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EX-32.2 - SECTION 906 CFO CERTIFICATION - Chaparral Energy, Inc.dex322.htm
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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-Q

 

 

 

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

For the quarterly period ended March 31, 2011

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 number: 333-134748

 

 

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   73-1590941

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

701 Cedar Lake Boulevard

Oklahoma City, Oklahoma

  73114
(Address of principal executive offices)   (Zip code)

(405) 478-8770

(Registrant’s telephone number, including area code)

 

 

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

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

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

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

 

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

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

1,411,040 shares of the registrant’s Common Stock were outstanding as of May 13, 2011.

 

 

 


Table of Contents

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

 

     Page  

Part I. FINANCIAL INFORMATION

  

Item 1. Financial Statements

     6   

Consolidated balance sheets as of March 31, 2011 (unaudited) and December 31, 2010

     6   

Consolidated statements of operations for the three months ended March 31, 2011 and 2010 (unaudited)

     8   

Consolidated statements of cash flows for the three months ended March 31, 2011 and 2010 (unaudited)

     9   

Notes to consolidated financial statements (unaudited)

     11   

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     29   

Overview

     29   

Liquidity and capital resources

     30   

Results of operations

     36   

Non-GAAP financial measure and reconciliation

     43   

Critical accounting policies and estimates

     44   

Recent accounting pronouncements

     46   

Item 3. Quantitative and qualitative disclosures about market risk

     47   

Item 4. Controls and procedures

     49   

Part II. OTHER INFORMATION

     50   

Item 1. Legal Proceedings

     50   

Item 1A. Risk Factors

     50   

Item 6. Exhibits

     51   

Signatures

     52   

EX-31.1 (Certification by CEO required by rule 13a-14(a)/15d-14(a))

  

EX-31.2 (Certification by CFO required by rule 13a-14(a)/15d-14(a))

  

EX-32.1 (Certification by CEO pursuant to section 906)

  

EX-32.2 (Certification by CFO pursuant to section 906)

  

 

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

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

 

   

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

 

   

the amount, nature and timing of capital expenditures;

 

   

drilling, completion and performance of wells;

 

   

competition and government regulations;

 

   

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

 

   

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

 

   

increases in proved reserves;

 

   

operating costs and other expenses;

 

   

cash flow and anticipated liquidity;

 

   

estimates of proved reserves;

 

   

exploitation of property acquisitions; and

 

   

marketing of oil and natural gas.

 

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Table of Contents

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. These risks and uncertainties include those factors described under the heading “Risk Factors” in our Annual Report on Form 10-K filed with the SEC on March 29, 2011. Specifically, some factors that could cause actual results to differ include:

 

   

the significant amount of our debt;

 

   

worldwide demand for oil and natural gas;

 

   

volatility and declines in oil and natural gas prices;

 

   

drilling plans (including scheduled and budgeted wells);

 

   

the number, timing or results of any wells;

 

   

changes in wells operated and in reserve estimates;

 

   

supply of CO2;

 

   

future growth and expansion;

 

   

future exploration;

 

   

integration of existing and new technologies into operations;

 

   

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

 

   

borrowings and capital resources and liquidity;

 

   

changes in strategy and business discipline;

 

   

future tax matters;

 

   

any loss of key personnel;

 

   

future seismic data (including timing and results);

 

   

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

 

   

geopolitical events affecting oil and natural gas prices;

 

   

outcome, effects or timing of legal proceedings;

 

   

the effect of litigation and contingencies;

 

   

the ability to generate additional prospects; and

 

   

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

Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The terms defined in this section are used throughout this Form 10-Q:

 

   

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

 

   

BBtu. One billion British thermal units.

 

   

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

 

   

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

 

   

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

 

   

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

 

   

MBoe. One thousand barrels of crude oil equivalent.

 

   

Mcf. One thousand cubic feet of natural gas.

 

   

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

 

   

MMBoe. One million barrels of crude oil equivalent.

 

   

MMcf. One million cubic feet of natural gas.

 

   

NYMEX. The New York Mercantile Exchange.

 

   

PDP. Proved developed producing.

 

   

Proved reserves. The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

 

   

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

 

   

SEC. The Securities and Exchange Commission.

 

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Table of Contents

PART I — FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

 

(dollars in thousands, except per share data)

   March 31,
2011
(unaudited)
    December 31,
2010
 

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 79,628      $ 55,111   

Accounts receivable, net

     71,425        62,780   

Inventories

     9,944        11,068   

Prepaid expenses

     1,645        2,429   

Derivative instruments

     —          1,429   

Deferred income taxes

     17,459        9,531   
                

Total current assets

     180,101        142,348   

Property and equipment—at cost, net

     67,579        66,014   

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

    

Proved

     2,335,079        2,253,662   

Unevaluated (excluded from the amortization base)

     22,070        19,135   

Accumulated depreciation, depletion, amortization and impairment

     (1,033,795     (1,003,261
                

Total oil and natural gas properties

     1,323,354        1,269,536   

Derivative instruments

     31        —     

Deferred income taxes

     32,280        20,617   

Other assets

     32,939        30,777   
                
   $ 1,636,284      $ 1,529,292   
                

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

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets - continued

 

(dollars in thousands, except per share data)

   March 31,
2011
(unaudited)
    December 31,
2010
 

Liabilities and stockholders’ equity

    

Current liabilities:

    

Accounts payable and accrued liabilities

   $ 86,311      $ 75,982   

Accrued payroll and benefits payable

     12,209        13,427   

Accrued interest payable

     24,713        23,695   

Revenue distribution payable

     19,481        17,223   

Current maturities of long-term debt and capital leases

     3,975        4,167   

Derivative instruments

     62,898        28,853   
                

Total current liabilities

     209,587        163,347   

Long-term debt and capital leases, less current maturities

     16,662        16,686   

Senior notes, net

     1,016,393        941,234   

Derivative instruments

     22,671        2,482   

Deferred compensation

     795        981   

Asset retirement obligations

     41,488        41,005   

Commitments and contingencies (Note 7)

    

Stockholders’ equity:

    

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

     —          —     

Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 58,192 and 51,346 shares issued and outstanding as of March 31, 2011 and December 31, 2010, respectively

     —          —     

Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 357,882 shares issued and outstanding

     4        4   

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

     2        2   

Class D Common stock, $0.01 par value, 10,000,000 shares authorized and 279,999 shares issued and outstanding

     3        3   

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

     5        5   

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

     —          —     

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

     —          —     

Additional paid in capital

     419,042        417,834   

Accumulated deficit

     (129,529     (89,265

Accumulated other comprehensive income, net of taxes

     39,161        34,974   
                
     328,688        363,557   
                
   $ 1,636,284      $ 1,529,292   
                

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

 

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Table of Contents

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

 

     Three months ended
March 31,
 

(dollars in thousands)

   2011
(unaudited)
    2010
(unaudited)
 

Revenues:

    

Oil and natural gas sales

   $ 127,599      $ 100,375   

Loss from oil and natural gas hedging activities

     (6,755     (4,985

Other revenues

     1,145        871   
                

Total revenues

     121,989        96,261   

Costs and expenses:

    

Lease operating

     27,556        24,419   

Production taxes

     8,624        6,990   

Depreciation, depletion, and amortization

     33,977        24,521   

General and administrative

     8,008        6,440   

Other expenses

     1,082        704   
                

Total costs and expenses

     79,247        63,074   
                

Operating income

     42,742        33,187   

Non-operating income (expense):

    

Interest expense

     (23,710     (22,552

Non-hedge derivative gains (losses)

