will be immediately recognized in income. If it is probable the oil or gas sales which are hedged will not occur or the hedge is not highly effective, hedge accounting is discontinued and the effect is immediately recognized in income.

Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, if a derivative which qualified for cash flow hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination would remain in accumulated other comprehensive income (loss) and would be amortized into oil and gas sales over the original term of the instrument. No derivatives were liquidated or sold prior to maturity during 2005, 2006, or 2007.

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 CEO, 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

 

29


Table of Contents
Index to Financial Statements

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.

If Mark A. Fischer ceases to be either our Chairman, CEO or President in connection with a change of control, such event could also result in a change of control event occurring under our senior credit agreement, the indenture governing our outstanding senior notes or our Phantom Unit 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.

 

30


Table of Contents
Index to Financial Statements

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;

 

   

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, 2007 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 $525.0 million, equal to our borrowing base at December 31, 2007, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.25 million.

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 Item 1. Business—Oil and Gas Operations. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See “Commitments and Obligations” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 14, “Commitments and Contingencies,” to the Consolidated Financial Statements for the future minimum rental payments. 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 of approximately $14.4 million 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 value

 

31


Table of Contents
Index to Financial Statements

of the receivable was calculated in accordance with the securities purchase agreement and intend to diligently 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. As of December 31, 2007, the recorded receivable was approximately $14.4 million and was recorded in other assets 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

None.

 

32


Table of Contents
Index to Financial Statements

PART II

 

ITEM 5. MARKET PRICE 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 24, 2008, we had 877,000 shares of common stock outstanding held by three record holders.

Cash dividends of $1.0 million was paid during the year ended December 31, 2006. Dividends of $0.4 million were paid on a quarterly basis from January 1, 2005 through September 30, 2006 and a one-time dividend of $2.0 million was paid on February 1, 2005. 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.

 

33


Table of Contents
Index to Financial Statements
ITEM 6. SELECTED FINANCIAL DATA

You should read the following historical financial data of Chaparral 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, 2007 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 share and per share amounts)

   2003     2004     2005     2006     2007  

Operating results data:

          

Revenues

          

Oil and gas sales

   $ 74,186     $ 113,546     $ 201,410     $ 249,180     $ 365,958  

Loss on oil and gas hedging activities

     (12,220 )     (21,350 )     (68,324 )     (4,166 )     (28,140 )

Service company sales

     —         —         —         —         20,611  
                                        

Total revenues

     61,966       92,196       133,086       245,014       358,429  
                                        

Costs and expenses

          

Lease operating

     19,520       26,928       42,147       71,663       104,469  

Production taxes

     4,840       8,272       14,626       18,710       26,216  

Depreciation, depletion and amortization

     10,376       17,533       31,423       52,299       85,842  

General and administrative

     4,946       5,985       9,808       14,659       21,838  

Service company expenses

     —         —         —         —         18,441  
                                        

Total costs and expenses

     39,682       58,718       98,004       157,331       256,806  
                                        

Operating income

     22,284       33,478       35,082       87,683       101,623  
                                        

Non-operating income (expense)

          

Interest expense

     (4,116 )     (6,162 )     (15,588 )     (45,246 )     (87,656 )

Non-hedge derivative losses

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

Other income

     208       279       665       792       2,276  
                                        

Net non-operating expense

     (3,908 )     (5,883 )     (14,923 )     (49,131 )     (109,161 )

Income (loss) from continuing operations before income taxes, minority interest and accounting change

     18,376       27,595       20,159       38,552       (7,538 )

Income tax expense (benefit)

     6,932       9,880       7,309       14,817       (2,745 )

Minority interest

     —         —         —         (71 )     —    
                                        

Income (loss) from continuing operations before accounting change

     11,444       17,715       12,850       23,806       (4,793 )

Cumulative effect of change in accounting principle, net of income taxes

     (887 )     —         —         —         —    
                                        

Net income (loss)

   $ 10,557     $ 17,715     $ 12,850     $ 23,806     $ (4,793 )
                                        

Income (loss) per share from continuing operations (basic and diluted)

   $ 14.77     $ 22.86     $ 16.58     $ 29.74     $ (5.47 )

Income (loss) per share from accounting change, net

     (1.15 )     —         —         —         —    
                                        

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

   $ 13.62     $ 22.86     $ 16.58     $ 29.74     $ (5.47 )
                                        

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

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

Cash flow data:

          

Net cash provided by operating activities

   $ 32,541     $ 46,870     $ 55,744     $ 89,198     $ 113,858  

Net cash used in investing activities

     (55,213 )     (92,141 )     (325,068 )     (703,848 )     (239,857 )

Net cash provided by financing activities

     26,146       54,061       257,080       621,855       128,883  

 

     As of December 31,  

(Dollars in thousands)

   2003     2004     2005     2006     2007  

Financial position data:

          

Cash and cash equivalents

   $ 5,052     $ 13,842     $ 1,598     $ 8,803     $ 11,687  

Total assets

     211,086       308,827       647,379       1,331,435       1,530,898  

Total debt

     118,355       176,622       446,544       976,272       1,114,237  

Retained earnings

     30,977       48,692       58,126       80,883       76,090  

Accumulated other comprehensive loss, net of income taxes

     (4,900 )     (12,107 )     (47,967 )     (3,946 )     (73,839 )

Total equity

     26,078       36,586       10,167       177,864       103,178  

Cash dividends per common share

     —         —       $ 4.40     $ 1.35       —    

 

34


Table of Contents
Index to Financial Statements
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, 2007, we had estimated proved reserves of 987 Bcfe, with a PV-10 value of $2.7 billion. Our reserves were 65% proved developed 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.

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.

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 13.5%, 10.8% and 8.1% 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.

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

 

   

the amount of estimated revenues from oil and gas sales;

 

   

the quantity of our proved oil and gas reserves;

 

   

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

 

35


Table of Contents
Index to Financial Statements
   

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.

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

 

   

Private equity sale. On September 29, 2006, we sold an aggregate of 102,000 shares of Chaparral’s 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 owns properties principally located in Oklahoma and Texas, areas which are complementary to our core areas of operations. Proved reserves attributable to the acquisitions were in excess of 346 Bcfe. Calumet’s proved reserves are long-lived, have low production decline rates and are approximately 96% oil. In addition to increasing our current average net daily production, many of the properties have significant drilling and EOR opportunities. Additionally, as part of the transaction, we acquired Calumet’s hedging arrangements, which included hedge swaps of 75 MBbls of oil per month at $66.10 per barrel during 2006, 75 MBbls per month at $63.00 per barrel during 2007 and 30 MBbls per month at $68.10 during 2008.

 

   

Production Tax Credit. During 2006, the Company purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. The Company’s expected return on the investment will be 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.

 

   

Oklahoma Ethanol. In August 2005, we entered a joint venture, Oklahoma Ethanol, L.L.C. to construct and operate an ethanol production plant in Oklahoma. We spent approximately $1.7 million toward the design for the construction of the plant for the year ended December 31, 2007.

