Chaparral Energy, Inc. - FORM 10-Q - August 14, 2014

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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 June 30, 2014

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 August 14, 2014:
Class
 
Number of
shares
Class A Common Stock, $0.01 par value
 
362,519

Class B Common Stock, $0.01 par value
 
344,859

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

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
 
2




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 laws. 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, and 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 a 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 for the year ended December 31, 2013. 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 the forward-looking statements contained herein. 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:

•
Basin. A low region or natural depression in the earth’s crust where sedimentary deposits accumulate.
•
Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate, or natural gas liquids.
•
BBtu. One billion British thermal units.
•
Boe. Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.
•
Boe/d. Barrels of oil equivalent per day.
•
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.
•
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
•
CO2. Carbon dioxide.
•
Enhanced oil recovery (EOR). The use of any improved recovery method, including injection of CO2 or polymer, to remove additional oil after secondary recovery.
•
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
•
MBbls. One thousand barrels of crude oil, condensate, or natural gas liquids.
•
MBoe. One thousand barrels of crude oil equivalent.
•
Mcf. One thousand cubic feet of natural gas.
•
MMBbls. One million barrels of crude oil, condensate, or natural gas liquids.
•
MMBoe. One million barrels of crude oil equivalent.
•
MMBtu. One million British thermal units.
•
MMcf. One million cubic feet of natural gas.
•
Natural gas liquids (NGLs). Those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include propane, butane, isobutane, pentane, hexane and natural gasoline.
•
Net acres. The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 50% interest in 100 acres owns net 50 acres.
•
NYMEX. The New York Mercantile Exchange.
•
Play. A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.
•
Proved reserves. The quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
•
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
•
PV-10 value. When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.
•
SEC. The Securities and Exchange Commission.
•
Secondary recovery. The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

5

•
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
•
Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.


6

PART I — FINANCIAL INFORMATION

ITEM 1.
FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries
Consolidated balance sheets


 
 
June 30,
2014
 
December 31,
2013
(dollars in thousands, except share data)
 
(unaudited)
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
35,450

 
$
48,595

Accounts receivable, net
 
113,365

 
96,515

Inventories, net
 
21,429

 
16,137

Prepaid expenses
 
2,591

 
3,998

Derivative instruments
 
—

 
2,152

Deferred income taxes
 
26,467

 
9,260

Total current assets
 
199,302

 
176,657

Property and equipment—at cost, net
 
68,927

 
69,426

Oil and natural gas properties, using the full cost method:
 
 
 
 
Proved
 
3,413,684

 
3,258,661

Unevaluated (excluded from the amortization base)
 
344,541

 
321,477

Accumulated depreciation, depletion, amortization and impairment
 
(1,582,078
)
 
(1,470,090
)
Total oil and natural gas properties
 
2,176,147

 
2,110,048

Derivative instruments
 
303

 
6,403

Other assets
 
33,031

 
35,348

 
 
$
2,477,710

 
$
2,397,882

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

7

Chaparral Energy, Inc. and subsidiaries
Consolidated balance sheets—continued
 
 
June 30,
2014
 
December 31,
2013
(dollars in thousands, except share data)
 
(unaudited)
 
Liabilities and stockholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable and accrued liabilities
 
$
168,968

 
$
134,811

Accrued payroll and benefits payable
 
21,382

 
24,246

Accrued interest payable
 
24,064

 
24,225

Revenue distribution payable
 
36,370

 
25,138

Current maturities of long-term debt and capital leases
 
5,623

 
5,334

Derivative instruments
 
46,818

 
8,234

Total current liabilities
 
303,225

 
221,988

Long-term debt and capital leases, less current maturities
 
1,532,544

 
1,557,528

Derivative instruments
 
17,157

 
—

Stock-based compensation
 
4,030

 
4,942

Asset retirement obligations and other
 
46,199

 
53,305

Deferred income taxes
 
77,357

 
62,855

Commitments and contingencies (Note 11)
 

 

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 365,702 and 70,117 shares issued and outstanding as of June 30, 2014 and December 31, 2013, respectively
 
4

 
—

Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859 and 357,882 shares issued and outstanding as of June 30, 2014 and December 31, 2013, respectively.
 
3

 
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 nil and 279,999 shares issued and outstanding as of June 30, 2014 and December 31, 2013, respectively
 
—

 
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 and 2 and 3 shares issued and outstanding as of June 30, 2014 and December 31, 2013, respectively
 
—

 
—

Additional paid in capital
 
428,339

 
424,377

Retained earnings
 
68,845

 
72,873

 
 
497,198

 
497,264

 
 
$
2,477,710

 
$
2,397,882


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


8

Chaparral Energy, Inc. and subsidiaries
Consolidated statements of operations
 
 
 
Three months ended
 
Six months ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
(unaudited)
 
 
Revenues:
 
 
 
 
 
 
 
 
Commodity sales
 
$
192,976

 
$
144,353

 
$
366,315

 
$
271,865

Gain from oil hedging activities
 
—

 
9,509

 
—

 
19,512

Total revenues
 
192,976

 
153,862

 
366,315

 
291,377

Costs and expenses:
 
 
 
 
 
 
 
 
Lease operating
 
36,564

 
32,949

 
71,585

 
66,926

Production taxes
 
8,159

 
8,588

 
14,802

 
16,468

Depreciation, depletion and amortization
 
63,354

 
47,941

 
119,104

 
91,857

General and administrative
 
14,992

 
11,553

 
28,379

 
25,561

Total costs and expenses
 
123,069

 
101,031

 
233,870

 
200,812

Operating income
 
69,907

 
52,831


132,445


90,565

Non-operating (expense) income:
 
 
 
 
 
 
 
 
Interest expense
 
(26,203
)
 
(24,200
)
 
(52,662
)
 
(48,491
)
Non-hedge derivative (losses) gains
 
(57,996
)
 
32,892

 
(87,195
)
 
17,346

Other income, net
 
805

 
187

 
965

 
413

Net non-operating (expense) income
 
(83,394
)
 
8,879

 
(138,892
)
 
(30,732
)
(Loss) income before income taxes
 
(13,487
)
 
61,710

 
(6,447
)
 
59,833

Income tax (benefit) expense
 
(5,054
)
 
22,810

 
(2,419
)
 
22,123

Net (loss) income
 
$
(8,433
)
 
$
38,900

 
$
(4,028
)
 
$
37,710

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


9

Chaparral Energy, Inc. and subsidiaries
Consolidated statements of comprehensive income (loss)
 
 
 
Three months ended
 
Six months ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
(unaudited)
 
 
Net (loss) income
 
$
(8,433
)
 
$
38,900

 
$
(4,028
)
 
$
37,710

Other comprehensive loss
 
 
 
 
 
 
 
 
Reclassification adjustment for hedge gains included in gain from oil hedging activities in the consolidated statements of operations
 
—

 
(9,509
)
 
—

 
(19,512
)
Income tax benefit related to other comprehensive loss
 
—

 
3,642

 
—

 
7,460

Other comprehensive loss, net of tax
 
—

 
(5,867
)
 
—

 
(12,052
)
Comprehensive (loss) income
 
$
(8,433
)
 
$
33,033

 
$
(4,028
)
 
$
25,658

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



10

Chaparral Energy, Inc. and subsidiaries
Consolidated statements of cash flows
 
 
Six months ended
 
 
June 30,
 
 
2014
 
2013
(in thousands)
 
(unaudited)
Cash flows from operating activities
 
 
 
 
Net (loss) income
 
$
(4,028
)
 
$
37,710

Adjustments to reconcile net (loss) income to net cash provided by operating activities
 
 
 
 
Depreciation, depletion & amortization
 
119,104

 
91,857

Deferred income taxes
 
(2,705
)
 
22,007

Gain on hedge reclassification adjustments
 
—

 
(19,512
)
Non-hedge derivative losses (gains)
 
87,195

 
(17,346
)
Gain on sale of assets
 
(811
)
 
(224
)
Other
 
1,670

 
2,432

Change in assets and liabilities
 
 
 
 
Accounts receivable
 
(13,319
)
 
(15,245
)
Inventories
 
(4,908
)
 
(1,568
)
Prepaid expenses and other assets
 
1,463

 
1,435

Accounts payable and accrued liabilities
 
(14,560
)
 
(5,912
)
Revenue distribution payable
 
11,233

 
4,023

Stock-based compensation
 
2,183

 
342

Net cash provided by operating activities
 
182,517

 
99,999

Cash flows from investing activities
 
 
 
 
Expenditures for property, plant, and equipment and oil and natural gas properties
 
(322,310
)
 
(248,206
)
Proceeds from asset dispositions
 
173,175

 
68,133

Settlement of non-hedge derivative instruments
 
(21,982
)
 
15,918

Other
 
—

 
(664
)
Net cash used in investing activities
 
(171,117
)
 
(164,819
)
Cash flows from financing activities
 
 
 
 
Proceeds from long-term debt
 
111,282

 
100,650

Repayment of long-term debt
 
(134,681
)
 
(33,623
)
Principal payments under capital lease obligations
 
(1,146
)
 
—

Net cash (used in) provided by financing activities
 
(24,545
)
 
67,027

Net (decrease) increase in cash and cash equivalents
 
(13,145
)
 
2,207

Cash and cash equivalents at beginning of period
 
48,595

 
29,819

Cash and cash equivalents at end of period
 
$
35,450

 
$
32,026

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

11
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited)
(dollars in thousands, unless otherwise noted)


Note 1: Nature of operations and summary of significant accounting policies
Nature of operations
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 and Texas.
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, 2013.
The financial information as of June 30, 2014, and for the three and six months ended June 30, 2014 and 2013, is unaudited. The financial information as of December 31, 2013 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2013. 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 and six months ended June 30, 2014 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2014.
Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations.
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 June 30, 2014, cash with a recorded balance totaling $31,539 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 establish our allowance for doubtful accounts 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.