     (60,926     31,057   

Loss on extinguishment of debt

     (20,576     —     

Other income (expense)

     47        (159
                

Net non-operating income (expense)

     (105,165     8,346   
                

Income (loss) from operations before income taxes

     (62,423     41,533   

Income tax expense (benefit)

     (22,159     16,069   
                

Net income (loss)

   $ (40,264   $ 25,464   
                

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

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

 

     Three months ended
March 31,
 

(dollars in thousands)

   2011
(unaudited)
    2010
(unaudited)
 

Cash flows from operating activities

    

Net income (loss)

   $ (40,264   $ 25,464   

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

    

Depreciation, depletion & amortization

     33,977        24,521   

Deferred income taxes

     (22,159     16,074   

Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments

     6,755        (519

Non-hedge derivative (gains) losses

     60,926        (31,057

Other

     737        215   

Change in assets and liabilities

    

Accounts receivable

     (7,281     276   

Inventories

     1,026        170   

Prepaid expenses and other assets

     22,033        2,393   

Accounts payable and accrued liabilities

     7,942        (3,360

Revenue distribution payable

     2,258        (841

Deferred compensation

     1,066        166   
                

Net cash provided by operating activities

     67,016        33,502   

Cash flows from investing activities

    

Purchase of property and equipment and oil and natural gas properties

     (88,518     (44,858

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

     211        284   

Settlement of non-hedge derivative instruments

     (5,294     7,736   

Other

     —          16   
                

Net cash used in investing activities

     (93,601     (36,822

Cash flows from financing activities

    

Proceeds from long-term debt

     1,059        270   

Proceeds from senior notes

     400,000        —     

Repayment of long-term debt

     (1,227     (1,246

Repayment of senior notes

     (325,000     —     

Principal payments under capital lease obligations

     (48     (64

Payment of debt issuance and retirement costs and other financing fees

     (23,682     (835
                

Net cash provided by (used in) financing activities

     51,102        (1,875
                

Net increase (decrease) in cash and cash equivalents

     24,517        (5,195

Cash and cash equivalents at beginning of period

     55,111        73,417   
                

Cash and cash equivalents at end of period

   $ 79,628      $ 68,222   
                

Supplemental cash flow information

    

Cash paid (received) during the period for:

    

Interest, net of capitalized interest

   $ 21,564      $ 21,421   

Income taxes

     —          (5

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

 

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Table of Contents

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—continued

 

Supplemental disclosure of investing and financing activities (dollars in thousands)

During the three months ended March 31, 2011 and 2010, oil and natural gas property additions of $271 and $1,340, respectively, which were previously included in accounts payable and accrued expenses were settled and are reflected in cash used in investing activities.

During the three months ended March 31, 2011 and 2010, we recorded an asset and related liability of $159 and $4, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and natural gas properties.

Interest of $615 and $388 was capitalized during the three months ended March 31, 2011 and 2010, respectively, primarily related to unproved oil and natural gas leaseholds.

 

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Table of Contents

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 natural gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, Montana, Kansas, and Wyoming.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X and do not include all of the financial information and disclosures required by GAAP. The financial information as of March 31, 2011 and for the three months ended March 31, 2011 and 2010 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three months ended March 31, 2011 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2011.

The consolidated interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations contained in our Form 10-K filed with the Securities and Exchange Commission on March 29, 2011.

Principles of consolidation

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

Use of estimates

The preparation of financial statements in conformity with 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 natural gas reserves, valuation allowances associated with deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

Reclassifications

Certain reclassifications have been made to prior year amounts to conform to current year presentation.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of March 31, 2011, cash with a recorded balance totaling $73,690 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

 

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Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. Interest accrues beginning on the day after the due date of the receivable. We determine our allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. When the account is determined to be uncollectible, all interest previously accrued but not collected is reversed against the allowance for doubtful accounts. Accounts receivable consisted of the following at March 31, 2011 and December 31, 2010:

 

     March 31,
2011
    December 31,
2010
 

Joint interests

   $ 21,717      $ 17,835   

Accrued oil and natural gas sales

     49,256        41,316   

Derivative settlements

     347        3,431   

Other

     813        831   

Allowance for doubtful accounts

     (708     (633
                
   $ 71,425      $ 62,780   
                

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas production inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. Inventories at March 31, 2011 and December 31, 2010 consisted of the following:

 

     March 31,
2011
    December 31,
2010
 

Equipment inventory

   $ 5,762      $ 6,399   

Oil and natural gas product

     3,249        3,624   

Inventory for resale

     2,926        2,866   

Inventory valuation allowance

     (1,993     (1,821
                
   $ 9,944      $ 11,068   
                

 

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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. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized. During the first quarter of 2011, we recorded a valuation allowance of $1,449 for state NOL carryforwards we do not expect to realize before they expire.

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

If applicable, we would report a liability for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of March 31, 2011 and December 31, 2010, we have not recorded a liability or accrued interest related to uncertain tax positions.

The tax years 1999 through 2010 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. Sales of products or services are recognized at the time of delivery of materials or performance of service.

Derivative transactions

We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation.

Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the statement of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the statement of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.

If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, is immediately recognized in gain (loss) from oil and natural gas hedging activities in the statement of operations. Cash flows associated with hedges are reported as operating activities in the statement of cash flows unless the hedges contain a significant financing element, in which case they are reported as financing activities.

If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in AOCI and is reclassified into income as the hedged transactions occur. Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively.

We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See Note 2 for additional information regarding our derivative transactions.

 

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Fair value measurements

Fair value is defined by the Financial Accounting Standards Board (“FASB”) as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Assets and liabilities recorded at fair value in the balance sheet are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and assets acquired through a non-monetary exchange transaction.

Asset retirement obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first quarter of 2011 were escalated using an annual inflation rate of 2.95% and discounted using our credit-adjusted risk-free interest rate of 8.0%. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 3 for additional information regarding our asset retirement obligations.

 

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Stock-based compensation

Our stock-based compensation programs consist of phantom stock and restricted stock awards issued to employees. The estimated fair value of the phantom stock awards is remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value, in accordance with the terms of the Phantom Stock Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards is recognized on a straight-line basis over the five-year vesting period.

We measure the fair value of our restricted stock awards that include a service condition based upon the fair market value of our common stock on the date of grant, and recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. These assumptions reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.

See Note 6 for additional information relating to stock-based compensation.

Recently issued accounting standards

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

 

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Note 2: Derivative activities and financial instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. See Note 1 for additional information regarding our accounting policies for fair value measurements.

For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a put option contract sold by us with a price below the floor price of the collar. This additional put option requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a standard collar contract only. Therefore, if market prices are below the additional put option, we would be entitled to receive the market price plus the difference between the additional put option and the floor. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put option.

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

 

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Our outstanding derivative instruments as of March 31, 2011 are summarized below:

 

     Oil derivatives  
     Swaps      Collars      Three-way collars  
            Weighted
average
           

Weighted

average range

            Weighted average fixed price per Bbl  
     Volume
MBbls
     fixed price
per Bbl
     Volume
MBbls
     (fixed price
per Bbl)
     Volume
MBbls
     Additional
put option
     Floor      Ceiling  

2011

     2,329       $ 76.07         63       $ 110.00 - $153.00         —         $ —         $ —         $ —     

2012

     1,963         93.93         —           —           720         65.00         87.50         108.80   

2013

     420         102.00         —           —           600         71.00         94.00         128.20   
                                         
     4,712            63            1,320            
                                         

 

     Natural gas swaps      Natural gas basis
protection swaps
 
     Volume
BBtu
     Weighted average
fixed  price per Btu
     Volume
BBtu
     Weighted average
fixed price per Btu
 

2011

     13,860       $ 6.22         11,190       $ 0.64   

2012

     9,600         5.04         8,400         0.30   

2013

     6,000         5.21         —           —     
                       
     29,460            19,590      
                       

Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility, and we believe the credit risks associated with all of these institutions are acceptable. As of March 31, 2011 we have no balance outstanding on our credit facility. We did not post collateral under any of these contracts as they are secured under our revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our revolving credit facility. The aggregate fair value of our derivative liabilities was $108,800 at March 31, 2011.