 

   

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 $25.0 million. Approximately $5.0 million of the purchase price was deposited into escrow as security for certain potential working capital, environmental and employment adjustments. 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 was used to pay down outstanding amounts under our Credit Agreement.

 

36


Table of Contents
Index to Financial Statements

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.

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 %

Rockies

   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 )
                

 

37


Table of Contents
Index to Financial Statements

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   

Oil (per Bbl):

        

Year ended December 31, 2006

   $ 61.65    $ 47.32    76.8 %

Year ended December 31, 2007

     69.85      59.38    85.0 %

Gas (per Mcf):

        

Year ended December 31, 2006

   $ 6.29    $ 7.39    117.5 %

Year ended December 31, 2007

     6.41      6.76    105.5 %

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      85,842    64.1 %     1.61      2.11    31.1 %

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 26% increase in production volumes and an approximate 17% increase in 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 unit plan in efforts to meet market demand and recruit and maintain essential personnel. Approximately $0.4 million of the increase was due to the revision in the phantom unit 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.

 

38


Table of Contents
Index to Financial Statements

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:

 

     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 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 $18.4 million, for a net profit of $2.2 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 the year of 2006.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

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)
 
     2005    2006   

Oil and gas sales (dollars in thousands)

        

Oil

   $ 77,899    $ 117,504    50.8 %

Gas

     123,511      131,676    6.6 %
                

Total

   $ 201,410    $ 249,180    23.7 %

Production

        

Oil (MBbls)

     1,449      1,906    31.5 %

Gas (MMcf)

     16,660      20,949    25.7 %
                

MMcfe

     25,354      32,385    27.7 %

Average sales prices (excluding hedging)

        

Oil per Bbl

   $ 53.76    $ 61.65    14.7 %

Gas per Mcf

     7.41      6.29    (15.1 )%
                

Mcfe

   $ 7.94    $ 7.69    (3.2 )%

 

39


Table of Contents
Index to Financial Statements

Oil sales increased 50.8% from $77.9 million to $117.5 million during the year ended December 31, 2006. This increase was due to a 31.5% increase in production volumes to 1,906 MBbls and a 14.7% increase in average oil prices to $61.65 per barrel. Natural gas sales revenues increased 6.6% from $123.5 million for the year ended December 31, 2005 to $131.7 million for the year ended December 31, 2006. This increase was due to a 25.7% increase in production volumes to 20,949 Mmcf, partially offset by a 15.1% decrease in average gas prices to $6.29 per Mcf. Oil and gas production for the year ended December 31, 2006 increased due primarily to the addition of volumes from acquisitions, our expanded drilling program and enhancements of our existing properties. Approximately 1,655 MMcfe of the increase was due to the Calumet acquisition.

Production volumes by area were as follows (MMcfe):

 

     Year ended December 31,    Percent
Increase
 
         2005            2006       

Mid Continent

   16,314    19,499    19.5 %

Permian

   3,790    5,497    45.0 %

Gulf Coast

   2,418    3,348    38.5 %

Ark-La-Tex

   1,162    1,724    48.4 %

North Texas

   817    1,119    37.0 %

Rockies

   853    1,198    40.4 %
            

Totals

   25,354    32,385    27.7 %
            

The effects of hedging on our net revenues for the years ended December 31, 2005 and 2006 are as follows:

 

     Year ended December 31,  

(dollars in thousands)

       2005             2006      

Gain (loss) from oil and gas hedging activities:

    

Hedge settlements

   $ (53,584 )   $ (22,927 )

Hedge ineffectiveness

     (14,740 )     18,761  
                

Total

   $ (68,324 )   $ (4,166 )
                

Our loss from oil and gas hedging settlements in 2006 decreased $30.7 million due to improved hedge positions in relation to commodity prices from 2006 compared to 2005. Additionally as a result of lower NYMEX forward strip gas prices at December 31, 2006 compared to December 31, 2005, hedge ineffectiveness resulted in a gain of $18.8 million in 2006 compared to a loss of $14.7 million in 2005.

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   

Oil (per Bbl):

        

Year ended December 31, 2005

   $ 53.76    $ 36.43    67.8 %

Year ended December 31, 2006

     61.65      47.32    76.8 %

Gas (per Mcf):

        

Year ended December 31, 2005

   $ 7.41    $ 4.82    65.0 %

Year ended December 31, 2006

     6.29      7.39    117.5 %

 

40


Table of Contents
Index to Financial Statements

Costs and Expenses. The following table presents information about our operating expenses for each of the years ended December 31, 2005 and 2006:

 

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

(dollars in thousands)

   2005    2006      2005    2006   

Lease operating expenses

   $ 42,147    $ 71,663    70.0 %   $ 1.66    $ 2.21    33.1 %

Production taxes

     14,626      18,710    27.9 %     0.58      0.58    0.0 %

Depreciation, depletion and amortization

     31,423      52,299    66.4 %     1.24      1.61    29.8 %

General and administrative

     9,808      14,659    49.5 %     0.39      0.45    15.4 %

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 $5.1 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 $9.5 million of costs associated with workovers in 2006 compared to $4.5 million in 2005.

Production taxes (which include ad valorem taxes)—Increase was due primarily to a 28% increase in production volumes.

Depreciation, depletion and amortization—Increase was due primarily to an increase in DD&A on oil and gas properties of $19.4 million. For oil and gas properties, $10.2 million of the increase was due to higher production volumes in 2006 and $9.2 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 $0.36 to $1.45 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. Approximately $0.9 million, or $0.03 per mcfe, of the increase related to due diligence costs incurred in connection with the Calumet acquisition and other Calumet related general and administrative expenses. Approximately $0.5 million, or $0.02 per mcfe, of the increase was due to costs incurred in connection with a postponed initial public offering. G&A expense is net of $8.3 million in 2006 and $6.2 million in 2005 capitalized as part of our exploration and development activities.

Interest expense. Interest expense increased by $29.7 million, or 190%, compared to 2005, primarily as a result of increased levels of borrowings and higher interest rates paid. Approximately $25.9 million of the increase is due to the issuance of the 8 1/2% Senior Notes on December 1, 2005.

Non-hedge derivative losses. Non-hedge derivative losses were $4.7 million for the year 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. There were no non-hedge derivatives in 2005.

Liquidity and Capital Resources

Overview. Our primary sources of liquidity are cash generated from our operations, issuance of equity and our revolving credit line. At December 31, 2007, we had approximately $11.7 million of cash and cash equivalents and $76.3 million of availability under our revolving credit line with a borrowing base of $525.0 million. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit 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

 

41


Table of Contents
Index to Financial Statements

depending on the timing and amount of any equity funding received and the availability of acquisition opportunities that meet our investment criteria.

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.