12
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


We write off accounts receivable when they are determined to be uncollectible. Bad debt expense was $39 and $(514) for the three and six months ended June 30, 2014 and $268 and $519 for the three and six months ended June 30, 2013, respectively. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery. During the first quarter of 2014 we recovered previously written off amounts, which resulted in a reduction of bad debt expense for the six months ended June 30, 2014. Accounts receivable consisted of the following at June 30, 2014 and December 31, 2013: 
 
June 30,
2014
 
December 31,
2013
Joint interests
$
32,971

 
$
31,335

Accrued commodity sales
77,334

 
60,768

Derivative settlements
—

 
4,616

Production tax credit
2,031

 
694

Other
1,354

 
698

Allowance for doubtful accounts
(325
)
 
(1,596
)
 
$
113,365

 
$
96,515

Inventories
Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product 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. Inventories are shown net of a provision for obsolescence, commensurate with known or estimated exposure, which is reflected in the valuation allowance disclosed below. Inventories at June 30, 2014 and December 31, 2013 consisted of the following: 
 
 
June 30,
2014
 
December 31,
2013
Equipment inventory
 
$
19,457

 
$
13,657

Commodities
 
2,751

 
3,186

Inventory valuation allowance
 
(779
)
 
(706
)
 
 
$
21,429

 
$
16,137

Oil and natural gas properties
Capitalized Costs. We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits and other internal costs directly attributable to these activities.
The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work-in-progress costs are included in unevaluated oil and natural gas properties and as of June 30, 2014, include $227,383 of capital costs incurred for undeveloped acreage, $95,704 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $21,454 for wells and facilities in progress pending determination. As of December 31, 2013, work-in-progress costs included capital costs incurred of $196,227 for undeveloped acreage, $115,828 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $9,422 for wells and facilities in progress pending determination.

13
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.
Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.
Our estimates of oil and natural gas reserves as of June 30, 2014 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the Securities Exchange Commission (“SEC”). The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of June 30, 2014, and no ceiling test impairment was recorded.
A decline in oil and natural gas prices subsequent to June 30, 2014 could result in ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.
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 are 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 awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis 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. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards 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.
The costs associated with our stock-based compensation programs 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.

14
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


Recently adopted accounting pronouncements
In July 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance, which was effective and adopted by us in the first quarter of 2014, did not have a material impact on our financial statements and results of operations.
Recently issued accounting pronouncements
In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.
Note 2: Supplemental disclosures to the consolidated statements of cash flows
Supplemental disclosures to the consolidated statements of cash flows are presented below:
 
 
Six months ended June 30,
 
 
2014
 
2013
Net cash provided by operating activities included:
 
 
 
 
Cash payments for interest
 
$
56,419

 
$
53,199

Interest capitalized
 
(6,290
)
 
(7,549
)
Cash payments for interest, net of amounts capitalized
 
$
50,129

 
$
45,650

Cash payments for income taxes
 
$
591

 
$
240

Non-cash investing activities included:
 
 
 
 
Asset retirement obligation additions
 
$
2,966

 
$
262

Oil and natural gas properties acquired through increase in accounts payable and accrued liabilities
 
$
20,768

 
$
19,613


Note 3: Acquisitions and divestitures
During the second quarter of 2014, we closed on the sales of two of the five property packages that comprise our plan to divest our assets in Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $25,150 and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $125,000.
During the third quarter of 2014, we closed on the sales of two additional property packages. Our Ark-La-Tex and Central Basin Platform property packages, both of which were sold to RAM Energy, LLC (“RAM”), closed in July 2014 for cash proceeds of $48,495 and $45,854, respectively. The cash proceeds from the four sales above are subject to post-closing adjustments. As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.


15
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


In addition to the packages discussed above, we had various other divestitures during the six months ended June 30, 2014, for cash proceeds of $20,022. These divestitures included properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.
In December 2013, we acquired certain oil and natural gas properties in the Panhandle Marmaton play from Cabot Oil & Gas Corporation (the “Cabot Acquisition”). The acquisition qualified as a business combination for accounting purposes and, as such, we estimated the fair value of the acquired properties as of the acquisition date and allocated the purchase price to the assets and liabilities acquired based on their fair values. During the second quarter of 2014, we finalized the post-closing adjustments related to the Cabot Acquisition with no material changes to the purchase price allocation.
Note 4: Long-term debt
As of the dates indicated, long-term debt consisted of the following: 
 
 
June 30, 2014
 
December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,161 and $5,444, respectively
 
$
294,839

 
$
294,556

8.25% Senior Notes due 2021
 
400,000

 
400,000

7.625% Senior Notes due 2022, including premium of $5,286 and $5,719, respectively
 
555,286

 
555,719

Senior secured revolving credit facility
 
249,000

 
272,000

Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due August 2021 through December 2028; collateralized by real property
 
10,957

 
11,202

Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 6.44%, due August 2014 through February 2018 collateralized by automobiles, machinery and equipment
 
5,081

 
5,235

Capital lease obligations
 
23,004

 
24,150

 
 
1,538,167

 
1,562,862

Less current maturities
 
5,623

 
5,334

 
 
$
1,532,544

 
$
1,557,528

Senior Notes
The senior notes, which, as of June 30, 2014, include our 9.875% senior notes due 2020, our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) are our senior unsecured obligations, rank equally in right of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt.
Senior secured revolving credit facility
In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. During the six months ended June 30, 2014, we had borrowings of $110,000 and repayments of $133,000 on our senior secured revolving credit facility. The net repayment was funded by proceeds received from our Delaware Basin and Ft. Worth Basin property divestitures.
Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semiannually 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. On April 22, 2014, our borrowing base was reaffirmed at $600,000.

16
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


On May 19, 2014, we entered into a Limited Consent and Fourteenth Amendment to our senior secured revolving credit facility which provides for a series of automatic reductions in the borrowing base under the credit facility as the divestitures of our oil and natural gas properties are completed (see Note 3—Acquisitions and divestitures). As a result of two divestitures that closed during the second quarter, our borrowing base was reduced from $600,000 to $532,000 effective May 23, 2014. Subsequent divestitures during the third quarter further reduced our borrowing base from $532,000 to $484,500 effective July 18, 2014.
The Limited Consent and Fourteenth Amendment also imposed an additional reduction in availability under our senior secured revolving credit facility equal to 10% of the borrowing base to compensate for the over-hedging of our production in excess of the limits specified by covenants under the senior secured revolving credit facility. Outstanding hedges have temporarily exceeded the limits allowed under the senior secured revolving credit facility because of our recent asset divestitures. Our lenders have waived any covenant violations resulting from our temporary hedging noncompliance until August 15, 2014. On August 14, 2014 we entered into a Letter Agreement with our lenders to extend the waiver of temporary hedging noncompliance until November 1, 2014, the date of our next scheduled borrowing base redetermination. In conjunction with this extension, the 10% reduction in availability discussed above was replaced with a requirement to maintain a level of availability on our senior secured credit facility that is calculated based on our overhedged position. The requirement specifies that in the event the market value of our derivative contracts for a given commodity is a liability, the availability on our senior secured revolving credit facility must be no less than two times the liability on the overhedged production. As of August 14, 2014, we were overhedged on our projected natural gas production; however, since the market value of our natural gas derivative contracts, based on prior day settlement prices, was an asset on that date, there was no restriction on the availability under our senior secured credit facility.
We believe we were in compliance with all covenants under our senior secured revolving credit facility as of June 30, 2014.
Capital Leases
During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and gas full cost pool. The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are approximately $3,181 annually.
Note 5: 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 various types of derivative instruments, including commodity price swaps, enhanced price swaps, costless collars, put options, 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 (purchased put) and ceiling price (sold 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 sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold 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 sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold 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 utilizing the value associated with the sale of a put option.

17
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


Put options may be purchased from the counterparty by paying a cash premium at the time the put options are purchased or paying later when the put options settle. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.
We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will receive the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection.
We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.
We enter into crude oil derivative contracts for a portion of our natural gas liquids production. The following table summarizes our crude oil derivatives outstanding as of June 30, 2014: 
 
 
 
 
Weighted average fixed price per Bbl
Period and type of contract
 
Volume
MBbls
 
Swaps
 
Sold puts
 
Purchased puts
 
Sold calls
2014
 
 
 
 
 
 
 
 
 
 
Swaps
 
369

 
$
91.89

 
$
—

 
$
—

 
$
—

Three-way collars
 
1,200

 
$
—

 
$
75.50

 
$
93.25

 
$
101.94

Enhanced swaps
 
420

 
$
97.89

 
$
80.00

 
$
—

 
$
—

Put spread enhanced swaps
 
1,415

 
$
93.93

 
$
80.00

 
$
60.00

 
$
—

Purchased puts (1)
 
420

 
$
—

 
$
—

 
$
60.00

 
$
—

2015
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
6,058

 
$
92.92

 
$
80.00

 
$
—

 
$
—

Purchased puts (1)
 
5,548

 
$
—

 
$
—

 
$
60.00

 
$
—

2016
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
2,760

 
$
92.25

 
$
80.00

 
$
—

 
$
—

___________
(1)
Puts covering 840 Mbbls in 2014 were purchased during the second quarter of 2013 for $664. The 2015 puts were purchased during the second quarter of 2014 for $1,220.


18
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


The following tables summarize our natural gas derivative instruments outstanding as of June 30, 2014: 
Period and type of contract
 
Volume
BBtu
 
Weighted
average
fixed price
per MMBtu
2014
 
 
 
 
Natural gas swaps
 
10,280

 
$
4.05

Natural gas basis protection swaps
 
10,440

 
$
0.24

2015
 
 
 
 
Natural gas swaps
 
22,170

 
$
4.20

Natural gas basis protection swaps
 
2,400

 
$
0.18

2016
 
 
 
 
Natural gas swaps
 
7,800

 
$
4.33

Effect of derivative instruments on the consolidated balance sheets
All derivative financial instruments are recorded on the balance sheet at fair value. See Note 6—Fair value measurements 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 June 30, 2014
 
As of December 31, 2013
 
Assets
 
Liabilities
 
Net value
 
Assets
 
Liabilities
 
Net value
Natural gas swaps
$
1,129

 
$
(5,086
)
 
$
(3,957
)
 
$
1,457

 
$
(3,706
)
 
$
(2,249
)
Oil swaps
—

 
(4,232
)
 
(4,232
)
 
112

 
(2,807
)
 
(2,695
)
Oil collars
75

 
(4,067
)
 
(3,992
)
 
2,776

 
(4
)
 
2,772

Oil enhanced swaps
—

 
(51,299
)
 
(51,299
)
 
6,988

 
(6,212
)
 
776

Oil purchased puts
339

 
—

 
339

 
74

 
—

 
74

Natural gas basis differential swaps
21

 
(552
)
 
(531
)
 
1,706

 
(63
)
 
1,643

Total derivative instruments
1,564

 
(65,236
)
 
(63,672
)
 
13,113

 
(12,792
)
 
321

Less:
 
 
 
 
 
 
 
 
 
