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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ____________________________
Form 10-Q
____________________________
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2012

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  ý
(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  ý    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
ý
Smaller Reporting Company
¨



Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
Number of shares outstanding of each of the issuer’s classes of common stock as of May 11, 2012: 
Class
Number of
shares
Class A Common Stock, $0.01 par value
65,702

Class B Common Stock, $0.01 par value
357,882

Class C Common Stock, $0.01 par value
209,882

Class D Common Stock, $0.01 par value
279,999

Class E Common Stock, $0.01 par value
504,276

Class F Common Stock, $0.01 par value
1

Class G Common Stock, $0.01 par value
3





CHAPARRAL ENERGY, INC.
Index to Form 10-Q
 
 
 
 
Page
Part I. FINANCIAL INFORMATION
 
 
 
 
 
 
 
 


2


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;
changes in proved reserves;
operating costs and other expenses;
cash flow and anticipated liquidity;
estimates of proved reserves;
exploitation of property acquisitions; and
marketing of oil and natural gas.


3


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, 2012. Specifically, some factors that could cause actual results to differ include:
the significant amount of our debt;
worldwide supply of and demand for oil and natural gas;
volatility and declines in oil and natural gas prices;
drilling plans (including scheduled and budgeted wells);
the number, timing or results of any wells;
changes in wells operated and in reserve estimates;
supply of CO2;
future growth and expansion;
future exploration;
integration of existing and new technologies into operations;
future capital expenditures (or funding thereof) and working capital;
borrowings and capital resources and liquidity;
changes in strategy and business discipline;
future tax matters;
any loss of key personnel;
future seismic data (including timing and results);
the plans for timing, interpretation and results of new or existing seismic surveys or seismic data;
geopolitical events affecting oil and natural gas prices;
outcome, effects or timing of legal proceedings;
the effect of litigation and contingencies;
the ability to generate additional prospects; and
the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.
Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in 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.


4


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.

5


PART I — FINANCIAL INFORMATION

ITEM 1.
FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries
Consolidated balance sheets


 
 
March 31,
2012
 
December 31,
2011
(dollars in thousands, except per share data)
 
(unaudited)
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
22,501

 
$
34,589

Accounts receivable, net
 
68,957

 
64,788

Inventories
 
13,008

 
8,641

Prepaid expenses
 
2,326

 
3,265

Derivative instruments
 
10,844

 
12,840

Total current assets
 
117,636

 
124,123

Property and equipment—at cost, net
 
74,922

 
65,711

Oil and natural gas properties, using the full cost method:
 
 
 
 
Proved
 
2,625,128

 
2,535,404

Unevaluated (excluded from the amortization base)
 
34,173

 
22,831

Accumulated depreciation, depletion, amortization and impairment
 
(1,169,112
)
 
(1,135,567
)
Total oil and natural gas properties
 
1,490,189

 
1,422,668

Derivative instruments
 
8,795

 
16,785

Deferred income taxes
 
3,103

 
7,526

Other assets
 
31,801

 
32,920

 
 
$
1,726,446

 
$
1,669,733

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

6


Chaparral Energy, Inc. and subsidiaries
Consolidated balance sheets - continued
 
 
March 31,
2012
 
December 31,
2011
(dollars in thousands, except per share data)
 
(unaudited)
 
Liabilities and stockholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable and accrued liabilities
 
$
96,096

 
$
68,930

Accrued payroll and benefits payable
 
14,123

 
18,818

Accrued interest payable
 
22,825

 
30,882

Revenue distribution payable
 
18,008

 
20,800

Current maturities of long-term debt and capital leases
 
4,096

 
3,078

Derivative instruments
 
2,973

 
1,505

Deferred income taxes
 
20,697

 
23,704

Total current liabilities
 
178,818

 
167,717

Long-term debt and capital leases, less current maturities
 
1,071,955

 
1,031,495

Derivative instruments
 
1,393

 
127

Stock-based compensation
 
3,144

 
2,788

Asset retirement obligations
 
44,333

 
43,593

Commitments and contingencies (Note 10)
 

 

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 65,722 and 66,165 shares issued and outstanding as of March 31, 2012 and December 31, 2011, 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
 
420,057

 
419,370

Accumulated deficit
 
(37,435
)
 
(47,217
)
Accumulated other comprehensive income, net of taxes
 
44,167

 
51,846

 
 
426,803

 
424,013

 
 
$
1,726,446

 
$
1,669,733


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


7


Chaparral Energy, Inc. and subsidiaries
Consolidated statements of operations
 
 
 
Three months ended
 
 
March 31,
 
 
2012
 
2011
(in thousands)
 
(unaudited)
 
(unaudited)
Revenues:
 
 
 
 
Oil and natural gas sales
 
$
127,789

 
$
127,599

Gain (loss) from oil hedging activities
 
12,423

 
(6,755
)
Other revenues
 

 
1,145

Total revenues
 
140,212

 
121,989

Costs and expenses:
 
 
 
 
Lease operating
 
30,949

 
27,556

Production tax
 
8,290

 
8,624

Depreciation, depletion and amortization
 
36,932

 
33,977

General and administrative
 
13,449

 
8,008

Other expenses
 

 
1,082

Total costs and expenses
 
89,620

 
79,247

Operating income
 
50,592

 
42,742

Non-operating expense:
 
 
 
 
Interest expense
 
(24,156
)
 
(23,710
)
Non-hedge derivative losses
 
(10,463
)
 
(60,926
)
Loss on extinguishment of debt
 

 
(20,576
)
Other income and expenses
 
5

 
47

Net non-operating expense
 
(34,614
)
 
(105,165
)
Income (loss) before income taxes
 
15,978

 
(62,423
)
Income tax expense (benefit)
 
6,196

 
(22,159
)
Net income (loss)
 