In this section we describe our current plans for capital expenditures, identify the resources available to fund the capital expenditures and discuss the principal factors that can affect our liquidity and capital resources.

Capital expenditures. For the year ended December 31, 2007, we incurred actual costs as summarized by area in the following table:

 

(Dollars in thousands)

   For the year ended
December 31, 2007(1)
   Percent
of total
 

Mid-Continent

   $ 130,430    56.7 %

Permian Basin

     46,928    20.4 %

Gulf Coast

     30,661    13.3 %

Ark-La-Tex

     7,246    3.1 %

North Texas

     7,557    3.3 %

Rocky Mountains

     7,398    3.2 %
             
   $ 230,220    100 %
             

 

(1) Includes $0.3 million of additions relating to increases in Chaparral’s asset retirement obligations.

In addition to the capital expenditures for oil and gas properties, we spent approximately $23.9 million for acquisition and construction of new office and administrative facilities and equipment during 2007.

Our actual costs incurred for the year ended December 31, 2007 and our current 2008 budgeted capital expenditures for oil and gas properties are detailed in the table below:

 

(Dollars in thousands)

   For the year ended
December 31, 2007(1)
   2008 budgeted capital
expenditures(3)

Development activities:

     

Developmental drilling

   $ 106,146    $ 118,000

Enhancements

     43,887      29,000

EOR

     15,144      17,000

Acquisitions:

     

Proved properties(2)

     41,724      30,000

Unproved properties

     8,032      5,000

Exploration activities

     15,287      10,000
             

Total

   $ 230,220    $ 209,000
             

 

(1) Includes $0.3 million of additions relating to increases in Chaparral’s asset retirement obligations.
(2) The 2008 acquisition budget does not include an anticipated ethanol plant investment of approximately $30 to $33 million.
(3) Our current 2008 capital expenditure budget for oil and gas properties is $209.0 million assuming we receive net proceeds of $70.0 million from an issuance of our equity which we are considering during 2008.

 

42


Table of Contents
Index to Financial Statements

Our 2008 budgeted development and exploratory drilling and EOR capital expenditures summarized by area are detailed in the table below:

 

(Dollars in thousands)

   2008 drilling
capital
expenditures
   Percent
of total
 

Mid-Continent

   $ 64,000    44 %

Permian Basin

     57,000    39 %

Gulf Coast

     21,000    15 %

North Texas

     1,500    1 %

Other

     1,500    1 %
             
   $ 145,000    100 %
             

A majority of our capital expenditure budget for development drilling in 2008 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. We also have budgeted increased capital expenditures for our CO2 EOR projects in the Mid-Continent and Permian Basin.

We continually evaluate our capital needs and compare them to our estimated funds available. Our actual expenditures during fiscal 2008 may be higher or lower than our budgeted amounts. The final determination with respect to the drilling of any well, including those currently budgeted, will depend on a number of factors, including the results of our development and exploration efforts, the availability of sufficient capital resources by us and other participants for drilling prospects, economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, our financial results and the availability of leases on reasonable terms and permitting for the potential drilling locations.

Cash provided from operating activities. Substantially all of our cash flow from operating activities is from the production and sale of oil and gas adjusted by associated 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, 2007, the net cash provided from operations was approximately 47% of our net cash used in investing activities. For the year ended December 31, 2007, cash flow from operating activities increased by 28% from the prior year. This increase was due primarily to an increase in oil and gas sales revenue and reduced settlement losses on hedging activities partially offset by higher operating expense.

Our current credit facility. As of December 31, 2007, we had $447.0 million outstanding under our Credit Agreement and the borrowing base was $525.0 million. We believe we are in compliance with all covenants under the Credit Agreement as of December 31, 2007.

 

43


Table of Contents
Index to Financial Statements

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 generally accepted accounting principles. 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, 2006 and 2007, our current ratio as computed using generally accepted accounting principles was 0.88 and 0.69, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.15 and 1.49, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

 

(Dollars in thousands)

   December 31,
2006
    December 31,
2007
 

Current assets per GAAP

   $ 91,863     $ 120,704  

Plus—Availability under Credit Agreement

     112,136       76,311  

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

     (847 )     (19,123 )

Less—Short-term derivative instruments

     (7,599 )     —    
                

Current assets as adjusted

   $ 195,553     $ 177,892  
                

Current liabilities per GAAP

   $ 104,255     $ 174,980  

Less—Short-term derivative instruments

     (12,376 )     (54,307 )

Less—Short-term asset retirement obligation

     (749 )     (1,000 )
                

Current liabilities as adjusted

   $ 91,130     $ 119,673  
                

Current ratio for loan compliance

     2.15       1.49  
                

In 2005, the Company entered into a Sixth Restated Credit Agreement, which provided for a revolving credit line equal to the lesser of $450,000 or the borrowing base. The borrowing base was determined based on reserve value, among other factors. Effective May 25, 2006, the borrowing base was adjusted to $200,000. Effective September 11, 2006, the borrowing base was adjusted to $250,000. In October 2006, the Company 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. Effective November 1, 2007 the borrowing base was adjusted to $525,000. Interest is paid at least every three months on $634,000 based upon LIBOR and $3,000 based on an Alternative Base Rate, as defined in the credit agreement as of December 31, 2006 (effective rate of 7.375% and 8.750%, respectively) and on $447,000 based upon LIBOR as of December 31, 2007 (effective rate of 7.163%). The credit line is collateralized by the Company’s 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.

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.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At December 31, 2007, $447.0 million of our borrowings were Eurodollar loans.

 

44


Table of Contents
Index to Financial Statements

Interest on Eurodollar loans is computed at LIBOR, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the agreement, plus a margin where the margin varies from 1.25% to 2.50% depending on the utilization percentage of the conforming borrowing base. At December 31, 2007, the LIBOR rate was 4.88%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.28% resulting in an effective interest rate of 7.16% 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.

Commitment fees of 0.25% to 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 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;

 

   

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.

The Credit Agreement requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 to 1.0 and 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;

 

   

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.

 

45


Table of Contents
Index to Financial Statements

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.

We believe we were in compliance with all covenants under the Credit Agreement as of December 31, 2007.

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

 

   

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.

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 are 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.

 

46


Table of Contents
Index to Financial Statements

In addition, upon completion of a qualified equity offering prior to December 1, 2008, we are entitled to redeem up to 35% of the aggregate principal amount of the 8 1/2% Senior Notes from the proceeds, so long as:

 

 

 

we pay to the holders of such notes a redemption price of 108.5% of the principal amount of the 8 1/2% Senior Notes, plus accrued and unpaid interest to the date of redemption; and

 

 

 

at least 65% of the aggregate principal amount of the 8 1/2% Senior Notes remains outstanding after each such redemption, other than 8 1/2% Senior Notes held by us or our affiliates.

Finally, 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.

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 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 are 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.

 

47


Table of Contents
Index to Financial Statements

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.