 

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Discontinuance of cash flow hedge accounting

Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 are recognized immediately in non-hedge derivative gains (losses) in the consolidated statement of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Prior to March 31, 2010, a portion of the change in fair value was deferred through AOCI. As of March 31, 2011, AOCI consists of deferred net gains of $63,184 ($39,161 net of tax) that will be recognized as gains (losses) from oil and natural gas hedging activities through December 2013 as the hedged production is sold. We expect to reclassify $5,128 of net losses in accumulated other comprehensive income to income during the next 12 months.

Derivative activities

Gains and losses associated with cash flow hedges are summarized below.

 

     Three months ended
March 31,
 
     2011     2010  

Amount of loss recognized in AOCI (effective portion)

    

Oil swaps

   $ —        $ (1,035

Income taxes

     —          400   
                
   $ —        $ (635
                

Amount of gain (loss) reclassified from AOCI in income (effective portion)(1)

    

Oil swaps

   $ (6,755   $ (4,844

Gas swaps

     —          519   

Income taxes

     2,568        1,673   
                
   $ (4,187   $ (2,652
                

Loss on oil swaps recognized in income (ineffective portion)(1)

   $ —        $ (660
                

 

(1) Included in loss from oil and natural gas hedging activities in the consolidated statements of operations.

 

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Loss from oil and natural gas hedging activities, which is a component of total revenues in the consolidated statements of operations, is comprised of the following:

 

     March 31,
2011
    March 31,
2010
 

Oil hedges

    

Reclassification adjustment for hedge losses included in net income (loss)

   $ (6,755   $ (4,844

Loss on ineffective portion of derivatives qualifying for hedge accounting

     —          (660

Natural gas hedges

    

Reclassification adjustment for hedge gains included in net income (loss)

     —          519   
                
   $ (6,755   $ (4,985
                

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

 

     March 31,
2011
    March 31,
2010
 

Change in fair value of commodity price swaps

   $ (50,168   $ 23,765   

Change in fair value of costless collars

     (6,605     (2,196

Change in fair value of natural gas basis differential contracts

     1,141        1,752   

Receipts from (payments on) settlement of commodity price swaps

     (3,282     6,434   

Receipts from settlement of costless collars

     334        5,741   

Payments on settlement of natural gas basis differential contracts

     (2,346     (4,439
                
   $ (60,926   $ 31,057   
                

Derivative settlements receivable of $347 and $3,431 were included in accounts receivable at March 31, 2011 and December 31, 2010, respectively. Derivative settlements payable of $8,554 and $785 were included in accounts payable and accrued liabilities at March 31, 2011 and December 31, 2010, respectively.

 

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Fair value of derivative instruments

All derivative financial instruments are recorded on the balance sheet at fair value. We estimate the fair value of our derivative instruments using a combined income and market valuation methodology. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate. The fair value of collars is determined using an option pricing model which takes into account market volatility as well as the inputs described above. All derivative instruments are discounted further using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ nonperformance risk for derivative assets. As of March 31, 2011 and December 31, 2010, the rate reflecting our nonperformance risk was 2.50% and 2.50%, respectively. As of March 31, 2011, we had net liabilities with our counterparties. The weighted-average rate reflecting our counterparties’ nonperformance risk was approximately 2.14% as of December 31, 2010.

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

 

     As of March 31, 2011     As of December 31, 2010  
     Assets      Liabilities     Net value     Assets      Liabilities     Net value  

Derivatives not designated as hedging instruments:

              

Natural gas swaps

   $ 22,732       $ (1,404   $ 21,328      $ 32,538       $ (130   $ 32,408   

Oil swaps

     36         (97,324     (97,288     21         (58,221     (58,200

Oil collars

     489         (5,585     (5,096     1,509         —          1,509   

Natural gas basis differential swaps

     5         (4,487     (4,482     220         (5,843     (5,623
                                                  

Total derivative instruments

     23,262         (108,800     (85,538     34,288         (64,194     (29,906

Less:

              

Netting adjustments (1)

     23,231         (23,231     —          32,859         (32,859     —     

Current portion asset (liability)

     —           (62,898     (62,898     1,429         (28,853     (27,424
                                                  
   $ 31       $ (22,671   $ (22,640   $ —         $ (2,482   $ (2,482
                                                  

 

(1) Amounts represent the impact of legally enforceable master netting agreements that allow us to net settle positive and negative positions with the same counterparties.

We had no Level 1 assets or liabilities as of March 31, 2011 or December 31, 2010. Our derivative contracts classified as Level 2 are valued using NYMEX forward commodity price curves and quotations provided by price index developers such as Platts. In certain less liquid markets, forward prices are not as readily available. In these circumstances, commodity swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. Due to unavailability of observable volatility data input, the fair value measurement of all our collars has been categorized as Level 3.

 

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The fair value hierarchy for our financial assets and liabilities is shown by the following table:

 

     As of March 31, 2011     As of December 31, 2010  
     Derivative
assets
    Derivative
liabilities
    Net assets
(liabilities)
    Derivative
assets
    Derivative
liabilities
    Net assets
(liabilities)
 

Significant other observable inputs (Level 2)

   $ 22,773      $ (103,215   $ (80,442   $ 32,779      $ (64,194   $ (31,415

Significant unobservable inputs (Level 3)

     489        (5,585     (5,096     1,509        —          1,509   

Netting adjustments (1)

     (23,231     23,231        —          (32,859     32,859        —     
                                                
   $ 31      $ (85,569   $ (85,538   $ 1,429      $ (31,335   $ (29,906
                                                

 

(1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.

Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy for the first quarter of 2011 and 2010 were as follows:

 

Net derivative assets (liabilities)

   March 31,
2011
    March 31,
2010
 

Beginning balance

   $ 1,509      $ 26,355   

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

     (6,271     3,544   

Settlements

     (334     (5,741
                

Ending balance

   $ (5,096   $ 24,158   
                

Gains (losses) relating to assets still held at the reporting date included in non-hedge derivative gains (losses) for the period

   $ (6,233   $ 3,211   
                

Fair value of other 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 at March 31, 2011 and December 31, 2010 approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms. The carrying value and estimated market value of our senior notes at March 31, 2011 and December 31, 2010 were as follows:

 

     March 31, 2011      December 31, 2010  
     Carrying
value
     Estimated
fair value
     Carrying
value
     Estimated
fair value
 

8.5% Senior Notes due 2015

   $ —         $ —         $ 325,000       $ 332,313   

8.875% Senior Notes due 2017

     323,158         342,063         323,099         329,875   

9.875% Senior Notes due 2020

     293,235         334,680         293,135         315,000   

8.25% Senior Notes due 2021

     400,000         412,500         —           —     
                                   
   $ 1,016,393       $ 1,089,243       $ 941,234       $ 977,188   
                                   

Fair value amounts have been estimated based on quoted market prices. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

 

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Note 3: Asset retirement obligations

The activity incurred in the asset retirement obligation for the three months ended March 31, 2011 is:

 

     Three Months
Ended
March 31,
2011
 

Beginning balance

   $ 41,695   

Liabilities incurred in current period

     159   

Liabilities settled in current period

     (550

Accretion expense

     874   
        
   $ 42,178   

Less current portion

     690   
        
   $ 41,488   
        

See Note 1 for additional information regarding our accounting policies for asset retirement obligations and fair value measurements.