$
9,782

 
$
(40,264
)

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


8


Chaparral Energy, Inc. and subsidiaries
Consolidated statements of comprehensive income
 
 
 
Three months ended
 
 
March 31,
 
 
2012
 
2011
(in thousands)
 
(unaudited)
 
(unaudited)
Net income (loss)
 
$
9,782

 
$
(40,264
)
Other comprehensive income (loss)
 
 
 
 
Reclassification adjustment for hedge (gains) losses included in net income (loss)
 
(12,423
)
 
6,755

Income tax expense (benefit) related to other comprehensive income (loss)
 
4,744

 
(2,568
)
Other comprehensive income (loss), net of tax
 
(7,679
)
 
4,187

Comprehensive income (loss)
 
$
2,103

 
$
(36,077
)

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



9


Chaparral Energy, Inc. and subsidiaries
Consolidated statements of cash flows
 
 
Three months ended
 
 
March 31,
 
 
2012
 
2011
(in thousands)
 
(unaudited)
 
(unaudited)
Cash flows from operating activities
 
 
 
 
Net income (loss)
 
$
9,782

 
$
(40,264
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
 
 
 
 
Depreciation, depletion & amortization
 
36,932

 
33,977

Deferred income taxes
 
6,161

 
(22,159
)
Reclassification adjustment for hedge (gains) losses included in net income (loss)
 
(12,423
)
 
6,755

Non-hedge derivative losses
 
10,463

 
60,926

Loss on extinguishment of debt
 

 
20,576

Loss on sale of assets
 
95

 
5

Other
 
751

 
732

Change in assets and liabilities
 
 
 
 
Accounts receivable
 
(1,830
)
 
(7,281
)
Inventories
 
(4,367
)
 
1,026

Prepaid expenses and other assets
 
1,559

 
1,457

Accounts payable and accrued liabilities
 
(4,539
)
 
7,942

Revenue distribution payable
 
(2,792
)
 
2,258

Stock-based compensation
 
1,089

 
1,066

Net cash provided by operating activities
 
40,881

 
67,016

Cash flows from investing activities
 
 
 
 
Purchase of property and equipment and oil and natural gas properties
 
(98,403
)
 
(88,518
)
Proceeds from dispositions of property and equipment and oil and natural gas properties
 
1,856

 
211

Settlement of non-hedge derivative instruments
 
2,257

 
(5,294
)
Other
 
22

 

Net cash used in investing activities
 
(94,268
)
 
(93,601
)
Cash flows from financing activities
 
 
 
 
Proceeds from long-term debt
 
42,176

 
1,059

Repayment of long-term debt and capital lease obligations
 
(877
)
 
(1,275
)
Proceeds from Senior Notes
 

 
400,000

Repayment of Senior Notes
 

 
(325,000
)
Payment of debt issuance costs and other financing fees
 

 
(8,597
)
Payment of debt extinguishment costs
 

 
(15,085
)
Net cash provided by financing activities
 
41,299

 
51,102

Net increase (decrease) in cash and cash equivalents
 
(12,088
)
 
24,517

Cash and cash equivalents at beginning of period
 
34,589

 
55,111

Cash and cash equivalents at end of period
 
$
22,501

 
$
79,628

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

10


Chaparral Energy, Inc. and subsidiaries
Notes to consolidated financial statements (unaudited)
(dollars in thousands, unless otherwise noted)

Note 1: Nature of operations and summary of significant accounting policies
Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are 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, and Kansas.
Interim financial statements
The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011.
The financial information as of March 31, 2012, and for the three months ended March 31, 2012 and 2011, is unaudited. In management’s opinion, 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, 2012 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2012.
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, 2012, cash with a recorded balance totaling $18,617 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.

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. 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.

11


We write off accounts receivable when they are determined to be uncollectible. Accounts receivable consisted of the following at March 31, 2012 and December 31, 2011: 
 
March 31,
2012
 
December 31,
2011
Joint interests
$
21,369

 
$
16,926

Accrued oil and natural gas sales
47,086

 
47,667

Derivative settlements
963

 
449

Other
276

 
380

Allowance for doubtful accounts
(737
)
 
(634
)
 
$
68,957

 
$
64,788

Inventories
Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas production inventories. Equipment inventory is 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, 2012 and December 31, 2011 consisted of the following: 
 
March 31,
2012
 
December 31,
2011
Equipment inventory
$
11,007

 
$
6,164

Oil and natural gas product
3,317

 
3,793

Inventory valuation allowance
(1,316
)
 
(1,316
)
 
$
13,008

 
$
8,641

Stock-based compensation
Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees.
Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.
The estimated fair value of the phantom stock and RSU 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 and the Non-Officer Restricted Stock Unit 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 and RSU awards is recognized on a straight-line basis over the vesting period.
The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common stock on the date of grant, and is remeasured at the end of each reporting period until settlement. We 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.

12


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 our deferred tax assets will be realized. The amount of the deferred tax assets considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.
Recently adopted and issued accounting pronouncements
In May 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we adopted it effective January 1, 2012. There was no significant impact on our consolidated financial statements other than additional disclosures.
In June 2011, the FASB issued new authoritative guidance that requires entities that report other comprehensive income to present the components of net income and comprehensive income in either one continuous financial statement or two consecutive financial statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we applied it retrospectively beginning on January 1, 2012. We have elected to present the components of net income and comprehensive income in two consecutive financial statements.
In December 2011, the FASB issued authoritative guidance that requires enhanced disclosures that will enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. This guidance is effective for interim and annual reporting periods beginning on or after January 1, 2013 and should be applied retrospectively. We do not expect this guidance to have an impact on our consolidated financial statements other than additional disclosures.