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. Once complete, the exchange offer must remain open for at least 20 business days. If we fail to complete the exchange offer within 270 days after the closing date, we will 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 will increase an additional 0.25% for each additional 90 days, up to a total of 1.0%. Once the exchange offer has been completed by us, the liquidated damages will cease to accrue.

During September 2007, we determined that the exchange offer would not be 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.

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.

 

48


Table of Contents
Index to Financial Statements

Contractual obligations. The following table summarizes our contractual obligations and commitments as of December 31, 2007:

 

(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 expense

   $ 32,019    $ 487,024    $ —      $ —      $ 519,043

Senior notes, including estimated interest expense

     56,246      112,492      112,492      873,471      1,154,701

Other long-term notes—including estimated interest expense

     7,861      11,478      2,592      349      22,280

Capital leases—including estimated interest

     164      19      —        —        183

Operating leases

     477      43      —        —        520

Abandonment obligations

     1,000      2,000      2,000      25,684      30,684

Derivative obligations

     54,307      70,613      25,614      —        150,534

Total

   $ 152,074    $ 683,669    $ 142,698    $ 899,504    $ 1,877,945

 

(1) As of December 31, 2007, the Company has no off-balance sheet arrangements.

In 2006, we entered into an agreement to build a natural gas pipeline to transport gas to an ethanol plant expected to be constructed and operational in early 2008. As of December 31, 2007, the pipeline is being constructed, and the costs are currently estimated to be approximately $2.2 million.

We have long-term contracts to purchase up to all of the CO2 manufactured at three ethanol plants. Two of the plants are operating and, based on plant capacity, it is estimated that we will purchase approximately 4.2 MMcf per day over the ten-year contract term under one contract, and under the second contract approximately 13.75 MMcf per day over the fifteen-year contract term. Pricing under both contracts is variable over time and both contracts have the possibility of renewal. The third ethanol plant has not yet been constructed but, when constructed, we will purchase approximately 5.5 MMcf per day at variable contract prices over the ten-year contract term with the possibility of renewal.

We have two additional long-term 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 through July 1, 2010. We have historically taken less CO2 than the maximum allowed in the contract and based on our current level, we project we would purchase approximately 16.0 MMcf per day over the remainder of the term of the contract. We may also purchase a variable amount of CO2 under the second contract, up to 10.0 Mmcf per day through August 23, 2016, and we are currently purchasing 5.0 MMcf per day and project our purchases to remain at that level. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

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.

 

49


Table of Contents
Index to Financial Statements

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural 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 crude 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, or 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 that the change in the fair value of the contract offsets the changes in the expected future cash flows from our forecasted production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) on oil and gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in our consolidated statements of stockholders’ equity. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) on oil and gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment are marked to their period end market values with changes reported in earnings, and our consolidated statements of operations could include large non-cash fluctuations, particularly in volatile pricing environments.

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. and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 88% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2007 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% plus the lower of cost or fair market value of unevaluated properties. The ceiling calculation

 

50


Table of Contents
Index to Financial Statements
 

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 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, exploratory wells currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

 

   

Future development and abandonment costs. Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and 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”. 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

 

51


Table of Contents
Index to Financial Statements

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 September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. However, in February, 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. The Company is currently assessing the impact, if any, of the adoption of SFAS 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which the Company elects the fair value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS No. 159 to have a material impact to its consolidated financial statements.

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 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. The Company is currently assessing the impact, if any, the adoption of SFAS No. 141(R) may have on any future acquisitions.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51. “ 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 as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company is 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 addresses concerns that the existing disclosure requirements in SFAS 133, Accounting for Derivatives and Hedging Activities, 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

 

52


Table of Contents
Index to Financial Statements

interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently assessing the impact, if any, of the adoption of SFAS 161.

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.

 

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, 2007 production, our gross revenues from oil and gas sales would change approximately $2.1 million for each $0.10 change in gas prices and $3.4 million for each $1.00 change in oil prices.

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

We also use derivative financial instruments 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 delivery 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.

 

53


Table of Contents
Index to Financial Statements

In anticipation of the acquisition of Calumet, we entered into additional crude oil swaps in September and October 2006 to provide protection against a decline in the price of oil from the date of entering into a Securities Purchase Agreement and the close of the transaction on October 31, 2006. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 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. Our outstanding oil and natural gas derivative instruments as of December 31, 2007 are summarized below:

 

    Natural Gas basis
protection swaps
  Natural Gas Swaps     Crude Oil Swaps  
    Non-hedge   Hedge         Hedge   Non-hedge      
    Volume
MMcf
  Weighted
average
fixed price
to be
received
  Volume
MMcf
  Weighted
average
fixed price
to be
received
  Percent of
PDP
production
hedged(1)
    Volume
MBbl
  Weighted
average
fixed price
to be
received
  Volume
MBbl
  Weighted
average
fixed price
to be
received
  Percent of
PDP
production(1)(2)
 

1Q 2008

  2,070   $ 1.16   3,760   $ 8.50   71.9 %   624   $ 69.74   60   $ 67.48   80.6 %

2Q 2008

  2,220     0.81   3,720     7.83   74.1 %   600     69.59   60     67.63   79.4 %

3Q 2008

  2,220     0.81   3,460     7.91   72.9 %   580     69.33   60     67.64   80.0 %

4Q 2008

  2,120     0.90   3,300     8.23   73.1 %   550     69.86   74     67.41   80.6 %

1Q 2009

  2,070     0.92   900     9.08   20.9 %   495     69.82   111     67.15   80.8 %

2Q 2009

  540     0.82   900     8.14   21.8 %   477     68.83   90     66.94   77.6 %

3Q 2009

  —       —     900     8.23   23.2 %   465     68.15   90     66.57   80.5 %

4Q 2009

  —       —     900     8.59   24.1 %   456     67.58   90     66.18   81.0 %

1Q 2010

  —       —     —       —     —       420     67.40   102     65.80   79.3 %

2Q 2010

  —       —     —       —     —       420     67.10   90     65.47   79.4 %

3Q 2010

  —       —     —       —     —       408     66.43   90     65.10   79.2 %

4Q 2010

  —       —     —       —     —       402     65.95   90     64.75   79.8 %

1Q 2011

  —       —     —       —     —       309     64.40   99     64.24   68.8 %

2Q 2011

  —       —     —       —     —       309     64.06   90     63.93   68.7 %

3Q 2011

  —       —     —       —     —       309     63.71   90     63.61   70.2 %

4Q 2011

  —       —     —       —     —       309     63.33   90     63.30   71.5 %
                           
  11,240     17,840       7,133     1,376    
                           

 

(1) Based on our most recent internally estimated PDP production for such periods.
(2) Percentage includes both hedge and non-hedge swaps.