Note 4: Long-Term Debt

Long-term debt

Long-term debt at March 31, 2011 and December 31, 2010 consisted of the following:

 

     March 31,
2011
     December 31,
2010
 

Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.71% to 9.26%, due January 2017 through December 2028; collateralized by real property

   $ 12,912       $ 13,024   

Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.00% to 9.25%, due April 2011 through April 2016; collateralized by automobiles, machinery and equipment

     7,643         7,699   
                 
     20,555         20,723   

Less current maturities

     3,893         4,047   
                 
   $ 16,662       $ 16,676   
                 

In April 2010, we entered into an Eighth Restated Credit Agreement (“our senior secured revolving credit facility”), which is collateralized by our oil and gas properties. Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. Borrowings under our senior secured revolving credit facility are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

 

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The Fourth Amendment to our senior secured revolving credit facility, effective April 1, 2011, extended the maturity of our senior secured revolving credit facility from April 12, 2014 to April 1, 2016 and reaffirmed the borrowing base at $375,000. It also amended the definition of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

Our senior secured revolving credit facility has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than:

 

   

4.50 to 1.0 for each period of four consecutive fiscal quarters ending on or prior to December 31, 2011; and

 

   

4.25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2012 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 our senior secured revolving credit facility as of March 31, 2011.

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

 

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Senior Notes

On February 22, 2011, we issued $400,000 aggregate principal amount of 8.25% senior notes maturing on September 1, 2021. We used the net proceeds from the 8.25% senior notes to consummate a tender offer for all of our 8.5% senior notes due 2015, to redeem the 8.5% senior notes not purchased in the tender offer, and for general corporate purposes. Interest is payable on the 8.25% senior notes semi-annually on March 1 and September 1 each year beginning September 1, 2011. On or after September 1, 2016, we may, at our option, redeem the notes at the following redemption prices plus accrued and unpaid interest: 104.125% after September 1, 2016, 102.750% after September 1, 2017, 101.375% after September 1, 2018, and 100% after September 1, 2019. Prior to March 1, 2014, we may redeem up to 35% of the notes with the net proceeds of one or more equity offerings at a redemption price of 108.250%, plus accrued and unpaid interest.

As part of the indenture for our 8.25% senior notes, we entered into a registration rights agreement in which we agreed to file a registration statement with the Securities and Exchange Commission related to an offer to exchange the notes for an issue of registered notes within 270 days of the closing date. If we fail to complete the exchange offer within 270 days after the closing date, we would be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate increases an additional 0.25% for each additional 90 days, up to a total of 1.0%.

In connection with the issuance of the 8.25% senior notes, we capitalized $8,720 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. We had unamortized issuance costs of $8,667 as of March 31, 2011 that are included in other assets. Amortization of $53 was charged to interest expense during the three months ended March 31, 2011 related to the issuance costs.

During the first quarter of 2011, we recorded a $20,576 loss associated with the refinancing of our 8.5% Senior Notes due 2015, including $15,085 in repurchase or redemption-related fees and a $5,491 write off of deferred financing costs.

Senior Notes at March 31, 2011 and December 31, 2010 consisted of the following:

 

     March 31, 2011     December 31, 2010  

8.5% Senior Notes due 2015

   $ —        $ 325,000   

8.875% Senior Notes due 2017

     325,000        325,000   

9.875% Senior Notes due 2020

     300,000        300,000   

8.25% Senior Notes due 2021

     400,000        —     

Discount on Senior Notes due 2017

     (1,842     (1,901

Discount on Senior Notes due 2020

     (6,765     (6,865
                
   $ 1,016,393      $ 941,234   
                

The indentures governing our Senior Notes contain certain covenants which limit our ability to:

 

   

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

 

   

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

 

   

make investments;

 

   

create liens on assets;

 

   

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

 

   

transfer or sell assets;

 

   

engage in transactions with affiliates;

 

   

consolidate, merge or transfer all or substantially all assets and the assets of subsidiaries; and

 

   

enter into other lines of business.

 

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

Note 5: Related party transactions

CHK Holdings L.L.C., an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), owns approximately 20% of our outstanding common stock. We participate in ownership of properties operated by Chesapeake, and we received revenues and incurred joint interest billings on these properties as follows:

 

     Three months ended March 31,  
     2011     2010  

Revenues

   $ 1,277      $ 1,351   

Joint interest billings

     (258     (2,590

In addition, Chesapeake participates in ownership of properties operated by us, and we paid revenues and recorded joint interest billings to Chesapeake on these properties as follows:

 

     Three months ended March 31,  
     2011     2010  

Revenues

   $ (461   $ (404

Joint interest billings

     1,766        184   

Amounts receivable from and payable to Chesapeake were $1,160 and $261, respectively, as of March 31, 2011. Amounts receivable from and payable to Chesapeake were $718 and $120, respectively, as of December 31, 2010.

 

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Note 6: Equity

Common stock

The following is a summary of the changes in our common shares outstanding during the first quarter of 2011:

 

     Common Stock  
     Class A      Class B      Class C      Class D      Class E      Class F      Class G      Total  

Shares issued at January 1, 2011

     51,346         357,882         209,882         279,999         504,276         1         3         1,403,389   

Restricted stock issuances

     6,846         —           —           —           —           —           —           6,846   
                                                                       

Shares issued at March 31, 2011

     58,192         357,882         209,882         279,999         504,276         1         3         1,410,235   
                                                                       

Stock based compensation

Phantom Stock Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Plan”), to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to participants in total up to 2% of the fair market value of the Company. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the current plan, awards vest on the fifth anniversary of the award date, but may also vest on a pro-rata basis following a participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Upon vesting, participants are entitled to redeem their phantom stock for cash within 120 days of the vesting date. A summary of our phantom stock activity during the first quarter of 2011 is presented in the following table:

 

     Weighted
average
grant date
fair value
     Phantom
shares
    Vest
date
fair
value
     Weighted
average
amortization
period
remaining
 
     ($ per share)                   (years)  

Unvested and outstanding at January 1, 2011

   $ 16.04         126,859           2.09   

Granted

   $ 17.85         29,297        

Vested

   $ 17.89         (15,455   $ 276      

Forfeited

   $ 18.03         (8,440     
                

Unvested and outstanding at March 31, 2011

   $ 16.10         132,261           1.88   
                

No payments for phantom shares were made during the first quarter of 2011 or 2010. As of March 31, 2011, there were 15,455 vested units outstanding with a weighted average fair value of $17.85 per share, and an aggregate intrinsic value of $276, which is included in accrued payroll and benefits payable. Based on an estimated fair value of $22.67 per phantom share as of March 31, 2011, the aggregate intrinsic value of the unvested phantom shares outstanding was $2,998, which includes approximately $1,505 of unrecognized compensation cost that is expected to be recognized over a weighted-average period of 1.88 years. As of March 31, 2011 and December 31, 2010, accrued payroll and benefits payable included $698 and $321, respectively, for deferred compensation costs vesting within the next twelve months.

 

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2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Long-Term Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our affiliates’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.