13


Note 2: Supplemental disclosures to the consolidated statements of cash flows 
Supplemental disclosures to the consolidated statements of cash flows are presented below:
 
 
Three months ended March 31,
 
 
2012
 
2011
Net cash provided by operating activities included:
 
 
 
 
Cash payments for interest
 
$
31,233

 
$
21,564

Interest capitalized
 
(710
)
 
(615
)
Cash payments for interest, net of amounts capitalized
 
$
30,523

 
$
20,949

Cash (receipts) payments for income taxes
 
$

 
$

Non-cash investing activities included:
 
 
 
 
Asset retirement costs capitalized
 
$
20

 
$
159

Oil and natural gas properties acquired through increase (decrease) in accounts payable and accrued liabilities
 
$
17,505

 
$
(271
)


Note 3: Long-term debt
Long-term debt at March 31, 2012 and December 31, 2011, consisted of the following: 
 
 
March 31, 2012
 
December 31, 2011
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

 
400,000

Senior secured revolving credit facility
 
40,000

 

Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.50% to 5.46%, due January 2013 through December 2028; collateralized by real property
 
12,932

 
12,116

Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.00% to 9.25%, due April 2012 through March 2017; collateralized by automobiles, machinery and equipment
 
6,039

 
5,546

Capital lease obligations
 

 
10

Discount on 8.875% Senior Notes due 2017
 
(1,593
)
 
(1,658
)
Discount on 9.875% Senior Notes due 2020
 
(6,327
)
 
(6,441
)
 
 
1,076,051

 
1,034,573

Less current maturities
 
4,096

 
3,078

 
 
$
1,071,955

 
$
1,031,495


14


In April 2010, we entered into our Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and 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.
The Eighth Amendment to our senior secured revolving credit facility, effective April 30, 2012, amended our Asset Sale Covenant to permit the sale of certain oil and natural gas properties located in southern Oklahoma and increased our permitted ratio of Consolidated Net Debt to Consolidated EBITDAX from 4.25 to 4.50. It also reaffirmed the borrowing base at $375,000 through November 1, 2012. As of May 11, 2012, the balance outstanding under our senior secured revolving credit facility is $50,000.
Borrowings under our senior secured revolving credit facility are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans. The entire balance outstanding at March 31, 2012 was a Eurodollar loan.
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. 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 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 the four consecutive fiscal quarters ending on June 30, 2010 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, 2012.
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.
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.




15


Note 4: Derivative 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.
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 market price is below the additional put option price. If the market 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. 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 market price falls below the additional put option price. 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.


16


In December 2011, we amended our senior secured revolving credit facility to provide greater flexibility when hedging anticipated production. The terms of the amendment allow us to protect a portion of our natural gas liquids production from price volatility using crude oil derivatives. Our outstanding derivative instruments as of March 31, 2012 are summarized below: 
 
Oil derivatives
 
Swaps
 
Three-way collars
 
Volume
MBbls
 
Weighted average fixed price per Bbl
 
Volume
MBbls
 
Weighted average fixed price per Bbl
 
 
Additional
put option
 
Put
 
Call
2012
1,532

 
$
94.52

 
1,514

 
$
73.55

 
$
96.01

 
$
108.78

2013
540

 
102.45

 
3,240

 
77.78

 
100.07

 
115.45

 
2,072

 
 
 
4,754

 
 
 
 
 
 
 
 
Natural gas swaps
 
Natural gas basis
protection swaps
 
Volume
BBtu
 
Weighted average
fixed price per Btu
 
Volume
BBtu
 
Weighted average
fixed price per Btu
2012
10,800

 
$
4.73

 
6,300

 
$
0.30

2013
7,200

 
5.24

 

 

 
18,000

 
 
 
6,300

 
 
Our derivative contracts have been executed with the institutions that are parties to our senior secured revolving credit facility, and we believe the credit risks associated with all of these institutions are acceptable. We did not post collateral under any of these contracts as they are secured under our senior secured revolving credit facility. As of March 31, 2012, we had $40,000 outstanding under our senior secured revolving credit facility, and we had significant commodity derivative net asset balances with the following counterparties:
 
 
Percentage of
 
 
future hedged
Counterparty
 
production
JP Morgan Chase Bank, N.A.
 
37
%
Societe Generale
 
24
%
Crédit Agricole CIB
 
10
%
 
 
71
%
Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities was $24,071 at March 31, 2012.


17


Effect of derivative instruments on the consolidated balance sheets
All derivative financial instruments are recorded on the balance sheet at fair value. See Note 5 for additional information regarding fair value measurements. 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, 2012
 
As of December 31, 2011
 
Assets
 
Liabilities
 
Net value
 
Assets
 
Liabilities
 
Net value
Natural gas swaps
$
35,883

 
$

 
$
35,883

 
$
30,124

 
$

 
$
30,124

Oil swaps
337

 
(15,993
)
 
(15,656
)
 
3,832

 
(9,744
)
 
(5,912
)
Oil collars
3,124

 
(7,183
)
 
(4,059
)
 
6,296

 
(1,247
)
 
5,049

Natural gas basis differential swaps

 
(895
)
 
(895
)
 

 
(1,268
)
 
(1,268
)
Total derivative instruments
39,344

 
(24,071
)
 
15,273

 
40,252

 
(12,259
)
 
27,993

Less:
 
 
 
 
 
 
 
 
 
 
 
Netting adjustments (1)
19,705

 
(19,705
)
 

 
10,627

 
(10,627
)
 

Current portion asset (liability)
10,844

 
(2,973
)
 
7,871

 
12,840

 
(1,505
)
 
11,335

 
$
8,795

 
$
(1,393
)
 
$
7,402

 
$
16,785

 
$
(127
)
 
$
16,658

___________
(1)
Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.
We discontinued hedge accounting effective April 1, 2010. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through accumulated other comprehensive income (“AOCI”). As of March 31, 2012 and December 31, 2011, respectively, AOCI consists of deferred gains of $71,458 ($44,167 net of tax) and $83,880 ($51,846 net of tax) that will be recognized as gains from oil hedging activities through December 2013 as the hedged production is sold. We expect to reclassify deferred gains of $44,326 ($27,398 net of tax) from AOCI to income during the next 12 months.
Derivative settlements outstanding at March 31, 2012 and December 31, 2011 were as follows: 
 
March 31,
2012
 
December 31,
2011
Derivative settlements receivable included in accounts receivable
$
963

 
$
449

Derivative settlements payable included in accounts payable and accrued liabilities
$
1,741

 
$
5,042


18


Effect of derivative instruments on the consolidated statements of operations
We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations.
Gain (loss) from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains (losses) on discontinued oil hedges into net income.