 
 
Netting adjustments (1)
1,261

 
(1,261
)
 
—

 
4,558

 
(4,558
)
 
—

Current portion asset (liability)
—

 
(46,818
)
 
(46,818
)
 
2,152

 
(8,234
)
 
(6,082
)
 
$
303

 
$
(17,157
)
 
$
(16,854
)
 
$
6,403

 
$
—

 
$
6,403

___________
(1)
Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet.
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 (loss) (“AOCI”). As of December 31, 2013, there are no longer any deferred gains in AOCI as all the previously deferred gains (losses) have been reclassified into earnings upon the sale of the hedged production.
Derivative settlements outstanding at June 30, 2014 and December 31, 2013 were as follows: 
 
June 30,
2014
 
December 31,
2013
Derivative settlements receivable included in accounts receivable
$
—

 
$
4,616

Derivative settlements payable included in accounts payable and accrued liabilities
$
8,674

 
$
377


19
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


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 from oil hedging activities, which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains on discontinued oil hedges from AOCI into net income upon settlement of the contracts.
Non-hedge derivative (losses) gains in the consolidated statements of operations are comprised of the following: 
 
 
Three months ended
 
Six months ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
Change in fair value of commodity price swaps
 
$
1,948

 
$
15,044

 
$
(3,245
)
 
$
(4,320
)
Change in fair value of collars
 
(3,901
)
 
1,547

 
(6,764
)
 
(6,738
)
Change in fair value of enhanced swaps and put options
 
(42,337
)
 
8,765

 
(52,698
)
 
10,796

Change in fair value of natural gas basis differential contracts
 
(313
)
 
1,514

 
(2,174
)
 
1,690

Amortization of put premium
 
(166
)
 
—

 
(332
)
 
—

(Payments on) receipts from settlement of commodity price swaps
 
(5,773
)
 
312

 
(11,623
)
 
4,837

(Payments on) receipts from settlement of collars
 
(1,220
)
 
5,825

 
(1,261
)
 
11,556

(Payments on) receipts from settlement enhanced swaps
 
(7,001
)
 
—

 
(8,993
)
 
—

Receipts from (payments on) settlement of natural gas basis differential contracts
 
767

 
(115
)
 
(105
)
 
(475
)
 
 
$
(57,996
)
 
$
32,892

 
$
(87,195
)
 
$
17,346


Note 6: 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.

20
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


Recurring fair value measurements
Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 5—Derivative instruments). We have no Level 1 assets or liabilities as of June 30, 2014 or December 31, 2013. Our derivative contracts classified as Level 2 as of June 30, 2014 and December 31, 2013 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 June 30, 2014 and December 31, 2013, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, and purchased puts. 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 comparable maturities to our derivative contracts as the measure of our counterparties’ nonperformance risk. As of June 30, 2014 and December 31, 2013, the rate reflecting our nonperformance risk was 1.75% and 1.75%, respectively. The weighted average rate reflecting our counterparties’ nonperformance risk was approximately 0.30% and 0.31% as of June 30, 2014 and December 31, 2013, respectively.
The fair value hierarchy for our financial assets and liabilities is shown by the following table: 
 
As of June 30, 2014
 
As of December 31, 2013
 
Derivative
assets
 
Derivative
liabilities
 
Net assets
(liabilities)
 
Derivative
assets
 
Derivative
liabilities
 
Net assets
(liabilities)
Significant other observable inputs (Level 2)
$
1,150

 
$
(9,870
)
 
$
(8,720
)
 
$
3,275

 
$
(6,576
)
 
$
(3,301
)
Significant unobservable inputs (Level 3)
414

 
(55,366
)
 
(54,952
)
 
9,838

 
(6,216
)
 
3,622

Netting adjustments (1)
(1,261
)
 
1,261

 
—

 
(4,558
)
 
4,558

 
—

 
$
303

 
$
(63,975
)
 
$
(63,672
)
 
$
8,555

 
$
(8,234
)
 
$
321

___________
(1)
Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification.
Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the six months ended June 30, 2014 and 2013 were: 
 
 
Six months ended June 30,
Net derivative assets (liabilities)
 
2014
 
2013
Beginning balance
 
$
3,622

 
$
26,231

Realized and unrealized losses included in non-hedge derivative losses
 
(70,048
)
 
15,614

Purchases
 
1,220

 
664

Settlements paid (received)
 
10,254

 
(11,556
)
Ending balance
 
$
(54,952
)
 
$
30,953

(Losses) gains relating to instruments still held at the reporting date included in non-hedge derivative (losses) gains for the period
 
$
(63,617
)
 
$
18,651


21
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


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 six months of 2014 and 2013 were escalated using an annual inflation rate of 2.95% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 5.90% and 7.10%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. During the six months ended June 30, 2014 and 2013, additions to our asset retirement obligations were $2,966 and $262, respectively. See Note 7—Asset retirement obligations for additional information regarding our asset retirement obligations.
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 June 30, 2014 and December 31, 2013 were as follows: 
 
 
June 30, 2014
 
December 31, 2013
Level 2
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
9.875% Senior Notes due 2020
 
$
294,839

 
$
339,750

 
$
294,556

 
$
340,140

8.25% Senior Notes due 2021
 
400,000

 
442,000

 
400,000

 
437,000

7.625% Senior Notes due 2022
 
555,286

 
598,098

 
555,719

 
583,275

Senior secured revolving credit facility
 
249,000

 
249,000

 
272,000

 
272,000

Other secured long-term debt
 
16,038

 
16,038

 
16,437

 
16,437

 
 
$
1,515,163

 
$
1,644,886

 
$
1,538,712

 
$
1,648,852

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.
Counterparty credit risk
Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our senior secured revolving credit facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender, or an affiliate of a lender, under our senior secured revolving credit facility can be offset against amounts owed to such counterparty lender under our senior secured revolving credit facility. As of June 30, 2014, the counterparties to our open derivative contracts consisted of eleven financial institutions, of which ten were subject to our rights of offset under our senior secured revolving credit facility.

22
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.
 
 
Offset in the consolidated balance sheets
 
Gross amounts not offset in the consolidated balance sheets
 
 
Gross assets (liabilities)
 
Offsetting assets (liabilities)
 
Net assets (liabilities)
 
Derivatives(1)
 
Amounts outstanding under senior secured revolving credit facility
 
Net amount
As of June 30, 2014
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
1,564

 
$
(1,261
)
 
$
303

 
$
(303
)
 
$
—

 
$
—

Derivative liabilities
 
(65,236
)
 
1,261

 
(63,975
)
 
303

 
—

 
(63,672
)
 
 
$
(63,672
)
 
$
—

 
$
(63,672
)
 
$
—

 
$
—

 
$
(63,672
)
As of December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
13,113

 
$
(4,558
)
 
$
8,555

 
$
(3,484
)
 
$
(4,211
)
 
$
860

Derivative liabilities
 
(12,792
)
 
4,558

 
(8,234
)
 
3,484

 
—

 
(4,750
)
 
 
$
321

 
$
—

 
$
321

 
$
—

 
$
(4,211
)
 
$
(3,890
)
___________
(1)
Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.
We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. 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 subject to acceleration in the event of default was $65,236 at June 30, 2014.
Note 7: Asset retirement obligations
The following table provides a summary of our asset retirement obligation activity during the six months ended June 30, 2014 and 2013. 
 
 
Six months ended June 30,
 
 
2014
 
2013
Beginning balance
 
$
55,179

 
$
49,214

Liabilities incurred in current period
 
2,966

 
262

Liabilities settled and disposed in current period
 
(7,823
)
 
(2,867
)
Accretion expense
 
2,063

 
2,008

Ending balance
 
52,385

 
48,617

Less current portion included in accounts payable and accrued liabilities
 
6,792

 
2,900

 
 
$
45,593

 
$
45,717

See Note 6—Fair value measurements for additional information regarding fair value assumptions associated with our asset retirement obligations.

23
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


Note 8: 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”). Under the Phantom Plan, awards vest at the end of five years, 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 us 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, we do not expect to make any further awards under the Phantom Plan.
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 in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.
A summary of our phantom stock and RSU activity during the six months ended June 30, 2014 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
 
Vest
date
fair
value
 
($ per share)
 
 
 
 
 
($ per share)
 
 
 
 
Unvested and outstanding at January 1, 2014
$
17.01

 
53,162

 
 
 
$
13.53

 
325,297

 
 
Granted
—

 
—

 
 
 
8.11

 
475,878

 
 
Vested
10.91

 
(17,430
)
 
$
141

 
14.52

 
(99,754
)
 
$
809

Forfeited
19.16

 
(4,588
)
 
 
 
10.01

 
(58,197
)
 
 
Unvested and outstanding at June 30, 2014
$
20.10

 
31,144

 
 
 
$
9.68

 
643,224

 
 
Based on an estimated fair value of $15.26 per phantom share and RSU as of June 30, 2014, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $10,291.
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.
The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested 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. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

24
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


A summary of our restricted stock activity during the six months ended June 30, 2014 is presented below:
 
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, 2014
$
634.67

 
19,246

 
 
 
$
307.45

 
46,701

Granted
818.50

 
1,615

 
 
 
204.90

 
2,998

Vested
649.20

 
(4,414
)
 
$
3,613

 
—

 
—

Forfeited
641.10

 
(177
)
 
 
 
307.00

 
(484
)
Unvested and total outstanding at June 30, 2014
$
648.91

 
16,270

 
 
 
$
301.20

 
49,215

During the six months ended June 30, 2014 and 2013, respectively, we repurchased and canceled 1,390 and 769 vested shares, primarily for tax withholding, and we expect to repurchase approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $818.50 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $13,317 as of June 30, 2014.
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
 
Six months ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
Stock-based compensation cost
$
4,186

 
$
682

 
$
6,717

 
$
2,575

Less: stock-based compensation cost capitalized
(1,484
)
 
(356
)
 
(2,446
)
 
(935
)
Stock-based compensation expense
$
2,702

 
$
326

 
$
4,271

 
$
1,640

Payments for stock-based compensation were $1,214 and $1,229 during the second quarters of 2014 and 2013, respectively, and were $2,088 and $1,298 during the six months ended June 30, 2014 and 2013, respectively. As of June 30, 2014 and December 31, 2013, accrued payroll and benefits payable included $6,659 and $5,080, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $21,201 is expected to be recognized over a weighted average period of 2.5 years.