Our Board of Directors has approved awards of restricted stock under the 2010 Plan totaling 58,192 shares of our class A common stock. These awards consisted of a total of 11,322 shares that are subject to service vesting conditions (also defined as “Time Vesting” awards in the restricted stock agreements) and a total of 46,870 shares that are subject to market and performance vesting conditions (also defined as “Performance Vesting” awards in the restricted stock agreements). A summary of our restricted stock activity during the first quarter of 2011 is presented in the following table:

 

     Weighted
average
grant date
fair value
     Restricted
shares
 
     ($ per share)         

Unvested and outstanding at January 1, 2011

   $ 371.24         51,346   

Granted

   $ 381.32         6,846   

Vested

   $ —           —     

Forfeited

   $ —           —     
           

Unvested and total outstanding at March 31, 2011

   $ 372.43         58,192   
           

Unrecognized compensation cost of $16,774 associated with our non-vested restricted stock awards is expected to be recognized over a weighted-average period of 4.20 years.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. A portion of stock-based compensation cost associated with our employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period. We recognized stock-based compensation expense as follows for the periods indicated:

 

     Three months ending  
     March 31,
2011
    March 31,
2010
 

Stock-based compensation cost

   $ 1,675      $ 253   

Less: stock-based compensation cost capitalized

     (609     (87
                

Stock-based compensation expense

   $ 1,066      $ 166   
                

 

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Comprehensive income (loss)

Components of comprehensive income (loss), net of related tax, are as follows for the three months ended March 31, 2011 and 2010:

 

     Three months ended
March 31,
 
     2011     2010  

Net income (loss)

   $ (40,264   $ 25,464   

Unrealized loss on hedges

     —          (635

Reclassification adjustment for hedge (gains) losses included in net income (loss)

     4,187        2,652   
                

Comprehensive income (loss)

   $ (36,077   $ 27,481   
                

Note 7: Commitments and contingencies

Standby letters of credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had various Letters outstanding totaling $920 as of March 31, 2011 and as of December 31, 2010, respectively. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. We paid no interest on the Letters during the three months ended March 31, 2011 and 2010.

Various claims and lawsuits, incidental to the ordinary course of business, are pending both for and against us. In the opinion of management, all matters are not expected to have a material effect on our consolidated financial position or results of operations.

 

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ITEM 2. 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. In 2010, we reorganized our oil and natural gas assets into enhanced oil recovery (“EOR”) project areas and conventional (non-EOR) productive basins. Our primary areas of operation using conventional recovery methods are the Anadarko Basin Area, Central Oklahoma Area, and the Permian Basin Area. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and EOR projects.

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

Generally our producing properties have declining production rates. Our reserve estimates as of December 31, 2010 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 16%, 12% and 10% for the next three years. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

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

 

   

cash flow available for capital expenditures;

 

   

ability to borrow and raise additional capital;

 

   

ability to service debt;

 

   

quantity of oil and natural gas we can produce;

 

   

quantity of oil and natural gas reserves; and

 

   

operating results for oil and natural gas activities.

 

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During the first quarter of 2011, quarterly production was 2,062 MBoe, a 10% increase from production levels in the first quarter of 2010, primarily due to our recent drilling activity. A 15% increase in our average sales price before hedging, combined with the increase in production, resulted in an 27% increase in revenue from oil and natural gas sales in the first quarter of 2011 compared to the same period in 2010. However, due primarily to changes in the NYMEX forward commodity price curves, we had a $60.9 million loss on non-hedge derivatives in the first quarter of 2011 compared to a gain of $31.1 million in the first quarter of 2010. We also expensed $20.6 million of costs associated with the refinancing of our 8.5% Senior Notes due 2015 in the first quarter of 2011. Primarily as a result of these factors, we had a net loss of $40.3 million during the first quarter of 2011 compared to net income of $25.5 million during the first quarter of 2010.

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

 

   

8.25% Senior Notes due 2021. On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes due 2015, we capitalized approximately $8.7 million of issuance costs related to underwriting and other fees and we expensed approximately $20.6 million of refinancing costs, including a $5.5 million non-cash write off of deferred financing costs.

 

   

Capital expenditure budget. We have budgeted $250.0 million for capital expenditures for oil and natural gas properties in 2011. Our 2011 capital budget allocates $157.0 million to conventional oil and natural gas exploration and production activities. The remaining $93.0 million, or 37%, of the capital budget is allocated to the development of our EOR assets, and represents a substantial increase in capital being directed toward development of our EOR assets. The increased focus on EOR reduces near term growth opportunities but enhances longer term growth and is consistent with our strategy of driving near term growth with developmental drilling and long term growth through EOR development.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and private equity sales. As of March 31, 2011, we had cash and cash equivalents of $79.6 million and availability of $374.1 million under our senior secured revolving credit facility with a borrowing base of $375.0 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 pledge our producing oil and natural gas properties to secure our senior secured revolving credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We have the capacity to utilize the available funds to supplement our operating cash flows as a financing source for our capital expenditures. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and natural gas prices through the use of commodity derivatives.

 

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Sources and uses of cash

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

 

     Three months ended
March 31,
 

(dollars in thousands)

   2011     2010  

Cash flows provided by operating activities

   $ 67,016      $ 33,502   

Cash flows used in investing activities

     (93,601     (36,822

Cash flows provided by (used in) financing activities

     51,102        (1,875
                

Net increase (decrease) in cash during the period

   $ 24,517      $ (5,195
                

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas, reduced or increased by associated hedging activities. Cash flows from operating activities increased 100% from 2010 to 2011, primarily due to a 15% increase in the average price received and a 10% increase in production.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the quarters ended March 31, 2011 and 2010, cash flows provided by operating activities were approximately 76% and 75%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties.

Our capital expenditures for oil and natural gas properties are detailed below:

 

     Three months ended March 31, 2011               

(dollars in thousands)

   Acquisitions      Drilling      Enhancements      Total      Percent
of total
    Budgeted
2011 capital
expenditures
     Percent
of total
 

Enhanced Oil Recovery Project Areas (1)

   $ 563       $ 6,812       $ 10,757       $ 18,132         21   $ 93,000         37

Anadarko Basin Area

     2,132         30,491         1,227         33,850         39     71,000         29

Central Oklahoma Area

     663         7,079         2,161         9,903         11     35,000         14

Permian Basin Area

     429         7,842         1,391         9,662         11     21,000         8

Other

     145         12,079         3,084         15,308         18     30,000         12
                                                             

Total

   $ 3,932       $ 64,303       $ 18,620       $ 86,855         100   $ 250,000         100
                                                             

 

(1)

Drilling includes $0.3 million of additions relating to conventional assets located in our EOR Project Areas and $1.0 million for CO2 support facilities and pipelines. Enhancements includes $1.6 million of additions relating to conventional assets located in our EOR Project Areas and $1.1 million for CO2 support facilities and pipelines.

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $4.2 million for property and equipment during the first quarter of 2011.

Net cash provided by (used in) financing activities was $51.1 million during the first quarter of 2011 compared to ($1.9) million during the first quarter of 2010. On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes due 2015, we paid approximately $8.6 million of issuance costs related to underwriting and other fees and approximately $15.1 million of repurchase and redemption-related costs.

 

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Credit Agreements

In April 2010, we entered into our senior secured revolving credit facility, which is collateralized by our oil and natural gas properties, and, following a recent amendment, matures on April 1, 2016. Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. Effective April 1, 2011, the borrowing base was reaffirmed at $375.0 million.