Subsequent to December 31, 2007, we entered into additional natural gas swaps for 2,160 MMcf for the periods of February 2008 through December 2009 at a weighted average price of $8.19. We also entered into additional crude oil swaps for 110 MBbl for the periods of March 2008 through December 2009 at a weighted average price of $90.41.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of December 31, 2007 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 $525.0 million, equal to our borrowing base at December 31, 2007, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.25 million.

 

54


Table of Contents
Index to Financial Statements
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

   56

Consolidated balance sheets as of December 31, 2006 and 2007

   57

Consolidated statements of operations for the years ended December 31, 2005, 2006 and 2007

   58

Consolidated statements of stockholders’ equity and comprehensive income (loss) for the years ended December 31, 2005, 2006 and 2007

   59

Consolidated statements of cash flows for the years ended December 31, 2005, 2006 and 2007

   60

Notes to consolidated financial statements

   62

 

55


Table of Contents
Index to Financial Statements

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, 2006 and 2007, 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, 2007. 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, 2006 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

 

/s/    GRANT THORNTON LLP        

Oklahoma City, Oklahoma

March 31, 2008

 

56


Table of Contents
Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

 

      December 31,  

(dollars in thousands, except share data)

   2006     2007  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 8,803     $ 11,687  

Accounts receivable, net

     62,728       66,105  

Inventories

     7,505       19,480  

Deferred income taxes

     968       19,128  

Prepaid expenses

     4,260       4,304  

Derivative instruments

     7,599       —    
                

Total current assets

     91,863       120,704  

Property and equipment—at cost, net

     31,809       50,747  

Oil & gas properties, using the full cost method:

    

Proved

     1,254,230       1,477,096  

Unproved (excluded from the amortization base)

     18,299       25,327  

Accumulated depreciation, depletion and amortization

     (121,859 )     (200,577 )
                

Total oil & gas properties

     1,150,670       1,301,846  

Funds held in escrow

     23,385       5,224  

Other assets

     33,708       52,377  
                
   $ 1,331,435     $ 1,530,898  
                

Liabilities and stockholders’ equity

    

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 67,997     $ 77,540  

Accrued interest payable

     3,078       14,741  

Revenue distribution payable

     17,249       21,471  

Current maturities of long-term debt and capital leases

     3,555       6,921  

Derivative instruments

     12,376       54,307  
                

Total current liabilities

     104,255       174,980  

Long-term debt and capital leases, less current maturities

     647,717       459,826  

8 1/2% Senior Notes, due 2015

     325,000       325,000  

8 7/8% Senior Notes, due 2017

     —         322,490  

Derivative instruments

     2,300       96,227  

Deferred compensation

     771       2,017  

Asset retirement obligations

     27,377       29,684  

Deferred income taxes

     46,151       17,496  

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, 2006 and 2007, respectively

     9       9  

Additional paid in capital

     100,918       100,918  

Retained earnings

     80,883       76,090  

Accumulated other comprehensive loss, net of taxes

     (3,946 )     (73,839 )
                
     177,864       103,178  
                
   $ 1,331,435     $ 1,530,898  
                

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

 

57


Table of Contents
Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

 

     Year Ended December 31,  

(dollars in thousands, except share and per share amounts)

   2005     2006     2007  

Revenues:

      

Oil and gas sales

   $ 201,410     $ 249,180     $ 365,958  

Loss from oil and gas hedging activities

     (68,324 )     (4,166 )     (28,140 )

Service company sales

     —         —         20,611  
                        

Total revenues

     133,086       245,014       358,429  

Costs and expenses:

      

Lease operating

     42,147       71,663       104,469  

Production tax

     14,626       18,710       26,216  

Depreciation, depletion and amortization

     31,423       52,299       85,842  

General and administrative

     9,808       14,659       21,838  

Service company expenses

     —         —         18,441  
                        

Total costs and expenses

     98,004       157,331       256,806  

Operating income

     35,082       87,683       101,623  

Non-operating income (expense):

      

Interest expense

     (15,588 )     (45,246 )     (87,656 )

Non-hedge derivative losses

     —         (4,677 )     (23,781 )

Other income

     665       792       2,276  
                        

Net non-operating expense

     (14,923 )     (49,131 )     (109,161 )

Income (loss) before income taxes and minority interest

     20,159       38,552       (7,538 )

Income tax expense (benefit)

     7,309       14,817       (2,745 )

Minority interest

     —         (71 )     —    
                        

Net income (loss)

   $ 12,850     $ 23,806     $ (4,793 )
                        

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

   $ 16.58     $ 29.74     $ (5.47 )

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

     775,000       800,500       877,000  

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

 

58


Table of Contents
Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity

and comprehensive income (loss)

 

(dollars in thousands)

  Members’ units/
Common Stock
  Additional
Paid In
Capital
  Undistributed/
Retained
earnings
    Accumulated
other
comprehensive
income (loss)
    Total  
  Units/Shares     Amount        

Balance at January 1, 2005

  50,000,000     $ 1   $ —     $ 48,692     $ (12,107 )   $ 36,586  

Conversion from LLC to C Corporation

  (49,225,000 )     7     —       (7 )     —         —    

Dividends

  —         —       —       (3,409 )     —         (3,409 )

Net income

  —         —       —       12,850       —         12,850  

Other comprehensive income (loss), net

           

Unrealized loss on hedges, net of taxes of $42,970

  —         —       —       —         (68,749 )     (68,749 )

Reclassification adjustment for hedge losses included in net income, net of taxes of $20,695

  —         —       —       —         32,889       32,889  
                 

Total comprehensive loss

              (23,010 )
     

Balance at December 31, 2005

  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 (loss), 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 income (loss), net

           

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

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

Reclassification adjustment for hedge losses included in net income, 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  

 

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

 

59


Table of Contents
Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

 

    Year Ended December 31,  

(dollars in thousands)

  2005     2006     2007  

Cash flows from operating activities

     

Net income (loss)

  $ 12,850     $ 23,806     $ (4,793 )

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

     

Depreciation, depletion & amortization

    31,423       52,299       85,842  

Deferred income taxes

    7,637       14,839       (2,729 )

Unrealized (gain) loss on ineffective portion of hedges

    14,740       (18,761 )     8,343  

Non-cash change in fair value of derivative instruments

    —         4,681       23,781  

Gain on sale of assets

    (231 )     (132 )     (712 )

Other

    162       1,151       1,243  

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

     

Accounts receivable

    (7,979 )     (13,213 )     (13,635 )

Inventories

    (2,961 )     (329 )     3,704  

Prepaid expenses and other assets

    (270 )     376       (1,079 )

Accounts payable and accrued liabilities

    4,784       16,659       8,426  

Revenue distribution payable

    (4,936 )     7,696       4,221  

Deferred compensation

    525       126       1,246  
                       

Net cash provided by operating activities

    55,744       89,198       113,858  

Cash flows from investing activities

     

Purchase of property and equipment and oil and gas properties

    (170,570 )     (201,300 )     (221,066 )

Acquisition of a business, net of cash acquired

    (113,622 )     (466,656 )     (21,569 )