25
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


Note 9: Common stock
The following is a summary of the changes in our common shares outstanding during the six months ended June 30, 2014: 
 
Common Stock
 
Class A
 
Class B
 
Class C
 
Class D
 
Class E
 
Class F
 
Class G
 
Total
Shares outstanding at January 1, 2014
70,117

 
357,882

 
209,882

 
279,999

 
504,276

 
1

 
3

 
1,422,160

Stock transfers (1)
293,023

 
(13,023
)
 
—

 
(279,999
)
 
—

 
—

 
(1
)
 
—

Restricted stock issuances
4,613

 
—

 
—

 
—

 
—

 
—

 
—

 
4,613

Restricted stock repurchased
(1,390
)
 
—

 
—

 
—

 
—

 
—

 
—

 
(1,390
)
Restricted stock forfeitures
(661
)
 
—

 
—

 
—

 
—

 
—

 
—

 
(661
)
Shares outstanding at June 30, 2014
365,702

 
344,859

 
209,882

 
—

 
504,276

 
1

 
2

 
1,424,722

_______________
(1)
In this transaction, Healthcare of Ontario Pension Plan Trust Fund (“HOOPP”) purchased 280,000 shares of Class A common stock converted from Class D and Class G common stock held by CHK Energy Holdings, Inc. (“CHK Energy Holdings”) effective January 13, 2014. An additional 15,078 shares of Class A common stock was purchased by HOOPP from various other stockholders of which 13,023 shares were converted from Class B common stock.
Note 10: Related party transactions
CHK Energy Holdings, an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), previously owned 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
 
Six months ended
 
June 30, 2013
 
June 30, 2013
Revenues
$
1,460

 
$
2,480

Joint interest billings
$
(809
)
 
$
(1,312
)
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
 
Six months ended
 
June 30, 2013
 
June 30, 2013
Revenues
$
(956
)
 
$
(1,879
)
Joint interest billings
$
3,618

 
$
7,885

Amounts receivable from and payable to Chesapeake at December 31, 2013 were as follows: 
 
 
December 31, 2013
Amounts receivable from Chesapeake
 
$
466

Amounts payable to Chesapeake
 
$
64

On January 13, 2014, CHK Energy Holdings sold all of its equity interest in us to Healthcare of Ontario Pension Plan Trust Fund. The sale by CHK Energy Holdings was in compliance with terms and conditions of the Stockholders Agreement implemented on April 12, 2010.

26
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


Note 11: 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 $920 and $920 as of June 30, 2014 and December 31, 2013, respectively. 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 six months ended June 30, 2014 or 2013.
Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.
On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us in the United States District Court for the Western District of Oklahoma, 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 liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases that had issues similar to this case. The Tenth Circuit issued its opinions in those unrelated cases on July 9, 2013 and mandates were issued July 31, 2013. On or about October 1, 2013, the Court lifted the stay and entered a new scheduling order. The parties are conducting additional discovery and Plaintiff’s Motion for Class Certification is due February 15, 2015. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.
Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.
On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us in the District Court of Mayes County, Oklahoma, alleging claims on behalf of herself and all non-governmental Oklahoma citizens who are royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Petition was not served until July 2, 2013. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging entitlement to actual damages in an unspecified amount. The Plaintiff also requests allowable interest, punitive damages, injunctive relief, an accounting, disgorgement damages, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.
Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C.
On August 11, 2014, Martha Donelson and John Friend (the “Plaintiffs”), filed a complaint against us in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of themselves and all similarly situated Osage County land owners and surface lessees. The Plaintiffs assert class claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring our oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. The complaint has not yet been served on us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.
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.

27
Chaparral Energy, Inc. and subsidiaries
Condensed notes to consolidated financial statements (unaudited) – continued
(dollars in thousands, unless otherwise noted)


We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. In June 2014, we entered into two non-cancelable operating leases for CO2 recycle compressors at our EOR facilities. As of June 30, 2014, total minimum payments over the remaining life of the leases, which expire in 2021, were $6,711. The remaining operating leases primarily relate to office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to contracts for the purchase of CO2, drilling rig services, pipe and equipment. Other than the two new operating leases and net debt repayments during the six months ended June 30, 2014, there were no material changes to our contractual commitments since December 31, 2013.

28


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
Founded in 1988, we are an independent oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma and are one of the largest oil producers in the state. In recent years, we have capitalized on our sustained success in our Mid-Continent area, expanding our holdings to become a leading player in both the liquids-rich Northern Oklahoma Mississippian and the oil-rich Panhandle Marmaton plays. In addition, we have a leadership position in CO2 EOR and are now the third largest CO2 EOR operator in the United States based on the number of active projects. This position is underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state.
Beginning in 2011, we have increased our focus on acquisition of leasehold acreage and exploration in resource plays with repeatable drilling opportunities. Our focus is concentrated in the Mid-Continent region, with most of our capital dollars being spent in the Panhandle Marmaton, Mississippian and Woodford Shale plays. By concentrating in these core areas, we are developing a significant resource base to achieve production and reserve growth.
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, 2013 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 19%, 14% and 11% 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.

29

During the second quarter of 2014, production increased 15.3% to 2,859 MBoe compared to production of 2,479 MBoe during the second quarter of 2013, primarily due to our drilling activity. This increase in production, combined with a 15.9% increase in the average sales price before hedging, resulted in a 33.7% increase in revenue from commodity sales in the second quarter of 2014 compared to the same period in 2013. Additionally, we had a non-hedge derivative loss of $58.0 million in the second quarter of 2014 compared to $32.9 million of non-hedge derivative gains during the same period last year. The loss was due primarily to the increase in the forward price curve during the second quarter of 2014. As a result of these and other factors, we reported a net loss of $8.4 million during the second quarter of 2014 compared to net income of $38.9 million for the comparable period in 2013.
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:
•
Our oil and natural gas property capital expenditure budget for 2014 is set at $660.0 million. Our capital expenditures during the six months ended June 30, 2014 were $347.6 million, consisting primarily of $199.1 million in drilling and completion expenditures in our E&P Areas, $91.3 million for our EOR Project Areas (excluding acquisitions) and $43.7 million for the acquisition of oil and natural gas properties and leasehold.
•
We completed the sale of two separate divestiture packages of non-core properties during the second quarter of 2014 for approximately $150.2 million in cash, subject to post-closing adjustments. In July 2014, we completed the sale of two additional divestiture packages of non-core properties for approximately $94.3 million in cash, subject to post-closing adjustments. The properties included in these four sales accounted for approximately 11% and 16% of our total production during the six months ended June 30, 2014 and 2013, respectively. In addition to the packages described above, we also had various other divestitures during the first and second quarter of 2014 for a total of approximately $20.0 million in cash.
Results of operations
Production
Production volumes by area were as follows (MBoe):
 
Three months ended
 
Percentage
change
 
Six months ended
 
Percentage
change
 
June 30,
 
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
 
E&P Areas
 
 
 
 
 
 
 
 
 
 
 
Mississippian
681

 
336

 
102.7
 %
 
1,198

 
490

 
144.5
 %
Panhandle Marmaton
207

 
48

 
331.3
 %
 
393

 
68

 
477.9
 %
Woodford Shale
136

 
19

 
615.8
 %
 
158

 
35

 
351.4
 %
Legacy Production Areas
859

 
995

 
(13.7
)%
 
1,691

 
1,993

 
(15.2
)%
Total E&P Areas
1,883

 
1,398

 
34.7
 %
 
3,440

 
2,586

 
33.0
 %
EOR Project Areas
 
 
 
 
 
 
 
 
 
 
 
Active EOR Projects
458

 
390

 
17.4
 %
 
853

 
758

 
12.5
 %
Potential EOR Projects
247

 
275

 
(10.2
)%
 
519

 
542

 
(4.2
)%
Total EOR Project Areas
705

 
665

 
6.0
 %
 
1,372

 
1,300

 
5.5
 %
Non-Core Properties
271

 
416

 
(34.9
)%
 
638

 
836

 
(23.7
)%
Total
2,859

 
2,479

 
15.3
 %
 
5,450

 
4,722

 
15.4
 %
E&P Areas
E&P Areas includes our Mississippian, Panhandle Marmaton and Woodford Shale plays. E&P Areas also includes our Legacy Production Areas which primarily include mature properties with low production decline curves. The majority of the properties in our Legacy Production Areas are located in and hold leasehold acreage for future exploration in our existing repeatable resource plays.

30

Production in our Mississippian project area increased primarily due to our drilling and development activity in our NOMP for the twelve months ended June 30, 2014. Production in our Panhandle Marmaton project area increased primarily due to our drilling and development activity for the twelve months ended June 30, 2014 and production from newly acquired fields, specifically our Cabot Acquisition in December 2013. Production in our Legacy Production Areas decreased primarily due to normal production decline during the last twelve months concentrated in our Granite Wash and Cleveland Sand plays and strategic divestitures within these areas.
EOR Project Areas
Our EOR Project Areas include both currently Active EOR Projects and Potential EOR Properties with no current EOR production or reserves at June 30, 2014. Our Active EOR Project areas include properties that have proved EOR reserves, ongoing EOR operations, or that have an approved authorization for expenditure for EOR operations. Production increases in our Active EOR Projects were primarily due to ongoing drilling and CO2 injection activities in our Farnsworth Unit and a more pronounced EOR production response in our North Burbank Unit. We realized our first EOR production response from the North Burbank Unit in the fourth quarter of 2013 with more significant response developing during the second quarter of 2014. We anticipate production growth for this unit in the remainder of 2014 as we continue to develop the field.
Non-Core Properties
As discussed in our Annual Report on Form 10-K for the year ended December 31, 2013, our Board approved selling our Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas properties. Production decreases in our Non-Core Properties were primarily due to strategic divestitures within these areas combined with the natural production decline in wells producing during the last twelve months. See “Asset divestitures and alternative capital sources” below for further discussion on our divestitures.
Revenues
Our commodity sales are derived from the sale of oil, natural gas and natural gas liquids production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
The following table presents information about our commodity sales before the effects of commodity derivative settlements: 
 
Three months ended
 
Percentage
change
 
Six months ended
 
Percentage
change
 
June 30,
 
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
 
Commodity sales (in thousands)
 
 
 
 
 
 
 
 
 
 
 