Non-hedge derivative losses in the consolidated statements of operations are comprised of the following: 
 
Three months ended
 
March 31,
 
2012
 
2011
Change in fair value of commodity price swaps
$
(3,985
)
 
$
(50,168
)
Change in fair value of collars
(9,108
)
 
(6,605
)
Change in fair value of natural gas basis differential contracts
373

 
1,141

Receipts from (payments on) settlement of commodity price swaps
2,701

 
(3,282
)
Receipts from settlement of collars
33

 
334

Payments on settlement of natural gas basis differential contracts
(477
)
 
(2,346
)
 
$
(10,463
)
 
$
(60,926
)



19


Note 5: Fair value measurements
Fair value is defined by the 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.
Fair value measurements 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 as follows:
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability. 
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.
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.
Recurring fair value measurements
Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4). We have no Level 1 assets or liabilities as of March 31, 2012 or December 31, 2011. Our derivative contracts classified as Level 2 as of March 31, 2012 and December 31, 2011 consist of commodity price swaps and basis protection swaps, which are valued using an income approach. 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.
As of March 31, 2012 and December 31, 2011, our derivative contracts classified as Level 3 consist of three-way collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness.
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. If available, we use our counterparties’ credit default swap values or the spread between the risk-free interest rate and the yield on our counterparties’ publicly traded debt having similar maturities to our derivative contracts as the measure of our counterparties’ nonperformance risk. As of March 31, 2012 and December 31, 2011, the rate reflecting our nonperformance risk was 1.75% and 1.75%, respectively. The weighted-average rate reflecting our counterparties’ nonperformance risk was approximately 2.20% and 3.38% as of March 31, 2012 and December 31, 2011, respectively.

20


The fair value hierarchy for our financial assets and liabilities is shown by the following table: 
 
As of March 31, 2012
 
As of December 31, 2011
 
Derivative
assets
 
Derivative
liabilities
 
Net assets
(liabilities)
 
Derivative
assets
 
Derivative
liabilities
 
Net assets
(liabilities)
Significant other observable inputs (Level 2)
$
36,220

 
$
(16,888
)
 
$
19,332

 
$
33,956

 
$
(11,012
)
 
$
22,944

Significant unobservable inputs (Level 3)
3,124

 
(7,183
)
 
(4,059
)
 
6,296

 
(1,247
)
 
5,049

Netting adjustments (1)
(19,705
)
 
19,705

 

 
(10,627
)
 
10,627

 

 
$
19,639

 
$
(4,366
)
 
$
15,273

 
$
29,625

 
$
(1,632
)
 
$
27,993

  ___________
(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 our three-way collars classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2012 and 2011 were: 
 
 
For the three months ended March 31,
Net derivative assets (liabilities)
 
2012
 
2011
Beginning balance
 
$
5,049

 
$
1,509

Realized and unrealized losses included in non-hedge derivative losses
 
(9,075
)
 
(6,271
)
Settlements received
 
(33
)
 
(334
)
Ending balance
 
$
(4,059
)
 
$
(5,096
)
Losses relating to instruments still held at the reporting date included in non-hedge derivative losses for the period
 
$
(8,602
)
 
$
(6,233
)
Nonrecurring fair value measurements
Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. 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 three months of 2012 and 2011 were escalated using an annual inflation rate of 2.95% in each period, and discounted using our credit-adjusted risk-free interest rate of 7.5% and 8.0%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the three months ended March 31, 2012 and 2011, additions to our asset retirement obligations were $20 and $159, respectively. See Note 6 for additional information regarding our asset retirement obligations.

21


Fair value of other financial instruments
Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and long-term debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.
The carrying value and estimated fair value of our long-term debt at March 31, 2012 and December 31, 2011 were as follows: 
 
 
March 31, 2012
 
December 31, 2011
Level 2
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
8.875% Senior Notes due 2017
 
$
323,407

 
$
338,813

 
$
323,342

 
$
326,625

9.875% Senior Notes due 2020
 
293,673

 
335,250

 
293,559

 
322,500

8.25% Senior Notes due 2021
 
400,000

 
428,000

 
400,000

 
402,400

Senior secured revolving credit facility
 
40,000

 
40,000

 

 

Other secured long-term debt
 
18,971

 
18,971

 
17,672

 
17,672

 
 
$
1,076,051

 
$
1,161,034

 
$
1,034,573

 
$
1,069,197

The fair value of our Senior Notes was estimated based on quoted market prices. The carrying value of our senior secured revolving credit facility approximates fair value because it has a variable interest rate and incorporates a measure of our credit risk. The carrying value of our other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms.

Note 6: 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 obligation is included in depreciation, depletion, and amortization on the consolidated statements of operations. The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2012 and 2011. 
 
 
For the three months ended March 31,
 
 
2012
 
2011
Beginning balance
 
$
46,493

 
$
41,695

Liabilities incurred in current period
 
20

 
159

Liabilities settled in current period
 
(254
)
 
(550
)
Accretion expense
 
974

 
874

 
 
47,233

 
42,178

Less current portion
 
2,900

 
690

 
 
$
44,333

 
$
41,488

See Note 5 for additional information regarding fair value measurements.