Borrowings under our senior secured revolving credit facility are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

Interest on Eurodollar loans is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin where the margin varies from 1.75% to 2.75% depending on the utilization percentage of the conforming borrowing base. From April 1, 2011 until October 1, 2011, the margin will be fixed at 2.25%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on ABR loans is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%; plus a margin where the margin varies from 0.75% to 1.75%, depending on the utilization percentage of the borrowing base.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount 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 senior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:

 

   

incur additional indebtedness;

 

   

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

 

   

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

 

   

make investments in or loans to others;

 

   

change our line of business;

 

   

enter into operating leases;

 

   

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

 

   

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

 

   

enter into transactions with affiliates;

 

   

issue preferred stock;

 

   

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

 

   

enter into or terminate certain swap agreements;

 

   

amend our organizational documents; and

 

   

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

 

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Our senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At March 31, 2011 and December 31, 2010, our current ratio as computed using GAAP was 0.86 and 0.87, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 3.68 and 3.78, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:

 

(dollars in thousands)

   March 31,
2011
    December 31,
2010
 

Current assets per GAAP

   $ 180,101      $ 142,348   

Plus—Availability under senior secured revolving credit facility

     374,080        374,080   

Less—Short-term derivative instruments

     —          (1,429

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

     (17,584     (9,655
                

Current assets as adjusted

   $ 536,597      $ 505,344   
                

Current liabilities per GAAP

   $ 209,587      $ 163,347   

Less—Short term derivative instruments

     (62,898     (28,853

Less—Short-term asset retirement obligation

     (690     (690
                

Current liabilities as adjusted

   $ 145,999      $ 133,804   
                

Current ratio for loan compliance

     3.68        3.78   
                

In April 2011, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

Our senior secured revolving credit facility, as amended, requires us to maintain a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than:

 

   

4.50 to 1.0 for each period of four consecutive fiscal quarters ending on or prior to December 31, 2011; and

 

   

4. 25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2012 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.

 

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Our senior secured revolving credit facility also specifies events of default, including:

 

   

our failure to pay principal or interest under our senior secured revolving credit facility 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 our senior secured revolving credit facility;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

a Change of Control (as defined in our senior secured revolving credit facility); and

 

   

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

If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.

8.25% Senior Notes due 2021

On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes due 2015, we capitalized approximately $8.7 million of issuance costs related to underwriting and other fees and we expensed approximately $20.6 million of refinancing costs, including a $5.5 million non-cash write off of deferred financing costs.

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

On or after the date that is five years before the maturity date, we may redeem some or all of the Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption.

Prior to the date that is five years before the maturity date, the Senior Notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indenture.

 

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

 

   

incur or guarantee additional debt, or issue preferred stock;

 

   

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

 

   

consolidate, merge or transfer assets; and

 

   

enter into other lines of business.

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

Alternative capital resources

We have historically used cash flow from operations, debt financing, and private issuances 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.

 

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Results of operations

Revenues and production

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

 

     Three months ended
March 31,
     Percentage
change
 
     2011      2010     

Oil and natural gas sales (dollars in thousands)

        

Oil

   $ 105,753       $ 71,440         48.0

Natural gas

     21,846         28,935         (24.5 )% 
                    

Total

   $ 127,599       $ 100,375         27.1

Production

        

Oil (MBbls)

     1,204         974         23.6

Natural gas (MMcf)

     5,148         5,364         (4.0 )% 

MBoe

     2,062         1,868         10.4

Average sales prices (excluding derivative settlements)

        

Oil per Bbl

   $ 87.83       $ 73.35         19.7

Natural gas per Mcf

   $ 4.24       $ 5.39         (21.3 )% 

Boe

   $ 61.88       $ 53.73         15.2

Oil and natural gas revenues increased $27.2 million, or 27%, during the first quarter of 2011 compared to the first quarter of 2010 due to a 15% increase in the average price per Boe combined with a 10% increase in sales volumes. Oil production for the first quarter of 2011 increased compared to the first quarter of 2010 primarily due to our recent drilling activity. Gas production for the first quarter decreased primarily due to the decline in production from the Bowdle 47 No. 2, which accounted for approximately 3% and 7% of total production during the first quarter of 2011 and 2010, respectively. We drilled and completed an offset, the Bowdle 47 No. 4, which came online in late April of 2010 and accounted for approximately 1% of our total production during the first quarter of 2011.

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

 

     Three months ended March 31,
2011 vs. 2010
 

(dollars in thousands)

   Sales
change
    Percentage
change
in sales
 

Change in oil sales due to:

    

Prices

   $ 17,443        24.4

Production

     16,870        23.6
                

Total increase in oil sales

   $ 34,313        48.0
                

Change in natural gas sales due to:

    

Prices

   $ (5,924     (20.5 )% 

Production

     (1,165     (4.0 )% 
                

Total decrease in natural gas sales

   $ (7,089     (24.5 )% 
                

 

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Production volumes by area were as follows (MBoe):

 

     Three months ended
March  31,
     Percentage
change
 
     2011      2010     

Enhanced Oil Recovery Project Areas

     275         260         5.8

Anadarko Basin Area

     694         580         19.7

Central Oklahoma Area

     457         469         (2.6 )% 

Permian Basin Area

     343         339         1.2

Other

     293         220         33.2
                    

Total

     2,062         1,868         10.4
                    

The increase in production in the Anadarko Basin Area is primarily due to our drilling activity in the Area. Five of our Anadarko Basin Area wells, which came online during the fourth quarter of 2010 and the first quarter of 2011, accounted for approximately 7% of our total production during the first quarter of 2011.

 

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Derivative activities

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

Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Our derivative activities are dynamic to allow us to respond to the volatile commodity markets.

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

 

     Three months ended March 31,  
     2011     2010  

Oil (per Bbl):

    

Before derivative settlements

   $ 87.83      $ 73.35   

After derivative settlements

   $ 75.72      $ 68.27   

Post-settlement to pre-settlement price

     86.2     93.1

Natural gas (per Mcf):

    

Before derivative settlements

   $ 4.24      $ 5.39   

After derivative settlements

   $ 6.05      $ 6.73   

Post-settlement to pre-settlement price

     142.7     124.9

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

 

(dollars in thousands)

   March 31,
2011
    December 31,
2010
 

Derivative assets (liabilities):

    

Natural gas swaps

   $ 21,328      $ 32,408   

Oil swaps

     (97,288     (58,200

Oil collars

     (5,096     1,509   

Natural gas basis differential swaps

     (4,482     (5,623
                

Net derivative liability

   $ (85,538   $ (29,906
                

 

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Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 are recognized immediately in non-hedge derivative gains (losses) in the consolidated statement of operations. As of March 31, 2011, accumulated other comprehensive income (loss) (“AOCI”) consists of deferred net gains of $63.2 million ($39.2 million net of tax) related to discontinued cash flow hedges that will be recognized as gains (losses) from oil and natural gas hedging activities through December 2013 as the hedged production is sold.