Oil
$
153,275

 
$
112,364

 
36.4
%
 
$
288,394

 
$
214,399

 
34.5
%
Natural gas
24,780

 
21,172

 
17.0
%
 
49,932

 
36,372

 
37.3
%
Natural gas liquids
14,921

 
10,817

 
37.9
%
 
27,989

 
21,094

 
32.7
%
Total commodity sales
$
192,976

 
$
144,353

 
33.7
%
 
$
366,315

 
$
271,865

 
34.7
%
Production
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
1,528

 
1,230

 
24.2
%
 
2,943

 
2,356

 
24.9
%
Natural gas (MMcf)
5,622

 
5,418

 
3.8
%
 
10,795

 
10,254

 
5.3
%
Natural gas liquids (MBbls)
394

 
346

 
13.9
%
 
708

 
657

 
7.8
%
MBoe
2,859

 
2,479

 
15.3
%
 
5,450

 
4,722

 
15.4
%
Average daily production (Boe/d)
31,418

 
27,242

 
15.3
%
 
30,110

 
26,088

 
15.4
%
Average sales prices (excluding derivative settlements)
 
 
 
 
 
 
 
 
 
 
 
Oil per Bbl
$
100.31

 
$
91.35

 
9.8
%
 
$
97.99


$
91.00

 
7.7
%
Natural gas per Mcf
$
4.41

 
$
3.91

 
12.8
%
 
$
4.63


$
3.55

 
30.4
%
NGLs per Bbl
$
37.87

 
$
31.26

 
21.1
%
 
$
39.53


$
32.11

 
23.1
%
Average sales price per Boe
$
67.50

 
$
58.23

 
15.9
%
 
$
67.21


$
57.57

 
16.7
%

31

Our total commodity sales increased significantly during the three months ended June 30, 2014 as compared to the three months ended June 30, 2013 as a result of a 16% increase in the average price per Boe combined with a 15% increase in production volumes sold. Our total commodity sales increased significantly during the six months ended June 30, 2014 as compared to the six months ended June 30, 2013 as a result of a 17% increase in the average price per Boe combined with a 15% increase in production volumes sold.
Average production volumes sold increased by 4,176 Boe per day, or 15%, to 31,418 Boe per day during the three months ended June 30, 2014 compared to 27,242 Boe per day during the three months ended June 30, 2013. The increase in average production volumes sold was primarily a result of new production from wells that were completed during the twelve months ended June 30, 2014, offsetting the decline in production in wells that were producing as of June 30, 2013. Average daily production in our Mississippian and Panhandle Marmaton project areas increased by approximately 3,791 Boe per day and approximately 1,758 Boe per day, respectively, during the second quarter of 2014 compared to the second quarter of 2013, primarily as a result of our recent well completions and production from newly acquired fields, specifically our Cabot Acquisition in December 2013. These increases were partially offset by a decrease in average production volumes sold in our Legacy Production Areas and our Non-Core Properties primarily due to strategic divestitures combined with declines in production as a result of decreased drilling activity in these areas.
Average production volumes sold increased by 4,022 Boe per day, or 15%, to 30,110 Boe per day during the six months ended June 30, 2014 compared to 26,088 Boe per day during the six months ended June 30, 2013. The increase in average production volumes sold was primarily a result of our well completions during the twelve months ended June 30, 2014, offsetting the decline in production in wells that were producing as of June 30, 2013. Average daily production in our Mississippian and Panhandle Marmaton project areas increased by approximately 3,912 Boe per day and approximately 1,796 Boe per day, respectively, during the first half of 2014 compared to the first half of 2013 primarily as a result of our recent well completions and production from newly acquired fields, specifically our Cabot Acquisition in December 2013. These increases were partially offset by a decrease in average production volumes sold in our Legacy Production Areas and our Non-Core Properties primarily due to strategic divestitures combined with declines in production as a result of decreased drilling activity in these areas.
The relative impact of changes in commodity prices and sales volumes on our oil, natural gas and natural gas liquids sales before the effects of hedging is shown in the following table: 
 
 
Three months ended June 30,
 
Six months ended June 30,
 
 
2014 vs. 2013
 
2014 vs. 2013
(in thousands)
 
Sales
change
 
Percentage
change
in sales
 
Sales
change
 
Percentage
change
in sales
Change in oil sales due to:
 
 
 
 
 
 
 
 
Prices
 
$
13,688

 
12.2
%
 
$
20,577

 
9.6
%
Production
 
27,223

 
24.2
%
 
53,418

 
24.9
%
Total change in oil sales
 
$
40,911

 
36.4
%
 
$
73,995

 
34.5
%
Change in natural gas sales due to:
 
 
 
 
 
 
 
 
Prices
 
$
2,811

 
13.2
%
 
$
11,641

 
32.0
%
Production
 
797

 
3.8
%
 
1,919

 
5.3
%
Total change in natural gas sales
 
$
3,608

 
17.0
%
 
$
13,560

 
37.3
%
Change in natural gas liquids sales due to:
 
 
 
 
 
 
 
 
Prices
 
$
2,603

 
24.1
%
 
$
5,258

 
24.9
%
Production
 
1,501

 
13.8
%
 
1,637

 
7.8
%
Total change in natural gas liquids sales
 
$
4,104

 
37.9
%
 
$
6,895

 
32.7
%
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 various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps.

32

Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Our derivative activities are dynamic to allow us to respond to the volatile commodity markets.
Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices: 
 
Three months ended
 
Six months ended
 
June 30,
 
June 30,
 
2014
 
2013
 
2014
 
2013
Oil (per Bbl)(1):
 
 
 
 
 
 
 
Before derivative settlements
$
87.51

 
$
78.16

 
$
86.66

 
$
78.16

After derivative settlements
$
82.15

 
$
82.14

 
$
82.96

 
$
82.34

Post-settlement to pre-settlement price
93.9
%
 
105.1
%
 
95.7
%
 
105.3
%
Natural gas (per Mcf):
 
 
 
 
 
 
 
Before derivative settlements
$
4.41

 
$
3.91

 
$
4.63

 
$
3.55

After derivative settlements
$
3.89

 
$
3.86

 
$
3.84

 
$
3.87

Post-settlement to pre-settlement price
88.2
%
 
98.7
%
 
82.9
%
 
109.0
%
___________
(1)
Includes natural gas liquids.
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)
 
June 30,
2014
 
December 31,
2013
Derivative (liabilities) assets:
 
 
 
 
Natural gas swaps
 
$
(3,957
)
 
$
(2,249
)
Oil swaps
 
(4,232
)
 
(2,695
)
Oil collars
 
(3,992
)
 
2,772

Oil enhanced swaps
 
(51,299
)
 
776

Oil purchased puts
 
339

 
74

Natural gas basis differential swaps
 
(531
)
 
1,643

Net derivative (liabilities) assets
 
$
(63,672
)
 
$
321

The effects of derivative activities on our results of operations and cash flows were as follows for the periods indicated:
 
 
Three months ended June 30,
 
 
2014
 
2013
(in thousands)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
 
 
 
 
 
 
 
 
Gain from oil hedging activities
 
$
—

 
$
—

 
$
9,509

 
$
—

Non-hedge derivative (losses) gains:
 
 
 
 
 
 
 
 
Oil swaps, collars, enhanced swaps and puts
 
$
(47,126
)
 
$
(10,305
)
 
$
12,385

 
$
6,275

Natural gas swaps
 
2,836

 
(3,689
)
 
12,971

 
(138
)
Natural gas basis differential contracts
 
(313
)
 
767

 
1,514

 
(115
)
Amortization of put premium
 
(166
)
 
—

 
—

 
—

Non-hedge derivative (losses) gains
 
$
(44,769
)
 
$
(13,227
)
 
$
26,870

 
$
6,022

Total (losses) gains from derivative activities
 
$
(44,769
)
 
$
(13,227
)
 
$
36,379

 
$
6,022


33

 
 
Six months ended June 30,
 
 
2014
 
2013
(in thousands)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
 
 
 
 
 
 
 
 
Gain from oil hedging activities
 
$
—

 
$
—

 
$
19,512

 
$
—

Non-hedge derivative (losses) gains:
 
 
 
 
 
 
 
 
Oil swaps, collars, enhanced swaps and puts
 
$
(61,000
)
 
$
(13,499
)
 
$
2,357

 
$
12,591

Natural gas swaps
 
(1,707
)
 
(8,378
)
 
(2,619
)
 
3,802

Natural gas basis differential contracts
 
(2,174
)
 
(105
)
 
1,690

 
(475
)
Amortization of premium put
 
(332
)
 
—

 
—

 
—

Non-hedge derivative (losses) gains
 
$
(65,213
)
 
$
(21,982
)
 
$
1,428

 
$
15,918

Total (losses) gains from derivative activities
 
$
(65,213
)
 
$
(21,982
)
 
$
20,940

 
$
15,918

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 our consolidated statements of operations. Gain from oil hedging activities, which is a component of total revenues in our consolidated statements of operations, of $9.5 million and $19.5 million for the three and six months ended June 30, 2013, respectively, consists of the reclassification of hedge gains on discontinued oil hedges from accumulated other comprehensive income into net income.
We recognized net non-hedge derivative (losses) gains of $(58.0) million during the three months ended June 30, 2014 compared to $32.9 million during the three months ended June 30, 2013. Non-hedge derivative (losses) gains were $(87.2) million during the six months ended June 30, 2014 compared to $17.3 million during the six months ended June 30, 2013. The fluctuation in non-hedge derivative (losses) gains 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.
Lease operating expenses
 
Three months ended June 30,
 
Percentage
change
 
Six months ended June 30,
 
Percentage
change
 
2014
 
2013
 
2014
 
2013
 
Lease operating expenses (in thousands)
$
36,564

 
$
32,949

 
11.0
 %
 
$
71,585

 
$
66,926

 
7.0
 %
Lease operating expenses per Boe
$
12.79

 
$
13.29

 
(3.8
)%
 
$
13.13

 
$
14.17

 
(7.3
)%
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 EOR projects are more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of CO2.
Our lease operating expenses increased $3.6 million and $4.7 million during the three and six months ended June 30, 2014, compared to the three and six months ended June 30, 2013, respectively, primarily due to costs associated with the expansion of our EOR floods, including our newest EOR flood at North Burbank Unit which commenced CO2 recycling in the first quarter of 2014. This increase was partially offset by decreased operating expenses due to the divestiture of certain non-core assets with higher operating costs during the second quarter of 2014.
Our lease operating expenses on a Boe basis, however, decreased 4% and 7% during the three and six months ended June 30, 2014 compared to the three and six months ended June 30, 2013. The decrease on a Boe basis is primarily attributable to the increase in overall production volumes between periods and the divestiture of oil and gas properties with higher operating costs offset partially by the additional recycle costs associated with our newest CO2 flood at North Burbank Unit. Costs at our North Burbank Unit are high as this unit is in a startup phase.