22


Note 7: Stock-based compensation
Phantom Stock Plan and Restricted Stock Unit 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 “Phantom 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 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. Phantom shares are cash-settled within 120 days of the vesting date.
Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable the Company to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, no further awards under the Phantom Plan are expected to be made.
Restricted stock units may be awarded to Participants in total up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment during the twelve-month period following the occurrence of a change of control event. RSU awards are cash-settled, generally within 120 days of the vesting date.
A summary of our phantom stock and RSU activity during the three months ended March 31, 2012 is presented in the following table: 
 
Phantom Plan
 
RSU Plan
 
Weighted
average
grant date
fair value
 
Phantom
shares
 
Vest
date
fair
value
 
Weighted
average
grant date
fair value
 
Restricted Stock Units
 
($ per share)
 
 
 
 
 
($ per share)
 
 
Unvested and outstanding at January 1, 2012
$
16.37

 
125,768

 
 
 
$

 

Granted
$

 

 
 
 
$
17.84

 
151,170

Vested
$
14.29

 
(22,803
)
 
$
378

 
$

 

Forfeited
$
18.02

 
(2,829
)
 
 
 
$

 

Unvested and outstanding at March 31, 2012
$
16.80

 
100,136

 
 
 
$
17.84

 
151,170

No payments for phantom shares or RSU were made during the first quarter of 2012 or 2011. Based on an estimated fair value of $17.91 per phantom share and RSU as of March 31, 2012, the aggregate intrinsic value of the unvested phantom shares and RSU outstanding was $4,501.

23


2010 Equity Incentive Plan
We adopted the Chaparral Energy, Inc. 2010 Equity 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.
These awards consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vesting conditions (the “Performance Vested” awards). The Time Vested awards vest in equal annual installments over the five-year vesting period but may also vest on an accelerated basis in the event of a Transaction (as defined in the 2010 Plan). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan.

A summary of our restricted stock activity during the three months ended March 31, 2012 is presented in the following table: 
 
Time Vested
 
Performance Vested
 
Weighted
average
grant date
fair value
 
Restricted
shares
 
Vest
date
fair
value
 
Weighted
average
grant date
fair value
 
Restricted
shares
 
($ per share)
 
 
 
 
 
($ per share)
 
 
Unvested and outstanding at January 1, 2012
$
680.74

 
11,585

 
 
 
$
298.15

 
53,098

Granted
$
747.08

 
125

 
 
 
$
394.00

 
278

Vested
$
703.30

 
(255
)
 
$
191

 
$

 

Forfeited
$
703.30

 
(170
)
 
 
 
$
307.00

 
(593
)
Unvested and total outstanding at March 31, 2012
$
680.62

 
11,285

 
 
 
$
298.56

 
52,783

During the three months ended March 31, 2012, we repurchased and canceled 83 vested shares for tax withholding, and we expect to repurchase approximately 1,000 restricted shares vesting during the next twelve months. Payments for Time Vested restricted shares totaled $62 during the first quarter of 2012. There were no payments for Time Vested restricted shares during the first quarter of 2011. Based on an estimated fair value of $747.08 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $8,431.


24


Stock-based compensation cost
Compensation cost is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. 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.
A portion of stock-based compensation cost associated with 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. We recognized stock-based compensation expense as follows for the periods indicated:
 
Three months ended
 
March 31,
 
2012
 
2011
Stock-based compensation cost
$
1,804

 
$
1,675

Less: stock-based compensation cost capitalized
(653
)
 
(609
)
Stock-based compensation expense
$
1,151

 
$
1,066

As of March 31, 2012 and December 31, 2011, accrued payroll and benefits payable included $3,058 and $2,359, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $18,106 is expected to be recognized over a weighted-average period of 3.11 years.

Note 8: Common stock
The following is a summary of the changes in our common shares outstanding during the first quarter of 2012: 
 
Common Stock
 
Class A
 
Class B
 
Class C
 
Class D
 
Class E
 
Class F
 
Class G
 
Total
Shares issued at January 1, 2012
66,165

 
357,882

 
209,882

 
279,999

 
504,276

 
1

 
3

 
1,418,208

Restricted stock issuances
403

 

 

 

 

 

 

 
403

Restricted stock used for tax withholding
(83
)
 

 

 

 

 

 

 
(83
)
Restricted stock forfeitures
(763
)
 

 

 

 

 

 

 
(763
)
Shares issued at March 31, 2012
65,722

 
357,882

 
209,882

 
279,999

 
504,276

 
1

 
3

 
1,417,765




25


Note 9: Related party transactions
Chesapeake Holdings Corporation, 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,
 
2012
 
2011
Revenues
$
945

 
$
1,277

Joint interest billings
$
(472
)
 
$
(258
)
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,
 
2012
 
2011
Revenues
$
(623
)
 
$
(461
)
Joint interest billings
$
1,537

 
$
1,766

Amounts receivable from and payable to Chesapeake at March 31, 2012 and December 31, 2011 were as follows: 
 
March 31, 2012
 
December 31, 2011
Amounts receivable from Chesapeake
$
982

 
$
223

Amounts payable to Chesapeake
$
177

 
$
207




26


Note 10: Commitments and contingencies
Standby letters of credit (“Letters”) available under our senior secured revolving credit facility 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 $2,920 as of March 31, 2012 and December 31, 2011. Interest on each Letter accrues at the lender’s prime rate plus applicable margin for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the three months ended March 31, 2012 or 2011.
Naylor Farms, Inc. v. Chaparral Energy, L.L.C.
On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5,000. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied the allegations and are aggressively defending the case. The case is in the initial stages of discovery and has not yet been set for trial. As such, we are not yet able to estimate what impact, if any, the action will have on our financial condition, results of operations, or cash flows.
In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