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

 

     Three months ended March 31,  
     2011     2010  

(dollars in thousands)

   Non-cash
fair value
adjustment
    Cash
receipts
(payments)
    Non-cash
fair value
adjustment
    Cash
receipts
(payments)
 

Gain (loss) from oil and natural gas hedging activities:

        

Oil swaps

   $ (6,755   $ —        $ —        $ (5,504

Natural gas swaps

     —          —          519        —     
                                

Gain (loss) from oil and natural gas hedging activities

   $ (6,755   $ —        $ 519      $ (5,504
                                

Non-hedge derivative gains (losses):

        

Oil swaps and collars

   $ (45,693   $ (14,586   $ (1,737   $ 559   

Natural gas swaps and collars

     (11,080     11,638        23,306        11,616   

Natural gas basis differential contracts

     1,141        (2,346     1,752        (4,439
                                

Non-hedge derivative gains (losses)

   $ (55,632   $ (5,294   $ 23,321      $ 7,736   
                                

Total gains (losses) from derivative activities

   $ (62,387   $ (5,294   $ 23,840      $ 2,232   
                                

Due to an increase in average NYMEX forward strip oil prices as of March 31, 2011 and 2010 compared to December 31, 2010 and 2009, respectively, combined with high oil prices prevalent during the periods, we recorded a loss on oil derivatives of $67.0 million and $6.7 million during the first quarters of 2011 and 2010, respectively. This includes losses of $6.8 million and $0 reclassified into earnings during the first quarters of 2011 and 2010, respectively, that were associated with derivatives for which hedge accounting was previously discontinued.

During the first quarter of 2011, we recorded a non-hedge gain on gas derivatives of $0.6 million, due primarily to low natural gas prices prevalent during the period, partially offset by lower average contractual prices and higher average NYMEX forward strip gas prices as of March 31, 2011 compared to December 31, 2010. Due primarily to lower average NYMEX forward strip gas prices as of March 31, 2010 compared to December 31, 2009, combined with low natural gas prices prevalent during the period, we recognized non-hedge gains on gas derivatives of $34.9 million during the first quarter of 2010. In addition, we reclassified into earnings gains of $0.5 million which were associated with derivatives for which hedge accounting was previously discontinued.

During the first quarter of 2011 and 2010, losses on natural gas basis differential contracts were $1.2 million and $2.7 million, respectively, primarily due to low basis differentials prevalent during the period, partially offset by lower average contractual prices as of March 31, 2011 and 2010 compared to December 31, 2010 and 2009, respectively.

Primarily as a result of the above transactions, we recognized total losses on derivative activities of $67.7 million for the three months ended March 31, 2011 compared to total gains on derivative activities of $26.1 million for the three months ended March 31, 2010.

 

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Lease operating expenses

 

     Three months ended
March 31,
     Percentage
change
 
     2011      2010     

Lease operating expenses (in thousands)

   $ 27,556       $ 24,419         12.8
                          

Lease operating expenses per Boe

   $ 13.36       $ 13.07         2.2
                          

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices.

Our lease operating expenses increased by $3.1 million, or $0.29 per Boe, during the first quarter of 2011 compared to the first quarter of 2010, primarily due to our increased activity combined with the upward pressure on operating and service costs associated with the recent increase in oil prices.

Production taxes (which include ad valorem taxes)

 

     Three months ended
March 31,
     Percentage
change
 
     2011      2010     

Production taxes (in thousands)

   $ 8,624       $ 6,990         23.4
                          

Production taxes per Boe

   $ 4.18       $ 3.74         11.8
                          

Production taxes generally change in proportion to oil and natural gas sales. The 23% increase in production taxes during the first quarter of 2011 compared to the first quarter of 2010 was primarily due to the 15% increase in average realized prices combined with a 10% increase in production volumes.

 

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

 

     Three months ended
March 31,
     Percentage
change
 
     2011      2010     

DD&A (in thousands):

        

Oil and natural gas properties

   $ 30,535       $ 21,493         42.1

Property and equipment

     2,568         2,240         14.6

Accretion of asset retirement obligation

     874         788         10.9
                    

Total DD&A

   $ 33,977       $ 24,521         38.6
                    

DD&A per Boe:

        

Oil and natural gas properties

   $ 14.81       $ 11.51         28.7

Other fixed assets

     1.67         1.62         3.1
                    

Total DD&A per Boe

   $ 16.48       $ 13.13         25.5
                    

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $9.0 million in the first quarter of 2011 compared to the first quarter of 2010, of which $6.8 million was due to a higher rate per equivalent unit of production and $2.2 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $3.30 to $14.81 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.

 

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General and administrative expenses (“G&A”)

 

     Three months ended
March 31,
    Percent
change
 

(dollars in thousands, excluding per Boe amounts)

   2011     2010    

Gross G&A expenses

   $ 12,422      $ 9,636        28.9

Capitalized exploration and development costs

     (4,414     (3,196     38.1
                  

Net G&A expenses

   $ 8,008      $ 6,440        24.3
                  

Average G&A cost per Boe

   $ 3.88      $ 3.45        12.5
                  

G&A expenses for the first quarter of 2011 increased by $1.6 million, or $0.43 per Boe, compared to the first quarter of 2010 primarily due to higher compensation costs caused by our heightened level of activity. G&A expenses for the first quarter of 2011 include stock-based compensation expense of $1.0 million, of which $0.8 million is associated with grants of restricted stock under our 2010 Equity Incentive Plan that was adopted on April 12, 2010. G&A expenses for the first quarter of 2010 include stock-based compensation expense of $0.1 million associated with our Phantom Stock Plan.

Other income and expenses

Interest expense. The following table presents interest expense for the first quarters of 2011 and 2010:

 

     Three months ended
March 31,
 

(dollars in thousands)

   2011     2010  

Revolver interest

   $ —        $ 6,655   

8.5% Senior Notes due 2015

     4,587        7,115   

8.875% Senior Notes due 2017

     7,431        7,411   

9.875% Senior Notes due 2020

     7,356        —     

8.25% Senior Notes due 2021

     3,445        —     

Bank fees and other interest

     1,506        1,759   

Less capitalized interest

     (615     (388
                

Total interest expense

   $ 23,710      $ 22,552   
                

Average long-term borrowings

   $ 1,012,009      $ 1,176,285   
                

Interest expense increased by $1.2 million, or 5%, from 2010 to 2011 primarily as a result of higher interest rates.

Loss on extinguishment of debt. On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. During the first quarter of 2011, we recorded a $20.6 million loss associated with the refinancing of our 8.5% Senior Notes due 2015, including $15.1 million in repurchase or redemption-related fees and a $5.5 million write off of deferred financing costs.

 

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Non-GAAP financial measure and reconciliation

Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our senior secured revolving credit facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) deferred compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual charges.

In April 2011, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

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

 

     Three months ended
March 31,
 

(dollars in thousands)

   2011     2010  

Net income (loss)

   $ (40,264   $ 25,464   

Interest expense

     23,710        22,552   

Income tax expense (benefit)

     (22,159     16,069   

Depreciation, depletion, and amortization

     33,977        24,521   

Unrealized gains (losses) on ineffective portion of hedges and reclassification adjustments

     6,755        (519

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

     55,632        (23,321

Interest income

     (65     (92

Deferred compensation expense

     1,066        166   

(Gain) loss on disposed assets

     5        (42

Loss on extinguishment of debt

     20,576        —     
                

Adjusted EBITDA

   $ 79,233      $ 64,798   
                

 

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Critical accounting policies and estimates

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

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

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

Certain of our oil and natural gas derivative contracts have historically been treated as cash flow hedges under GAAP. This policy significantly impacts the timing of revenue or expense recognized from this activity, as our contracts are adjusted to their fair value at the end of each month. The effective portion of the hedge gain or loss, meaning the portion of the change in the fair value of the contract that offsets the change in the expected future cash flows from our forecasted sales of production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) from oil and natural gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the effective portion of change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in stockholders’ equity. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) from oil and natural gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment, or have not been designated as cash flow hedges, are marked to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.

 

 

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Oil and natural gas properties.