34

Production taxes (which include ad valorem taxes)
 
Three months ended June 30,
 
Percentage
change
 
Six months ended June 30,
 
Percentage
change
 
2014
 
2013
 
2014
 
2013
 
Production taxes (in thousands)
$
8,159

 
$
8,588

 
(5.0
)%
 
$
14,802

 
$
16,468

 
(10.1
)%
Production taxes per Boe
$
2.85

 
$
3.46

 
(17.6
)%
 
$
2.72

 
$
3.49

 
(22.1
)%
Production taxes generally change in proportion to commodity sales. Some states offer exemptions or reduced production tax rates for horizontal drilling, enhanced recovery projects and high cost gas wells. In Oklahoma, new wells qualify for a tax incentive and are taxed at a lower rate during their initial months of production. After the incentive period expires, the tax rate reverts to the statutory rate.
Our production taxes decreased 5% during the three months ended June 30, 2014 compared to the three months ended June 30, 2013 primarily due to reduced tax rates for horizontal drilling and high cost gas exemption tax credits, partially offset by the 16% increase in averaged realized prices combined with the 15% increase in sales volumes. Our production taxes decreased 10% during the six months ended June 30, 2014 compared to the six months ended June 30, 2013 primarily due to reduced tax rates for horizontal drilling along with EOR and high cost gas exemption tax credits, partially offset by the 17% increase in averaged realized prices combined with the 15% increase in sales volumes.
Depreciation, depletion and amortization (“DD&A”) and losses on impairment
 
Three months ended June 30,
 
Percentage
change
 
Six months ended June 30,
 
Percentage
change
 
2014
 
2013
 
2014
 
2013
 
DD&A (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas properties
$
59,829

 
$
44,795

 
33.6
 %
 
$
111,988

 
$
85,577

 
30.9
 %
Property and equipment
2,536

 
2,145

 
18.2
 %
 
5,053

 
4,272

 
18.3
 %
Accretion of asset retirement obligation
989

 
1,001

 
(1.2
)%
 
2,063

 
2,008

 
2.7
 %
Total DD&A
$
63,354

 
$
47,941

 
32.1
 %
 
$
119,104

 
$
91,857

 
29.7
 %
DD&A per Boe:
 
 
 
 
 
 
 
 
 
 
 
Oil and natural gas properties
$
20.93

 
$
18.07

 
15.8
 %
 
$
20.55

 
$
18.12

 
13.4
 %
Other fixed assets
$
1.23

 
$
1.27

 
(3.1
)%
 
$
1.30

 
$
1.33

 
(2.3
)%
Total DD&A per Boe
$
22.16

 
$
19.34

 
14.6
 %
 
$
21.85

 
$
19.45

 
12.3
 %
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 $15.0 million for the three months ended June 30, 2014, compared to the three months ended June 30, 2013, of which $8.1 million was due to a higher rate per equivalent unit of production and $6.9 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased $2.86 to $20.93 per Boe for the three months ended June 30, 2014 primarily due to higher estimated future development costs and higher cost reserve additions.
DD&A on oil and natural gas properties increased $26.4 million for the six months ended June 30, 2014, compared to the six months ended June 30, 2013, of which $13.2 million was due to a higher rate per equivalent unit of production and $13.2 million was due to an increase in production. Our DD&A rate per equivalent unit of production increased $2.43 to $20.55 per Boe for the six months ended June 30, 2014 primarily due to higher estimated future development costs and higher cost reserve additions.

35

General and administrative expenses (“G&A”) 
 
Three months ended June 30,
 
Percentage
change
 
Six months ended June 30,
 
Percentage
change
 
2014
 
2013
 
2014
 
2013
 
G&A (in thousands):
 
 
 
 
 
 
 
 
 
 
 
Gross G&A expenses
$
22,725

 
$
16,008

 
42.0
%
 
$
42,865

 
$
35,013

 
22.4
 %
Capitalized exploration and development costs
(7,733
)
 
(4,455
)
 
73.6
%
 
(14,486
)
 
(9,452
)
 
53.3
 %
Net G&A expenses
$
14,992

 
$
11,553

 
29.8
%
 
$
28,379

 
$
25,561

 
11.0
 %
Average G&A expense per Boe
$
5.24

 
$
4.66

 
12.4
%
 
$
5.21

 
$
5.41

 
(3.7
)%
Gross G&A expenses increased 42% and 22% during the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013. The increase between the comparative three and six month periods was primarily due to increased compensation and benefits costs related to the competitive nature of our market and our increased activity.
Capitalized exploration and development costs increased between periods, primarily due to a higher proportion of compensation costs subject to capitalization. A larger proportion of our compensation costs are being capitalized compared to the prior period as a result of our shift in focus from acquiring developed properties to exploring and developing leasehold acreage in resource plays with repeatable drilling opportunities.
Our G&A expenses on a Boe basis, increased 12% for the three months ended June 30, 2014 compared to the same period in 2013 due primarily to increased compensation and benefits costs quarter over quarter. Our G&A expenses on a Boe basis, however, decreased 4% for the six months ended June 30, 2014 compared to the same period in 2013 due primarily to the increase in overall production volumes between periods and an increase in the proportion of general and administrative expenses capitalized in connection with our increased 2014 development and exploration activities.
Other income and expenses
Interest expense. The following table presents interest expense for the periods indicated:
 
 
Three months ended
 
Six months ended
 
 
June 30,
 
June 30,
(in thousands)
 
2014
 
2013
 
2014
 
2013
9.875% Senior Notes due 2020
 
$
7,690

 
$
7,661

 
$
15,373

 
$
15,316

8.25% Senior Notes due 2021
 
8,420

 
8,406

 
16,836

 
16,808

7.625% Senior Notes due 2022
 
10,539

 
10,518

 
21,074

 
21,028

Senior secured revolving credit facility
 
1,645

 
364

 
3,064

 
491

Bank fees and other interest
 
1,256

 
1,172

 
2,605

 
2,397

Capitalized interest
 
(3,347
)
 
(3,921
)
 
(6,290
)
 
(7,549
)
Total interest expense
 
$
26,203

 
$
24,200

 
$
52,662

 
$
48,491

Average long-term borrowings
 
$
1,563,499

 
$
1,354,150

 
$
1,569,727

 
$
1,327,230

Total interest expense for the three and six months ended June 30, 2014 increased 8% and 9%, respectively, compared to the same periods in 2013 primarily due to increased levels of borrowing and reduced capitalized interest.
Liquidity and capital resources
Historically, our primary sources of liquidity have been cash generated from our operations, debt, private equity sales and proceeds from asset dispositions. As of June 30, 2014, we had cash and cash equivalents of $35.5 million and had borrowed $249.0 million under our senior secured revolving credit facility with a borrowing base of $532.0 million. As of August 14, 2014, outstanding borrowings under our senior secured revolving credit facility were $202.0 million with $281.6 million of remaining availability.

36

We believe that we will have sufficient funds available through our cash from operations, proceeds from asset divestitures 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.
Sources and uses of cash
Our net change in cash is summarized as follows:
 
 
Six months ended
 
 
June 30,
(in thousands)
 
2014
 
2013
Cash flows provided by operating activities
 
$
182,517

 
$
99,999

Cash flows used in investing activities
 
(171,117
)
 
(164,819
)
Cash flows (used in) provided by financing activities
 
(24,545
)
 
67,027

Net (decrease) increase in cash during the period
 
$
(13,145
)
 
$
2,207

Our cash flows from operating activities is derived substantially from the production and sale of oil and natural gas. Cash flows from operating activities were $82.5 million or 83% higher in the six months ended June 30, 2014 than they were in the same period of 2013 primarily due to an increase in commodity sales partially offset by increases in lease operating expenses and interest charges.
We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the six months ended June 30, 2014 and 2013, cash flows provided by operating activities were approximately 57% and 40%, respectively, of cash used for the acquisition and development of our property.
Our cash flows from investing activities is comprised primarily of cash inflows from asset dispositions and derivative settlement receipts offset by cash outflows for capital expenditures and derivative settlement payments.
Our actual costs incurred, including costs that we have accrued for, and our budgeted 2014 capital expenditures for oil and natural gas properties during the six months ended June 30, 2014 are summarized in the following table:
(in thousands)
 
E&P Areas
 
EOR Project Areas
 
Non-Core Properties
 
Total
 
2014 Capital Expenditures Budget (1)(2)(3)
Acquisitions
 
$
37,974

 
$
3,326

 
$
2,378

 
$
43,678

 
$
67,000

Drilling
 
199,081

 
32,214

 
77

 
231,372

 
455,000

Enhancements
 
12,639

 
32,884

 
976

 
46,499

 
76,000

Pipeline and field infrastructure
 
—

 
16,321

 
—

 
16,321

 
41,000

CO2 purchases
 
—

 
9,716

 
—

 
9,716

 
21,000

Total
 
$
249,694

 
$
94,461

 
$
3,431

 
$
347,586

 
$
660,000

___________
(1)
Includes $156 million allocated to our EOR project areas as follows: acquisitions of $3 million, drilling of $35 million, enhancements of $56 million, pipeline and field infrastructure of $41 million, and CO2 purchases of $21 million.
(2)
Budget categories presented include allocations of capitalized interest and general and administrative expenses.
(3)
During August 2014, our Board approved a $35 million increase to our capital expenditures budget.
Net cash used in investing activities during the six months ended June 30, 2014 was comprised of cash outflows for capital expenditure of $322.3 million and derivative settlement payments of $22.0 million partially offset by cash inflows from dispositions of non-strategic oil and natural gas properties of $173.2 million. The 2014 asset dispositions include the divestiture of our Delaware Basin and Ft. Worth Basin properties. Net cash used in investing activities during the six months ended June 30, 2013 was comprised primarily of cash outflows for capital expenditure of $248.2 million partially offset by cash inflows from asset dispositions of $68.1 million and derivative settlement receipts of $15.9 million.