Note 11: Subsequent events
On April 4, 2012, we entered into an agreement to divest certain of our mature oil and natural gas properties located in southern Oklahoma for a cash price of $37,000 subject to post-closing adjustments. The sale is expected to close by May 30, 2012. The properties included in the sale accounted for approximately 1% of our total production during the first quarter of 2012 and 2011.
On April 17, 2012, we entered into an amendment to our senior secured revolving credit facility to increase the amount of additional debt permitted thereunder by $75,000 in connection with an offering of Senior Notes.
On May 2, 2012, we issued $400,000 aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 7.625% Senior Notes and the repurchase or redemption of our 8.875% Senior Notes due 2017, we capitalized approximately $8,500 of issuance costs related to underwriting and other fees and we expensed approximately $21,700 of refinancing costs in May 2012.


27



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. Our core operations consist of enhanced oil recovery (“EOR”) projects and conventional (non-EOR) oil and natural gas production activities focused in the Mid-Continent and Permian Basin Areas. 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, 2011 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 15%, 11% 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.
During the first quarter of 2012, production was 2,118 MBoe compared to production of 2,062 MBoe during the first quarter of 2011. This slight increase in production was offset by a slight decrease in our average sales price before hedging, and as a result, revenue from oil and natural gas sales was flat in the first quarter of 2012 compared to the same period in 2011. In addition, due primarily to changes in the NYMEX forward commodity price curves, our loss on non-hedge derivatives decreased to $10.5 million during the first quarter of 2012 compared to a loss of $60.9 million in the first quarter of 2011. 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. As a result of these and other factors, we reported net income of $9.8 million during the first quarter of 2012 compared to a net loss of $40.3 million for the comparable period in 2011.


28


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:
7.625% Senior Notes due 2022. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 7.625% Senior Notes and the repurchase or redemption of our 8.875% Senior Notes due 2017, in May 2012, we capitalized approximately $8.5 million of issuance costs related to underwriting and other fees and we expensed approximately $21.7 million of refinancing costs, including a $4.3 million non-cash write off of deferred financing costs.
Asset sale. On April 4, 2012, we entered into an agreement to divest certain of our mature oil and natural gas properties located in southern Oklahoma for a cash price of $37.0 million subject to post-closing adjustments. The sale is expected to close by May 30, 2012. The properties included in the sale accounted for approximately 1% of our total production during the first quarter of 2012 and 2011.
Capital expenditures. Our oil and natural gas property capital expenditure budget for 2012, which is front-end loaded, is set at $316.0 million. Our capital expenditures are focused on the development of our EOR assets and drilling in our repeatable resource plays. Investing in EOR reduces near term growth opportunities but enhances longer term growth and is consistent with our strategy of driving near term growth through drilling and long term growth through EOR development.
Stock-based compensation. In the first quarter of 2012, we adopted the Chaparral Energy, Inc. Non-Officer Restricted Stock Unit Plan (the “RSU Plan”), which is intended to replace our existing Phantom Stock Plan. Initial awards under the RSU Plan have an aggregate grant-date fair value of $2.7 million and will vest in equal annual installments over the next three years.


29



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
 
Percentage
change
 
March 31,
 
 
2012
 
2011
 
Oil and natural gas sales (in thousands)
 
 
 
 
 
Oil
$
116,303

 
$
105,753

 
10.0
 %
Natural gas
11,486

 
21,846

 
(47.4
)%
Total
$
127,789

 
$
127,599

 
0.1
 %
Production
 
 
 
 
 
Oil (MBbls)
1,316

 
1,204

 
9.3
 %
Natural gas (MMcf)
4,812

 
5,148

 
(6.5
)%
MBoe
2,118

 
2,062

 
2.7
 %
Average sales prices (excluding derivative settlements)
 
 
 
 
 
Oil per Bbl
$
88.38

 
$
87.83

 
0.6
 %
Gas per Mcf
$
2.39

 
$
4.24

 
(43.6
)%
Boe
$
60.33

 
$
61.88

 
(2.5
)%
Oil and natural gas revenues were flat during the first quarter of 2012 compared to the first quarter of 2011, primarily due to a 3% decrease in the average price per Boe, which offset the 3% increase in sales volumes.
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, 2012 vs. 2011
(in thousands)
 
Sales
change
 
Percentage
change
in  sales
Change in oil sales due to:
 
 
 
 
Prices
 
$
713

 
0.7
 %
Production
 
9,837

 
9.3
 %
Total change in oil sales
 
$
10,550

 
10.0
 %
Change in natural gas sales due to:
 
 
 
 
Prices
 
$
(8,934
)
 
(40.9
)%
Production
 
(1,426
)
 
(6.5
)%
Total change in natural gas sales
 
$
(10,360
)
 
(47.4
)%

30


Production volumes by area were as follows (MBoe): 
 
Three months ended
 
Percentage
change
 
March 31,
 
 
2012
 
2011
 
Enhanced Oil Recovery Project Areas
325

 
275

 
18.2
 %
Mid-Continent Area
1,253

 
1,151

 
8.9
 %
Permian Basin Area
311

 
343

 
(9.3
)%
Other
229

 
293

 
(21.8
)%
Total
2,118

 
2,062

 
2.7
 %
We sold certain non-strategic oil and natural gas properties located in the Rocky Mountains area during the fourth quarter of 2011. These properties accounted for approximately 2% of our production during the first quarter of 2011.