Payment on non-hedge derivative transactions assumed in acquisition of a business

    (42,108 )     —         —    

Cash in escrow

    —         (21,795 )     (2,156 )

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

    1,202       5,820       526  

Proceeds from sale of a business

    —         —         3,158  

Purchase of prepaid production tax asset

    —         (15,000 )     —    

Other

    30       (4,917 )     1,250  
                       

Net cash used in investing activities

    (325,068 )     (703,848 )     (239,857 )

Cash flows from financing activities

     

Proceeds from long-term debt

    122,676       629,936       119,865  

Repayment of long-term debt and acquisition financing

    (309,383 )     (100,199 )     (304,240 )

Proceeds from equity issuance

    —         100,919       —    

Proceeds from acquisition financing

    132,000       —         —    

Proceeds from senior notes

    325,000       —         322,329  

Principal payments under capital lease obligations

    (442 )     (148 )     (171 )

Dividends

    (3,409 )     (1,049 )     —    

Settlement of derivative instruments acquired

    —         876       (1,898 )

Fees paid related to financing activities

    (9,195 )     (8,107 )     (7,002 )

Fees paid related to IPO activities

    (167 )     (373 )     —    
                       

Net cash provided by financing activities

    257,080       621,855       128,883  
                       

Net increase (decrease) in cash and cash equivalents

    (12,244 )     7,205       2,884  

Cash and cash equivalents at beginning of period

    13,842       1,598       8,803  
                       

Cash and cash equivalents at end of period

  $ 1,598     $ 8,803     $ 11,687  
                       

Supplemental cash flow information

     

Cash paid (received) during the period for:

     

Interest, net of capitalized interest

  $ 12,590     $ 44,068     $ 73,822  

Income taxes

    (328 )     (22 )     (16)  

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

 

60


Table of Contents
Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(continued)

 

Supplemental disclosure of noncash investing and financing activities

During the years ended December 31, 2005, 2006, and 2007 the Company entered into capital lease obligations of $70, $140, and $21, respectively, for machinery and equipment.

During the years ended December 31, 2005, 2006 and 2007, the Company recorded non-cash additions to oil and gas properties of $9,367, $7,317 and $24,527, respectively. Non cash additions to oil and gas properties in 2007 includes $15,597 related to final settlement of the Calumet acquisition.

During the years ended December 31, 2005, 2006, and 2007, the Company recorded an asset and related liability of $4,680, $10,813 and $266, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $3 was capitalized during the year ended December 31, 2005 primarily related to the construction of the Company’s office building and other construction projects. Interest of $1,001 and $1,613 was capitalized during the years ended December 31, 2006 and 2007, respectively, primarily related to unproved oil and gas leaseholds.

 

61


Table of Contents
Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(Dollars in thousands, unless otherwise noted)

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

Chaparral Energy, Inc. and subsidiaries, (collectively, “we”, “our”, “us” or the “Company”) is involved in the acquisition, exploration, development, production and operation of oil and gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, Montana and Wyoming.

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

Principles of consolidation

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

The loss from operations related to the minority interest of Oklahoma Ethanol, LLC is shown separately in the statement of operations. As the minority interests’ share of the losses has exceeded their equity and there is no obligation for the minority interest holders to fund those losses, the minority interest balance is reported as zero in the consolidated balance sheet and all losses are therefore recognized by the Company. If future earnings materialize, the Company will recognize all earnings up to the amount of those losses previously absorbed.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and gas reserves, valuation allowances associated with deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.

Accounts receivable

The Company has receivables from joint interest owners and oil and gas purchasers which are generally uncollateralized. The Company generally reviews these parties for credit worthiness and general financial condition. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. Accounts receivable past due 90 days or more and still accruing interest at December 31, 2006 and 2007 were $1,034 and $1,060, respectively. The Company determines its allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and gas properties operated by the Company and the owner’s ability to pay its obligation, among other things.

 

62


Table of Contents
Index to Financial Statements

The Company writes off accounts receivable when they are determined to be uncollectible. Bad debt expense (recovery) for the years ended December 31, 2005, 2006, and 2007 was $140, $553, and $(11), respectively. Interest accrues beginning on the day after the due date of the receivable. When the account is determined to be uncollectible, all interest previously accrued but not collected is reversed against current interest income. Accounts receivable consisted of the following at December 31:

 

     2006     2007  

Joint interests

   $ 13,771     $ 19,319  

Accrued oil and gas sales

     32,763       40,377  

Service company sales

     —         4,827  

Receivable from purchase price adjustment

     14,406       —    

Other

     2,084       1,920  

Allowance for doubtful accounts

     (296 )     (338 )
                
   $ 62,728     $ 66,105  
                

Inventories

Inventories are comprised of equipment used in developing oil and gas properties, oil and gas production inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the specific identification method and average cost method, respectively. Oil and gas product inventories are stated at the lower of production cost or market. The Company regularly reviews inventory quantities on hand and records provisions for excess or obsolete inventory if necessary. Inventories at December 31, 2006 and 2007 consist of the following:

 

     December 31,
2006
   December 31,
2007

Equipment inventory

   $ 4,832    $ 3,027

Oil and gas product

     2,673      3,221

Service company inventory for resale

     —        13,232
             
   $ 7,505    $ 19,480
             

Property and equipment

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

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

 

Furniture and fixtures

   10 years

Automobiles and trucks

   5 years

Machinery and equipment

   10 – 20 years

Office and computer equipment

   5 – 10 years

Building and improvements

   10 – 40 years

Oil and gas properties

The Company uses the full-cost method of accounting for oil and gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the exploration for and development of oil and gas reserves. Proceeds from disposition of oil and gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion

 

63


Table of Contents
Index to Financial Statements

rate. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

Depreciation, depletion and amortization of oil and gas properties are provided 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 upon their relative energy content. The Company’s cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and the anticipated proceeds from salvaging equipment. Depreciation, depletion and amortization expense of oil and gas properties was $27,650, $47,086, and $78,717 for the years ended December 31, 2005, 2006, and 2007, respectively.

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 the Company’s cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties.

Production tax benefit asset

During 2006, the Company purchased interests in two venture capital limited liability companies resulting in a total investment of $15,000. The Company’s expected return on the investment will be 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, 2006, and 2007, the carrying value of the production tax benefit assets was $15,000 and $14,255, respectively, and was included in other assets in the consolidated balance sheets. Of the $1,490 received in 2007, $745 was recognized as income and $745 as a reduction of the asset.

Funds held in escrow

The Company has funds held in escrow that are restricted as to withdrawal or usage. The restricted amounts consisted of the following at December 31:

 

     2006    2007

Title defect escrow from acquisition

   $ 21,795    $ 383

Plugging and abandonment escrow

     1,590      1,635

Post closing adjustment escrow from acquisition

     —        3,206
             
   $ 23,385    $ 5,224
             

Upon clearing of the title defects, the amount in escrow will be disbursed. If the title defects are not cleared in a manner satisfactory to the Company, the amount will be returned to the Company.