37

Cash flows from financing activities is comprised primarily of cash inflows from long-term debt borrowings offset by cash outflows from repayments of long-term debt and capital leases. During the six months ended June 30, 2014 we had borrowings of $111.3 million which were offset by repayments of $134.7 million on our long-term debt and $1.1 million on our capital leases. The net reduction in long-term debt during this time period was funded by the proceeds from our asset divestitures. During the six months ended June 30, 2013 we had borrowings on our long-term debt of $100.7 million offset by repayments of $33.6 million.
Indebtedness
Long-term debt consists of the following as of the dates indicated:
(in thousands)
 
June 30, 2014
 
December 31, 2013
9.875% Senior Notes due 2020, net of discount of $5,161 and $5,444, respectively
 
$
294,839

 
$
294,556

8.25% Senior Notes due 2021
 
400,000

 
400,000

7.625% Senior Notes due 2022, including premium of $5,286 and $5,719, respectively
 
555,286

 
555,719

Senior secured revolving credit facility
 
249,000

 
272,000

Real estate mortgage notes
 
10,957

 
11,202

Installment notes
 
5,081

 
5,235

Capital lease obligations
 
23,004

 
24,150

 
 
$
1,538,167

 
$
1,562,862

Please see “Note 4—Long-term debt” in Item 8. Financial Statement and Supplementary Data of our annual report on Form 10-K for the year ended December 31, 2013 for a discussion of material terms governing our senior notes and senior secured revolving credit facility.
Senior secured revolving credit facility
We maintain a senior secured revolving credit facility, which is collateralized by our oil and natural gas properties, and matures on November 1, 2017. As of August 14, 2014, we have $202.0 million of outstanding borrowings under our senior secured revolving credit facility.
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 banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. 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. On April 22, 2014, our borrowing base was reaffirmed at $600.0 million.
On May 19, 2014, we entered into a Limited Consent and Fourteenth Amendment to our senior secured revolving credit facility which provides for a series of automatic reductions in the borrowing base under the senior secured revolving credit facility as the divestitures of our oil and natural gas properties are completed (see “Asset divestitures and alternative capital sources” below). As a result of our Fort Worth Basin and Delaware Basin divestitures that closed in May 2014, our borrowing base was reduced from $600.0 million to $532.0 million effective May 23, 2014. As a result of our Ark-La-Tex and Central Basin Platform divestitures that closed in July 2014, our borrowing base was further reduced from $532.0 million to $484.5 million effective July 18, 2014. We are still actively marketing the sale of our Gulf Coast properties whereupon a successful sale will trigger a further reduction in the borrowing base of $6.5 million.

38

The Limited Consent and Fourteenth Amendment also imposed an additional reduction in availability under our senior secured revolving credit facility equal to 10% of the borrowing base to compensate for the hedging of our production in excess of limits specified by covenants under the senior secured revolving credit facility. Outstanding hedges have temporarily exceeded the limits allowed under the senior secured revolving credit facility because of our recent asset divestitures. Our lenders have waived any covenant violations resulting from our temporary hedging noncompliance until August 15, 2014. On August 14, 2014 we entered into a Letter Agreement with our lenders to extend the waiver of temporary hedging noncompliance until November 1, 2014, the date of our next scheduled borrowing base redetermination. In conjunction with this extension, the 10% reduction in availability discussed above was replaced with a requirement to maintain a level of availability on our senior secured credit facility that is calculated based on our overhedged position. The requirement specifies that in the event the market value of our derivative contracts for a given commodity is a liability, the availability on our senior secured revolving credit facility must be no less than two times the liability on the overhedged production. As of August 14, 2014, we were overhedged on our projected natural gas production; however, since the market value of our natural gas derivative contracts, based on prior day settlement prices, was an asset on that date, there was no restriction on the availability under our senior secured credit facility.
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 June 30, 2014 and December 31, 2013, our current ratio as computed using GAAP was 0.66 and 0.80, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.63 and 2.35, 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)
 
June 30,
2014
 
December 31,
2013
Current assets per GAAP
 
$
199,302

 
$
176,657

Plus—Availability under senior secured revolving credit facility
 
228,880

 
327,080

Less—Short-term derivative instruments
 
—

 
(2,152
)
Less - Deferred tax asset on derivative instruments and asset retirement obligations
 
(20,114
)
 
(2,908
)
Current assets as adjusted
 
$
408,068

 
$
498,677

Current liabilities per GAAP
 
$
303,225

 
$
221,988

Less—Short-term derivative instruments
 
(46,818
)
 
(8,234
)
Less—Short-term asset retirement obligations
 
(6,792
)
 
(1,874
)
Current liabilities as adjusted
 
$
249,615

 
$
211,880

Current ratio for loan compliance
 
1.63

 
2.35

Our senior secured revolving credit facility, as amended, requires us to maintain a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than 4.50 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. As of June 30, 2014, availability under our senior secured revolving credit facility was limited to $228.9 million compared to the availability on August 14, 2014 which was $281.6 million.
Capital Leases
During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and gas full cost pool.The lease financing obligations are for 84-month terms and include the option to purchase the equipment for a specified price at 72 months as well as an option to purchase the equipment at the end of the lease term for its then-current fair market value. Lease payments related to the equipment are recognized as principal payments and interest expense.

39

Asset divestitures and alternative capital sources
As discussed in our Annual Report on Form 10-K for the year ended December 31, 2013, our Board approved selling our Ark-La-Tex, Permian Basin, Gulf Coast, and North Texas properties in five property packages to implement our strategy of focusing our operations in the Mid-Continent area. The five packages include: (i) our Fort Worth Basin package located in North Texas; (ii) our Delaware Basin package; (iii) our Central Basin Platform package; (iv) our Ark-La-Tex package; and (v) our Gulf Coast package.
During the second quarter of 2014, we closed on the sales of two of the five property packages in our divestiture plan. In May 2014, we sold our Fort Worth Basin package to Scout Energy Group I, LP, for cash proceeds of $25.2 million and we sold our Delaware Basin package to RKI Exploration & Production, LLC for cash proceeds of $125.0 million.
During the third quarter of 2014, we closed on the sales of two additional property packages. Our Ark-La-Tex and Central Basin Platform property packages, both of which were sold to RAM Energy, LLC (“RAM”), closed in July 2014 for cash proceeds of $48.5 million and $45.9 million, respectively. The cash proceeds from the four sales above are subject to post-closing adjustments.
In addition to the packages discussed above, we had various other divestitures during the six months ended June 30, 2014 for cash proceeds of approximately $20.0 million. These divestitures included properties predominantly located in Andrews County, Texas, which comprised part of our Permian Basin properties, and Osage County, Oklahoma.
Proceeds from the property sales discussed above as well as any future divestitures provide us with an additional source of liquidity to pay down borrowings under our senior secured revolving credit facility, fund capital expenditures and for general corporate purposes. Our external sources of liquidity in the future may include asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.
Contractual Obligations
We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to contracts for the purchase of CO2, drilling rig services, pipe and equipment. In June 2014, we entered into two non-cancelable operating leases for compressors at our EOR facilities. As of June 30, 2014, total minimum payments over the remaining life of the leases, which expire in 2021, were $6.7 million.
Other than the two new operating leases for compressors and net repayment of debt during the six months ended June 30, 2014, there were no material changes to our contractual commitments since December 31, 2013.


40

Non-GAAP financial measure and reconciliation
Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our senior secured revolving credit facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.
We define adjusted EBITDA as net income, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on hedge reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges.
The following table provides a reconciliation of our net income to adjusted EBITDA for the specified periods:
 
 
Three months ended June 30,
 
Six months ended June 30,
(in thousands)
 
2014
 
2013
 
2014
 
2013
Net (loss) income
 
$
(8,433
)
 
$
38,900

 
$
(4,028
)
 
$
37,710

Interest expense
 
26,203

 
24,200

 
52,662

 
48,491

Income tax (benefit) expense
 
(5,054
)
 
22,810

 
(2,419
)
 
22,123

Depreciation, depletion, and amortization
 
63,354

 
47,941

 
119,104

 
91,857

Reclassification adjustment for hedge gains
 
—

 
(9,509
)
 
—

 
(19,512
)
Non-cash change in fair value of non-hedge derivative instruments
 
44,603

 
(26,870
)
 
64,881

 
(1,428
)
Interest income
 
(56
)
 
(58
)
 
(71
)
 
(154
)
Stock-based compensation expense
 
1,022

 
(32
)
 
2,260

 
1,282

Gain on disposed assets
 
(727
)
 
(129
)
 
(811
)
 
(224
)
Adjusted EBITDA
 
$
120,912

 
$
97,253

 
$
231,578

 
$
180,145


Critical accounting policies
For a discussion of our critical accounting policies, which remain unchanged, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2013.
Also see the footnote disclosures included in “Note 1—Nature of operations and summary of significant accounting policies” in Item 1. Financial statements of this report.
Recent accounting pronouncements
See recently adopted and issued accounting standards in “Note 1—Nature of operations and summary of significant accounting policies” in Item 1. Financial statements of this report.


41

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our senior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the six months ended June 30, 2014, our gross revenues from oil and natural gas sales would change approximately $3.7 million for each $1.00 change in oil and natural gas liquid prices and $1.1 million for each $0.10 change in natural gas prices.
To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, including commodity price swaps, enhanced swaps, costless collars, put options, and basis protection swaps. We currently 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. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.
For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.
Collars contain a fixed floor price (purchased put) and ceiling price (sold 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 sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market price is below the sold put option price. If the market price is greater than the sold 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 sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold 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 utilizing the value associated with the sale of a put option.
Put options may be purchased from the counterparty by our payment of a cash premium. If the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor with the opportunity for upside if commodity prices increase.
We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will receive the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection.
We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.
Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). In conjunction with the sale of our Non-Core Properties in 2014, we may also early settle a portion of our derivative contracts in order to align our hedged volumes with anticipated production from remaining proved reserves. The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative position.