31


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.
Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. In December 2011, we amended our senior secured revolving credit facility to provide greater flexibility when hedging anticipated production. The terms of the amendment allow us to protect a portion of our natural gas liquids production from price volatility using crude oil derivatives. 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,
 
2012
 
2011
Oil (per Bbl):
 
 
 
Before derivative settlements
$
88.38

 
$
87.83

After derivative settlements
$
85.11

 
$
75.72

Post-settlement to pre-settlement price
96.3
%
 
86.2
%
Natural gas (per Mcf):
 
 
 
Before derivative settlements
$
2.39

 
$
4.24

After derivative settlements
$
3.75

 
$
6.05

Post-settlement to pre-settlement price
156.9
%
 
142.7
%
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. 
(in thousands)
 
March 31, 2012
 
December 31, 2011
Derivative assets (liabilities):
 
 
 
 
Natural gas swaps
 
$
35,883

 
$
30,124

Oil swaps
 
(15,656
)
 
(5,912
)
Oil collars
 
(4,059
)
 
5,049

Natural gas basis differential swaps
 
(895
)
 
(1,268
)
Net derivative asset (liability)
 
$
15,273

 
$
27,993

We discontinued hedge accounting effective April 1, 2010. Net derivative gains (losses) attributable to derivatives previously subject to hedge accounting were deferred through accumulated other comprehensive income (“AOCI”). As of March 31, 2012 and December 31, 2011, respectively, AOCI consists of deferred gains of $71.5 million ($44.2 million net of tax) and $83.9 million ($51.8 million net of tax) that will be recognized as gains from oil hedging activities through December 2013 as the hedged production is sold.

32


We no longer apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains (losses) in the consolidated statements of operations.
Gain (loss) from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains (losses) on discontinued oil hedges into net income.
The effects of derivative activities on our results of operations and cash flows for the first quarters of 2012 and 2011 were as follows: 
 
 
Three months ended March 31,
 
 
2012
 
2011
(in thousands)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
 
 
 
 
 
 
 
 
Gain (loss) from oil hedging activities
 
$
12,423

 
$

 
$
(6,755
)
 
$

Non-hedge derivative gains (losses):
 
 
 
 
 
 
 
 
Oil swaps and collars
 
$
(18,852
)
 
$
(4,297
)
 
$
(45,693
)
 
$
(14,586
)
Natural gas swaps
 
5,759

 
7,031

 
(11,080
)
 
11,638

Natural gas basis differential contracts
 
373

 
(477
)
 
1,141

 
(2,346
)
Non-hedge derivative gains (losses)
 
$
(12,720
)
 
$
2,257

 
$
(55,632
)
 
$
(5,294
)
Total gains (losses) from derivative activities
 
$
(297
)
 
$
2,257


$
(62,387
)
 
$
(5,294
)
During the first quarters of 2012 and 2011, respectively, we reclassified into earnings gains (losses) of $12.4 million and $(6.8) million, which were associated with oil swaps for which hedge accounting was previously discontinued.
We recognized net non-hedge derivative losses of $10.5 million and $60.9 million for the first quarters of 2012 and 2011, respectively. The fluctuation in non-hedge derivative gains (losses) from period to period is due primarily to the significant volatility of oil and natural gas prices and to changes in our outstanding derivative contracts during these periods.
Total gains (losses) on derivative activities recognized in our consolidated statements of operations for the first quarters of 2012 and 2011 were $2.0 million and $(67.7) million, respectively.

33


Lease operating expenses 
 
Three months ended March 31,
 
Percentage
change
 
2012
 
2011
 
Lease operating expenses (in thousands)
$
30,949

 
$
27,556

 
12.3
%
Lease operating expenses per Boe
$
14.61

 
$
13.36

 
9.4
%
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 $3.4 million, or $1.25 per Boe, during the first quarter of 2012 compared to the first quarter of 2011. Favorable weather conditions allowed for increased activity during the first quarter of 2012. Workover expenses for operated properties and field personnel wages and benefits increased by $1.0 million and $0.9 million, respectively, during the first quarter of 2012 compared to the first quarter of 2011.
Production taxes (which include ad valorem taxes) 
 
Three months ended March 31,
 
Percentage
change
 
2012
 
2011
 
Production taxes (in thousands)
$
8,290

 
$
8,624

 
(3.9
)%
Production taxes per Boe
$
3.91

 
$
4.18

 
(6.5
)%
Production taxes generally change in proportion to oil and natural gas sales. The decrease in production taxes during the first quarter of 2012 compared to the first quarter of 2011 was primarily due to claiming a reduced tax rate on production from horizontal and deep wells drilled in Oklahoma.

34


Depreciation, depletion and amortization (“DD&A”) 
 
Three months ended March 31,
 
Percentage
change
 
2012
 
2011
 
DD&A (in thousands):
 
 
 
 
 
Oil and natural gas properties
$
33,545

 
$
30,535

 
9.9
 %
Property and equipment
2,413

 
2,568

 
(6.0
)%
Accretion of asset retirement obligation
974

 
874

 
11.4
 %
Total DD&A
$
36,932

 
$
33,977

 
8.7
 %
DD&A per Boe:
 
 
 
 
 
Oil and natural gas properties
$
15.84

 
$
14.81

 
7.0
 %
Other fixed assets
$
1.60

 
$
1.67

 
(4.2
)%
Total DD&A per Boe
$
17.44

 
$
16.48

 
5.8
 %
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 $3.0 million in the first quarter of 2012 compared to the first quarter of 2011, of which $2.2 million was due to a higher rate per equivalent unit of production and $0.8 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $1.03 to $15.84 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.
General and administrative expenses (“G&A”) 
 
 
Three months ended March 31,
 
Percentage
change
 
 
2012
 
2011
 
G&A (in thousands):
 
 
 
 
 
 
Gross G&A expenses
 
$
18,044

 
$
12,422

 
45.3
%
Capitalized exploration and development costs
 
(4,595
)
 
(4,414
)
 
4.1
%
Net G&A expenses
 
$
13,449

 
$
8,008

 
67.9
%
Average G&A expense per Boe
 
$
6.35

 
$
3.88

 
63.7
%
G&A expenses for the first quarter of 2012 increased by $2.47 per Boe compared to the first quarter of 2011. Approximately one third of the increase is due to professional services related to certain projects and initiatives that are expected to phase out over the year. The remainder is due primarily to compensation and benefit cost increases related to the competitive nature of our market and our increased activity, along with other expenses and general inflation.