The Company is entitled to make quarterly withdrawals from the plugging escrow account equal to one-half of the interest earnings for the period and as reimbursement for actual plugging and abandonment expenses incurred on the North Burbank field which was included in the Calumet acquisition, provided that written documentation has been provided. The balance is not intended to reflect the Company’s total future financial obligation for the plugging and abandonment of these wells.

 

64


Table of Contents
Index to Financial Statements

Impairment of long-lived assets

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

Deferred income taxes

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

In July 2006, the FASB issued interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB statement No. 109, (“FIN 48”). FIN 48 prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on a tax return. Under FIN 48, tax positions are recognized in our consolidated financial statements as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities assuming full knowledge of the position and all relevant facts. These amounts are subsequently reevaluated and changes are recognized as adjustments to current period tax expense. FIN 48 also revised disclosure requirements to include an annual tabular rollforward of unrecognized tax benefits.

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, we recognized no material adjustment in our tax liability for unrecognized income tax benefits. At the adoption date of January 1, 2007, we had approximately $100 of unrecognized tax benefits, all of which would affect our effective tax rate if recognized. At December 31, 2007, the unrecognized tax benefit amount was unchanged from adoption.

If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2007, we have not accrued interest related to uncertain tax positions.

The tax years 1998-2006 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

Revenue recognition

Oil revenue is recognized when the product is delivered to the purchaser and natural gas revenue when delivered to the gas purchaser’s sales meter. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Service company sales are recognized at the time of delivery of materials or performance of service.

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. The Company recognizes gas imbalances on the sales method and, accordingly, has recognized revenue on all production delivered to its purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability

 

65


Table of Contents
Index to Financial Statements

is recorded for the Company’s obligation for natural gas taken by its purchasers which exceeds the Company’s ownership interest of the well’s total production. The Company’s aggregate imbalance due to over production is approximately 1,866,000 thousand cubic feet (mcf), 1,903,000 mcf, and 1,961,000 mcf at December 31, 2005, 2006, and 2007, respectively. The Company’s aggregate imbalance due to under production is approximately 3,313,000 mcf, 3,331,000 mcf, and 3,170,000 mcf at December 31, 2005, 2006, and 2007, respectively.

Derivative transactions

The Company uses price swaps to reduce the effect of fluctuations in crude oil and natural gas prices. The Company accounts for these transactions in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires that the Company recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation. Derivatives that are not hedges must be adjusted to fair value through income.

If the derivative qualifies as a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will be offset against the change in fair value of the hedged assets, liabilities or firm commitments through income, or will be 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, will be immediately recognized in income. If it is probable the oil or gas sales which are hedged will not occur or the hedge is not highly effective, hedge accounting is discontinued and the effect is immediately recognized in income.

Under SFAS No. 133, if a derivative which qualified for cash flow hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination would remain in accumulated other comprehensive income (loss) and would be amortized into oil and gas sales over the original term of the instrument. No derivatives were liquidated or sold prior to maturity during 2005, 2006, or 2007. The ineffective portions of derivative gains or losses are reported in loss from oil and gas hedging activities on the consolidated statements of operations.

Asset retirement obligations

The Company accounts for asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. These obligations to abandon and restore properties are based upon estimated future costs which may change based upon future inflation rates and changes in statutory remediation rules.

Environmental liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2006 and 2007, the Company has not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon financial position, operating results, or the cash flows of the Company.

 

66


Table of Contents
Index to Financial Statements

Earnings per share

Basic earnings per share is computed by dividing net income attributable to all classes of common shareholders by the weighted average number of shares of all classes of common stock outstanding during the applicable period. Diluted earnings per share is determined in the same manner as basic earnings per share except that the number of shares is increased to assume exercise of potentially dilutive securities outstanding during the periods presented. There were no potentially dilutive securities outstanding during the periods presented.

Recently issued accounting standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. However, in February, 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. The Company is currently assessing the impact, if any, of the adoption of SFAS 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which the Company elects the fair value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS No. 159 to have a material impact on its consolidated financial statements.

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 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. The Company is currently assessing the impact, if any, the adoption of SFAS No. 141(R) may have on any future acquisitions.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51. “ 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 as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company is 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 addresses concerns that the existing disclosure requirements in SFAS 133, Accounting for

 

67


Table of Contents
Index to Financial Statements

Derivatives and Hedging Activities, 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, with early application encouraged. The Company is currently assessing the impact, if any, of the adoption of SFAS 161.

Note 2: Significant acquisitions

Calumet—On October 31, 2006 the Company acquired all the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates (“Calumet”) for an aggregate cash purchase price of approximately $500,000. The purchase price was paid in cash and financed through an increase in the Company’s existing senior revolving credit facility. As a result of the acquisition, Calumet Oil Company and JMG Oil and Gas, LP became wholly-owned subsidiaries and the results of operations have been included in the consolidated statements of operations since October 31, 2006. Calumet owns properties principally located in Oklahoma and Texas, areas which are complementary to our core areas of operations. In addition to increasing our current average net daily production, many of the properties have significant drilling and EOR opportunities.

Pursuant to the purchase agreement with Calumet, the Company estimated and recorded a receivable of $14,412 due from the previous owners related to working capital at the time of acquisition. The value of the receivable is estimated in accordance with the purchase contract as of December 31, 2006, and is included in other assets as of December 31, 2007. The estimated receivable may differ from the final settlement amount and may result in an adjustment to the purchase price.

At the closing date of the sale, the Company withheld and deposited into escrow $31,900 of the purchase price payment for oil and gas properties to which title defects were determined during the due diligence process. Pursuant to the agreement, upon clearing of the title defects by the previous owners of Calumet the amount in escrow will be disbursed. If the title defects for a specific property are not cleared in a manner satisfactory to the Company, the amount escrowed for that property will be returned to the Company. As of December 31, 2007, the escrow balance was $383 for defects yet to be cleared.

As part of the purchase, the previous owners of Calumet agreed to make a Section 338 election pursuant to the Internal Revenue Code, and the Company agreed to reimburse the owners for the amount of depreciation recapture recorded. As of December 31, 2007, the Company has recorded an estimated liability of $4,378 related to the election. The estimated payable may differ from the final settlement amount and may result in an adjustment to the purchase price. The liability balance is recorded in accounts payable and accrued liabilities on the accompanying consolidated balance sheets.

Green Country Supply—On April 16, 2007, the Company acquired all of the outstanding shares of common stock of Green Country Supply, Inc. (“GCS”) for an aggregate cash purchase price of $25,000, subject to certain post-closing adjustments. The purchase price was paid in cash and financed through the Company’s existing line of credit. 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. As a result of the acquisition, GCS became a wholly-owned subsidiary and the results of operations have been included in the consolidated statement of operations since April 16, 2007. We believe the acquisition of GCS will allow the Company to better control its costs and generate additional revenue through sales to third parties.