42

Our outstanding crude oil derivative instruments as of June 30, 2014 are summarized below:
 
 
 
 
Weighted average fixed price per Bbl
 
Period and type of contract
 
Volume
MBbls
 
Swaps
 
Sold puts
 
Purchased puts
 
Sold calls
 
 
 
 
 
 
 
 
 
 
 
 
 
July - September 2014
 
 
 
 
 
 
 
 
 
 
 
Swaps
 
208

 
$
91.93

 
$
—

 
$
—

 
$
—

 
Three-way collars
 
600

 
$
—

 
$
75.50

 
$
93.25

 
$
101.94

 
Enhanced swaps
 
210

 
$
98.20

 
$
80.00

 
$
—

 
$
—

 
Put spread enhanced swaps
 
670

 
$
93.99

 
$
80.00

 
$
60.00

 
$
—

 
Purchased puts
 
210

 
$
—

 
$
—

 
$
60.00

 
$
—

 
October - December 2014
 
 
 
 
 
 
 
—

 
 
 
Swaps
 
161

 
$
91.83

 
$
—

 
$
—

 
$
—

 
Three-way collars
 
600

 
$
—

 
$
75.50

 
$
93.25

 
$
101.94

 
Enhanced swaps
 
210

 
$
97.58

 
$
80.00

 
$
—

 
$
—

 
Put spread enhanced swaps
 
745

 
$
93.87

 
$
80.00

 
$
60.00

 
$
—

 
Purchased puts
 
210

 
$
—

 
$
—

 
$
60.00

 
$
—

 
January - March 2015
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
1,535

 
$
93.27

 
$
80.00

 
$
—

 
$
—

 
Purchased puts
 
1,370

 
$
—

 
$
—

 
$
60.00

 
$
—

 
April - June 2015
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
1,583

 
$
93.29

 
$
80.00

 
$
—

 
$
—

 
Purchased puts
 
1,418

 
$
—

 
$
—

 
$
60.00

 
$
—

 
July - September 2015
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
1,470

 
$
92.55

 
$
80.00

 
$
—

 
$
—

 
Purchased puts
 
1,380

 
$
—

 
$
—

 
$
60.00

 
$
—

 
October - December 2015
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
1,470

 
$
92.55

 
$
80.00

 
$
—

 
$
—

 
Purchased puts
 
1,380

 
$
—

 
$
—

 
$
60.00

 
$
—

 
January - March 2016
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
720

 
$
92.33

 
$
80.00

 
$
—

 
$
—

 
April - June 2016
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
720

 
$
92.33

 
$
80.00

 
$
—

 
$
—

 
July - September 2016
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
660

 
$
92.17

 
$
80.00

 
$
—

 
$
—

 
October - December 2016
 
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
660

 
$
92.17

 
$
80.00

 
$
—

 
$
—

 




43

Our outstanding natural gas derivative instruments as of June 30, 2014 are summarized below: 
Period and type of contract
 
Volume
BBtu
 
Weighted
average
fixed price
per MMBtu
 
 
 
 
 
July - September 2014
 
 
 
 
Natural gas swaps
 
5,190

 
$
3.98

Natural gas basis protection swaps
 
5,240

 
$
0.24

October - December 2014
 
 
 
 
Natural gas swaps
 
5,090

 
$
4.11

Natural gas basis protection swaps
 
5,200

 
$
0.24

January - March 2015
 
 
 
 
Natural gas swaps
 
5,270

 
$
4.34

Natural gas basis protection swaps
 
600

 
$
0.18

April - June 2015
 
 
 
 
Natural gas swaps
 
4,740

 
$
4.11

Natural gas basis protection swaps
 
600

 
$
0.18

July - September 2015
 
 
 
 
Natural gas swaps
 
5,920

 
$
4.13

Natural gas basis protection swaps
 
600

 
$
0.18

October - December 2015
 
 
 
 
Natural gas swaps
 
6,240

 
$
4.22

Natural gas basis protection swaps
 
600

 
$
0.18

January - March 2016
 
 
 
 
Natural gas swaps
 
2,400

 
$
4.49

Natural gas basis protection swaps
 
—

 
$
—

April - June 2016
 
 
 
 
Natural gas swaps
 
1,800

 
$
4.19

Natural gas basis protection swaps
 
—

 
$
—

July - September 2016
 
 
 
 
Natural gas swaps
 
1,800

 
$
4.24

Natural gas basis protection swaps
 
—

 
$
—

October - December 2016
 
 
 
 
Natural gas swaps
 
1,800

 
$
4.36

Natural gas basis protection swaps
 
—

 
$
—











44

Subsequent to June 30, 2014, we entered into oil derivatives summarized below:
 
 
 
 
Weighted average fixed price per Bbl
Period and type of contract
 
Volume
MBbls
 
Swaps
 
Sold puts
 
Purchased puts
 
Sold calls
 
 
 
 
 
 
 
 
 
 
 
July - September 2014
 
 
 
 
 
 
 
 
 
 
Swaps
 
140

 
$
103.51

 
$
—

 
$
—

 
$
—

October - December 2014
 
 
 
 
 
 
 
—

 
 
Swaps
 
26

 
$
101.20

 
$
—

 
$
—

 
$
—

January - March 2015
 
 
 
 
 
 
 
 
 
 
Swaps
 
150

 
$
98.33

 
$
—

 
$
—

 
$
—

April - June 2015
 
 
 
 
 
 
 
 
 
 
Swaps
 
150

 
$
96.60

 
$
—

 
$
—

 
$
—

July - September 2015
 
 
 
 
 
 
 
 
 
 
Swaps
 
150

 
$
95.12

 
$
—

 
$
—

 
$
—

October - December 2015
 
 
 
 
 
 
 
 
 
 
Swaps
 
150

 
$
94.03

 
$
—

 
$
—

 
$
—

January - March 2016
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
240

 
$
94.94

 
$
82.00

 
$
—

 
$
—

Three-way collars
 
60

 
$
—

 
$
84.00

 
$
92.00

 
$
101.01

April - June 2016
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
240

 
$
94.94

 
$
82.00

 
$
—

 
$
—

Three-way collars
 
60

 
$
—

 
$
84.00

 
$
92.00

 
$
101.01

July - September 2016
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
240

 
$
94.94

 
$
82.00

 
$
—

 
$
—

Three-way collars
 
60

 
$
—

 
$
84.00

 
$
92.00

 
$
101.01

October - December 2016
 
 
 
 
 
 
 
 
 
 
Enhanced swaps
 
240

 
$
94.94

 
$
82.00

 
$
—

 
$
—

Three-way collars
 
60

 
$
—

 
$
84.00

 
$
92.00

 
$
101.01


Interest rates. All of the outstanding borrowings under our senior secured revolving facility as of June 30, 2014 are subject to market rates of interest as determined from time to time by the banks. We may elect to borrow under our senior secured revolving credit facility at either Eurodollar rate, which is linked to LIBOR, or the ABR. Loans subject to the ABR bear interest at a fluctuating rate that is linked to the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in the senior secured revolving credit facility, plus 0.50%, or (3) the Adjusted LIBO rate, as defined in our senior secured revolving credit facility, plus 1%. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $532.0 million, equal to our borrowing base at June 30, 2014, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.3 million.


45

ITEM 4.
CONTROLS AND PROCEDURES
Disclosure controls and procedures
We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation as of the end of the period covered by this quarterly report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Internal control over financial reporting
There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time.
On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") issued an updated version of its Internal Control - Integrated Framework ("2013 Framework"). Originally issued in 1992 ("1992 Framework"), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of June 30, 2014, we continue to utilize the 1992 Framework during our transition to the 2013 Framework by the end of 2014.
PART II—OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS
Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us in the United States District Court for the Western District of Oklahoma, 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 $5.0 million. 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 liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The case was stayed on August 9, 2012 to allow the U.S. Court of Appeals for the Tenth Circuit to decide two unrelated cases that had issues similar to this case. The Tenth Circuit issued its opinions in those unrelated cases on July 9, 2013 and mandates were issued July 31, 2013. On or about October 1, 2013, the Court lifted the stay and entered a new scheduling order. The parties are conducting additional discovery and Plaintiff’s Motion for Class Certification is due February 15, 2015. Because a class has not been certified, we are not yet able to estimate a possible loss, or range of possible loss, if any.
Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson (the “Plaintiff”), filed a complaint against us in the District Court of Mayes County, Oklahoma, alleging claims on behalf of herself and all non-governmental Oklahoma citizens who are royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Petition was not served until July 2, 2013. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging entitlement to actual damages in an unspecified amount. The Plaintiff also requests allowable interest, punitive damages, injunctive relief, an accounting, disgorgement damages, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.



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Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, Martha Donelson and John Friend (the “Plaintiffs”), filed a complaint against us in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of themselves and all similarly situated Osage County land owners and surface lessees. The Plaintiffs assert class claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring our oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. The complaint has not yet been served on us. At this time, a class has not been certified and discovery has yet to begin. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.
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.

ITEM 1A.
RISK FACTORS
Information with respect to risk factors is included under Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2013. There have been no material changes to the risk factors since the filing of such Form 10-K.


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ITEM 6.
EXHIBITS
 
Exhibit No.
 
Description
 
 
 
10.1
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and Scout Energy Group I, LP dated April 3, 2014.
 
 

10.2
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and RKI Exploration & Production dated April 8, 2014.
 
 
 
10.3
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and RAM Energy, LLC dated April 25, 2014.
 
 
 
10.4
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and RAM Energy, LLC dated May 30, 2014.
 
 
 
10.5
 
Limited Consent and Fourteenth Amendment to Eighth Restated Credit Agreement dated as of May 19, 2014.
 
 
 
10.6
 
Letter Agreement to Eighth Restated Credit Agreement dated as of August 14, 2014.
 
 
 
31.1
 
Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
 
 
 
31.2
 
Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
 
 
 
32.1
 
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
32.2
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
101.INS
 
XBRL Instance Document
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document




48

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
CHAPARRAL ENERGY, INC.
 
 
By:
/s/ Mark A. Fischer
Name:
Mark A. Fischer
Title:
Chief Executive Officer
 
(Principal Executive Officer)
 
 
By:
/s/ Joseph O. Evans
Name:
Joseph O. Evans
Title:
Chief Financial Officer and
Executive Vice President
 
(Principal Financial Officer and
Principal Accounting Officer)
Date: August 14, 2014


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EXHIBIT INDEX

Exhibit No.
 
Description
 
 
 
10.1
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and Scout Energy Group I, LP dated April 3, 2014.
 
 
 
10.2
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and RKI Exploration & Production dated April 8, 2014.
 
 
 
10.3
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and RAM Energy, LLC dated April 25, 2014.
 
 
 
10.4
 
Asset Purchase and Sale Agreement by and between Chaparral Energy, L.L.C. and RAM Energy, LLC dated May 30, 2014.
 
 
 
10.5
 
Limited Consent and Fourteenth Amendment to Eighth Restated Credit Agreement dated as of May 19, 2014.
 
 
 
10.6
 
Letter Agreement to Eighth Restated Credit Agreement dated as of August 14, 2014.
 
 
 
31.1
 
Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
 
 
 
31.2
 
Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
 
 
 
32.1
 
Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
32.2
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
101.INS
 
XBRL Instance Document
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document


50

Chaparral Energy, Inc. Reports

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