35


Other income and expenses
Interest expense. The following table presents interest expense for the periods indicated: 
 
 
Three months ended
 
 
March 31,
(in thousands)
 
2012
 
2011
8.5% Senior Notes due 2015
 
$

 
$
4,587

8.875% Senior Notes due 2017
 
7,453

 
7,431

9.875% Senior Notes due 2020
 
7,630

 
7,356

8.25% Senior Notes due 2021
 
8,390

 
3,445

Senior secured revolving credit facility
 
56

 

Bank fees and other interest
 
1,337

 
1,506

Capitalized interest
 
(710
)
 
(615
)
Total interest expense
 
$
24,156

 
$
23,710

Average long-term borrowings
 
$
1,052,511

 
$
1,012,009

Total interest expense increased by $0.4 million during the first quarter of 2012 compared to the first quarter of 2011 primarily due to increased levels of borrowing, partially offset by a lower weighted-average interest rate.
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.
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, 2012, we had cash and cash equivalents of $22.5 million and availability of $332.1 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.


36


Sources and uses of cash
Our net increase (decrease) in cash is summarized as follows: 
 
 
Three months ended
 
 
March 31,
(in thousands)
 
2012
 
2011
Cash flows provided by operating activities
 
$
40,881

 
$
67,016

Cash flows used in investing activities
 
(94,268
)
 
(93,601
)
Cash flows provided by financing activities
 
41,299

 
51,102

Net increase (decrease) in cash during the period
 
$
(12,088
)
 
$
24,517

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 were 39% lower in the first quarter of 2012 than they were in the first quarter of 2011 primarily due to higher interest payments and operating expenses.
We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the three months ended March 31, 2012 and 2011, cash flows provided by operating activities were approximately 42% and 76%, 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 during the three months ended March 31, 2012 are detailed below: 
(in thousands)
 
EOR Project Areas
 
Mid-Continent Area
 
Permian Basin Area
 
Other
 
Total
 
Budgeted
2012 capital
expenditures
Acquisitions
 
$
128

 
$
11,101

 
$
854

 
$
25

 
$
12,108

 
$
15,000

Drilling
 
10,154

 
43,899

 
11,810

 
740

 
66,603

 
148,000

Enhancements
 
10,409

 
2,873

 
2,132

 
2,198

 
17,612

 
36,000

Pipeline and field infrastructure
 
4,578

 

 

 

 
4,578

 
100,000

CO2 purchases
 
1,939

 

 

 

 
1,939

 
17,000

Total
 
$
27,208

 
$
57,873

 
$
14,796

 
$
2,963

 
$
102,840

 
$
316,000

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $11.8 million for property and equipment during the three months ended March 31, 2012.
During the three months ended March 31, 2012 and 2011, we received (paid) net derivative settlements totaling $2.3 million and $(5.3) million, respectively. Primarily as a result of our capital investments and derivative settlements, cash flows used in investing activities were $94.3 million and $93.6 million during the three months ended March 31, 2012 and 2011, respectively.
Cash flows provided by financing activities were $41.3 million during the first quarter of 2012, primarily due to borrowings of $40.0 million under our senior secured revolving credit facility. Cash flows provided by financing activities were $51.1 million during the first quarter of 2011. 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.


37


Senior Notes
On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 7.625% Senior Notes and the repurchase or redemption of our 8.875% Senior Notes due 2017, we capitalized approximately $8.5 million of issuance costs related to underwriting and other fees and we expensed approximately $21.7 million of refinancing costs in May 2012.
The Senior Notes, which, as of March 31, 2012, included our 8.875% Senior Notes due 2017, our 9.875% Senior Notes due 2020, and our 8.25% Senior Notes due 2021, 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 indentures.
On or after the date that is five years before the maturity date of a series of our Senior Notes, we may redeem some or all of such Senior Notes at any time at redemption prices specified in the applicable indenture, plus accrued and unpaid interest to the date of redemption.
Prior to the date that is five years before the maturity date of a series of our Senior Notes, such Senior Notes may be redeemed in whole or in part at a redemption price equal to the principal amount of such notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the applicable indenture.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:
incur 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 indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

38


Senior secured revolving credit facility
In April 2010, we entered into our senior secured revolving credit facility, which is collateralized by our oil and natural gas properties and 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.
The Eighth Amendment to our senior secured revolving credit facility, effective April 30, 2012, amended our Asset Sale Covenant to permit the sale of certain oil and natural gas properties located in southern Oklahoma and increased our permitted ratio of Consolidated Net Debt to Consolidated EBITDAX from 4.25 to 4.50. It also reaffirmed the borrowing base at $375.0 million through November 1, 2012. As of May 11, 2012, the balance outstanding under our senior secured revolving credit facility is $50.0 million.
Borrowings under our senior secured revolving credit facility are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans. As of March 31, 2012, the balance outstanding under our senior secured revolving credit facility was $40.0 million, all of which was a Eurodollar loan.
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. 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, 2012 and December 31, 2011, our current ratio as computed using GAAP was 0.66 and 0.74, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.96 and 3.56, 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,
2012
 
December 31,
2011
Current assets per GAAP
 
$
117,636

 
$
124,123

Plus—Availability under senior secured revolving credit facility
 
332,080

 
372,080

Less—Short-term derivative instruments
 
(10,844
)