At the closing date of the sale, the Company withheld and deposited into escrow $5,029 of the purchase price for certain working capital, environmental and employment adjustments. Pursuant to the agreement, upon settlement of the various requirements, the amount in escrow will be disbursed. If the requirements are not met, the amount escrowed will be returned to the Company. As of December 31, 2007, $3,206 remained in escrow.

 

68


Table of Contents
Index to Financial Statements

The acquisition was accounted for using the purchase method in accordance with the provisions of SFAS No. 141, Business Combinations. The purchase price allocation of the GCS acquisition is preliminary and subject to additional adjustments. The Company expects to complete the final allocation in the next 6 months. The calculation of the purchase price and the allocation to assets and liabilities are shown below.

 

      GCS  

Calculation and allocation of purchase price:

  

Cash payment

   $ 25,000  

Cash deposited in escrow

     (3,083 )
        

Total purchase price

     21,917  
        

Plus fair value of liabilities assumed:

  

Accounts payable and accrued expenses

     5,242  
        

Total purchase price plus liabilities assumed

   $ 27,159  
        

Fair value of assets acquired:

  

Current assets, including cash of $348

   $ 23,307  

Property and equipment

     3,016  

Intangible assets

     836  
        

Total fair value of assets acquired

   $ 27,159  
        

The intangible assets primarily consist of fair value of customer lists which are being amortized over 84 months.

The unaudited pro forma information of the Company set forth below includes the operations of GCS for years ended December 31, 2006 and 2007 as if the acquisition occurred on January 1, 2006. The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined.

 

      Year ended
December 31, 2006
   Year ended
December 31, 2007
 

(dollars in thousands, except per share data)

   As
reported
   Pro forma    As
reported
    Pro
forma
 

Revenue

   $ 245,014    $ 278,415    $ 358,429     $ 366,786  
                              

Net income (loss)

   $ 23,806    $ 26,079    $ (4,793 )   $ (4,551 )

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

   $ 29.74    $ 32.58    $ (5.47 )   $ (5.19 )

Note 3: Property and equipment

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

 

     2006    2007

Furniture and fixtures

   $ 1,132    $ 1,437

Automobiles and trucks

     8,807      11,559

Machinery and equipment

     11,288      19,253

Office and computer equipment

     5,303      6,006

Building and improvements

     12,074      13,532
             
     38,604      51,787

Less accumulated depreciation and amortization

     10,813      14,622
             
     27,791      37,165

Work in progress

     1,446      8,552

Land

     2,572      5,030
             
   $ 31,809    $ 50,747
             

 

69


Table of Contents
Index to Financial Statements

Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:

 

     2006    2007

Office and computer equipment

   $ 1,762    $ 1,783

Machinery and equipment

     82      82
             
     1,844      1,865

Less accumulated depreciation and amortization

     1,312      1,675
             
   $ 532    $ 190
             

Note 4: Derivative activities and financial instruments

Derivative activities

The Company’s 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, the Company enters into swap agreements. For swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

The Company also uses derivative financial instruments 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 delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays 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 No. 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses.

In connection with the Calumet acquisition, the Company entered into additional commodity swaps and swaption contracts to provide protection against a decline in the price of oil. The swaptions gave the Company the option, but not the obligation, to enter into fixed price oil swaps under which we would receive a fixed commodity price and pay a floating market price, resulting in a net amount due to or from the counterparty. The cost of the swaption contracts was $2,790. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses.

As part of the Calumet acquisition, the Company assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $838. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the price assumed in the original fair value calculation.

 

70


Table of Contents
Index to Financial Statements

Pursuant to SFAS 133, the change in fair value of the acquired cash flow hedges from the date of acquisition is recorded as a component of accumulated other comprehensive income (loss). In addition, the hedge instruments are deemed to contain a significant financing element, and all cash flows associated with these positions are reported as a financing activity in the consolidated statement of cash flows for the periods in which settlement occurs.

All derivative financial instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying forward market price at the determination date considering the time value of money.

The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.

 

     December 31,  
     2006     2007  

Derivative assets (liabilities):

    

Gas swaps

   $ 10,118     $ 4,709  

Oil swaps

     (16,349 )     (155,782 )

Natural gas basis differential swaps

     (846 )     539  
                
   $ (7,077 )   $ (150,534 )
                

Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later transferred to earnings when the hedged transaction occurs. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. The ineffective portion of the hedge derivatives and the settlement of effective cash flow hedges is included in loss from oil and gas hedging activities in the consolidated statements of operations and is comprised of the following:

 

     Year ended December 31,  
     2005     2006     2007  

Reclassification of settled contracts

   $ (53,584 )   $ (22,927 )   $ (19,797 )

Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting

     (14,740 )     18,761       (8,343 )
                        
   $ (68,324 )   $ (4,166 )   $ (28,140 )
                        

Based upon market prices at December 31, 2007 the Company expects to charge $29,033 of the balance in accumulated other comprehensive loss to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of December 31, 2007 are expected to be settled by December 2011.

The changes in fair value and settlement of derivative contracts that do not qualify as hedges in accordance with SFAS 133 are recognized as non-hedge derivative losses. Non-hedge derivative losses in the consolidated statements of operations is comprised of the following:

 

     Year Ended
December 31,
 
     2006     2007  

Unrealized loss on non-qualified derivative contracts

   $ (3,746 )   $ (24,416 )

Unrealized gain (loss) on natural gas basis differential contracts

     (846 )     1,385  

Loss on settlement of natural gas basis differential contracts

     (85 )     (750 )
                
   $ (4,677 )   $ (23,781 )
                

 

71


Table of Contents
Index to Financial Statements

Hedge settlement payments of $3,444, and $8,759 were included in accounts payable and accrued liabilities at December 31, 2006 and 2007, respectively. Hedge settlement receivables of $759 and $51 were included in accounts receivable at December 31, 2006 and 2007, respectively.

Fair Value of Financial Instruments

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value for Long-term debt and capital leases at December 31, 2006 and 2007 approximates fair value because substantially all debt carries variable market rates. Based on market prices, at December 31, 2006, the carrying value of the 8 1/2 Senior Notes due 2015 approximates fair value. Based on market prices, at December 31, 2007, the fair value of the 8 1/2% Senior Notes and 8 7/8% Senior Notes were $291,688 and $293,313, respectively.

Fair value amounts have been estimated using available market information and valuation methodologies. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of hedge instruments and accounts receivable. Hedge instruments are exposed to credit risk from counterparties. Counterparties to the Company’s hedge instruments are primarily affiliates of its lenders and, therefore, the Company believes the counterparty risk is not significant. Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties the Company operates. The industry concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.

Sales of oil and natural gas to one purchaser accounted for 14.3% and 11.3% of total oil and natural gas revenues, excluding the effects of