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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

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

 

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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. We generally assess our ability to fully utilize these carryforwards by estimating expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report and by analyzing the expected reversal of existing deferred tax liabilities. These computations are imprecise due to the extensive use of estimates and assumptions. Each quarter we assess our ability to utilize NOL carryforwards. We will record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such asset will not be realized.

Also see the footnote disclosures included in Part 1, Item 1 of this report.

Recent accounting pronouncements

See recently adopted and issued accounting standards in Part I, Item 1. Financial Statements, Note 1: Nature of operations and summary of significant accounting policies.

 

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and natural gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our senior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the three months ended March 31, 2011, our gross revenues from oil and natural gas sales would change approximately $0.5 million for each $0.10 change in natural gas prices and $1.2 million for each $1.00 change in oil prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into commodity price swaps, costless collars, and basis protection swaps. Effective April 1, 2010, we have elected to de-designate all of our commodity contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. Therefore, the changes in fair value and settlement of all our derivative contracts subsequent to March 31, 2010 are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a put option contract sold by us with a price below the floor price of the collar. This additional put option requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a standard collar contract only. Therefore, if market prices are below the additional put option, we would be entitled to receive the market price plus the difference between the additional put option and the floor. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put option.

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative position.

 

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Our outstanding oil and natural gas derivative instruments as of March 31, 2011 are summarized below:

 

     Oil derivatives  
     Swaps      Collars      Three-way collars         
                                        Weighted average fixed price per Bbl         
     Volume
MBbls
     Weighted
average
fixed price
per Bbl
     Volume
MBbls
     Weighted
average  range
(fixed price
per Bbl)
     Volume
MBbls
     Additional
put option
     Floor      Ceiling      Percent of
PDP
production (1)
 

2Q 2011

     810       $ 76.62         21       $ 110.00 - $153.00         —         $ —         $ —         $ —           80.8

3Q 2011

     772         76.02         21         —           —           —           —           —           84.1

4Q 2011

     747         75.53         21         —           —           —           —           —           86.0

1Q 2012

     521         94.38         —           —           180         65.00         87.50         108.80         81.9

2Q 2012

     499         94.02         —          
—  
  
     180         65.00         87.50         108.80         82.3

3Q 2012

     480         93.75         —          
—  
  
     180         65.00         87.50         108.80         82.7

4Q 2012

     463         93.50         —           —           180         65.00         87.50         108.80         83.1

1Q 2013

     105         102.41         —           —           150         71.00         94.00         128.20         33.9

2Q 2013

     105         102.05         —           —           150         71.00         94.00         128.20         35.7

3Q 2013

     105         101.83         —           —           150         71.00         94.00         128.20         36.7

4Q 2013

     105         101.71         —           —           150         71.00         94.00         128.20         37.5
                                            
     4,712            63            1,320               
                                            

 

     Natural gas swaps  
     Volume
BBtu
     Weighted
average
fixed price
per Btu
     Percent of
PDP
production(1)
 

2Q 2011

     4,870       $ 5.92         79.5

3Q 2011

     4,600         6.17         83.1

4Q 2011

     4,390         6.59         85.2

1Q 2012

     2,400         5.09         49.4

2Q 2012

     2,400         4.91         52.0

3Q 2012

     2,400         4.99         54.3

4Q 2012

     2,400         5.19         56.4

1Q 2013

     1,500         5.31         36.6

2Q 2013

     1,500         5.03         39.4

3Q 2013

     1,500         5.12         40.8

4Q 2013

     1,500         5.37         42.0
              
     29,460         
              

 

     Natural gas basis
protection swaps
 
     Volume
BBtu
     Weighted
average
fixed price
per Btu
 

2Q 2011

     3,860       $ 0.64   

3Q 2011

     3,720         0.64   

4Q 2011

     3,610         0.65   

1Q 2012

     2,100         0.30   

2Q 2012

     2,100         0.30   

3Q 2012

     2,100         0.30   

4Q 2012

     2,100         0.30   
           
     19,590      
           

 

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

 

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Subsequent to March 31, 2011, we entered into additional oil swaps for 257 MBbls for the periods of May 2011 through December 2013 with a weighted average fixed price of $106.70 per Bbl and additional three-way oil collars for 600 MBbls for the periods of January 2012 through December 2013 with a weighted average ceiling of $122.40 per Bbl, a weighted average floor of $102.00 per Bbl, and an additional put option of $77.00 per Bbl. We also entered into additional gas swaps for 4,360 BBtu for the periods of June 2011 through December 2013 with a weighted average fixed price of $5.15 per Btu.

Interest rates. There were no outstanding borrowings under our senior secured revolving facility as of March 31, 2011. We may designate borrowings under our senior secured revolving credit facility as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in the senior secured revolving credit facility, plus 1/2 of 1%, or (3) the Adjusted LIBO rate, as defined in our senior secured revolving credit facility, plus 1%. 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 $375.0 million, equal to our borrowing base at March 31, 2011, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $3.75 million.

 

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation as of the end of the period covered by this quarterly report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Internal control over financial reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time.

 

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PART II—OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

In the opinion of management, there are no 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 1A. RISK FACTORS

Information with respect to risk factors is included under Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2010. There have been no material changes to the risk factors since the filing of such Form 10-K.

 

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ITEM 6. EXHIBITS

 

Exhibit No.

 

Description

  4.1*   Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
  4.2*   Form of 8  1/4 % Senior Note due 2021 (included as Exhibit A to Exhibit 4.1) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
  4.3*   Fourth Supplemental Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
10.1*   Second Amendment to Eighth Restated Credit Agreement dated as of January 11, 2011 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.2*   Third Amendment to Eighth Restated Credit Agreement dated as of February 7, 2011 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.3*   Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)
10.5*   Purchase Agreement dated as of February 7, 2011, by and among Chaparral Energy, Inc. and certain of its subsidiaries named therein, and Wells Fargo Securities, LLC, as Representative of the several Initial Purchasers named therein (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.6*   Solicitation Agent and Dealer Manager Agreement dated February 7, 2011 by and among Chaparral Energy, Inc. and Wells Fargo Securities, LLC (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.7*   Registration Rights Agreement dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
31.1   Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2   Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1   Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2   Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

* Incorporated by reference

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

CHAPARRAL ENERGY, INC.
By:  

/s/ Mark A. Fischer

Name:   Mark A. Fischer
Title:   President and Chief Executive Officer
  (Principal Executive Officer)
By:  

/s/ Joseph O. Evans

Name:   Joseph O. Evans
Title:  

Chief Financial Officer and

Executive Vice President

 

(Principal Financial Officer and

Principal Accounting Officer)

Date: May 13, 2011

 

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EXHIBIT INDEX

 

Exhibit No.

  

Description

  4.1*    Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
  4.2*    Form of 8 1/4 % Senior Note due 2021 (included as Exhibit A to Exhibit 4.1) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
  4.3*    Fourth Supplemental Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
10.1*    Second Amendment to Eighth Restated Credit Agreement dated as of January 11, 2011 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.2*    Third Amendment to Eighth Restated Credit Agreement dated as of February 7, 2011 (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.3*    Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)
10.5*    Purchase Agreement dated as of February 7, 2011, by and among Chaparral Energy, Inc. and certain of its subsidiaries named therein, and Wells Fargo Securities, LLC, as Representative of the several Initial Purchasers named therein (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.6*    Solicitation Agent and Dealer Manager Agreement dated February 7, 2011 by and among Chaparral Energy, Inc. and Wells Fargo Securities, LLC (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.7*    Registration Rights Agreement dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
31.1    Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2    Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1    Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2    Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

* Incorporated by reference

 

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