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EX-31.2 - EXHIBIT 31.2 - Chaparral Energy, Inc.cprex31203312015.htm
EX-31.1 - EXHIBIT 31.1 - Chaparral Energy, Inc.cprex31103312015.htm
EX-32.2 - EXHIBIT 32.2 - Chaparral Energy, Inc.cprex32203312015.htm
EX-32.1 - EXHIBIT 32.1 - Chaparral Energy, Inc.cprex32103312015.htm
EX-10.1 - EXHIBIT 10.1 - Chaparral Energy, Inc.fifteenthamendmenttoeighth.htm
EXCEL - IDEA: XBRL DOCUMENT - Chaparral Energy, Inc.Financial_Report.xls
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 ____________________________
Form 10-Q
____________________________
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015

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.)
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
¨
Accelerated Filer
¨
Non-Accelerated Filer
ý
Smaller Reporting Company
¨



Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
Number of shares outstanding of each of the issuer’s classes of common stock as of May 12, 2015:
Class
 
Number of
shares
Class A Common Stock, $0.01 par value
 
348,507

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
 
 
Part II. Other 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, 2014. Specifically, some factors that could cause actual results to differ include:
volatility and declines in oil and natural gas prices
worldwide supply of and demand for oil and natural gas;
the significant amount of our debt;
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.
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.
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 natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
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.
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.


5


PART I — FINANCIAL INFORMATION

ITEM 1.
FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries
Consolidated balance sheets


 
 
March 31,
2015
 
December 31,
2014
(dollars in thousands, except share data)
 
(unaudited)
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
42,173

 
$
31,492

Accounts receivable, net
 
102,581

 
98,444

Inventories, net
 
27,162

 
25,557

Prepaid expenses
 
3,321

 
4,484

Derivative instruments
 
166,873

 
179,921

Total current assets
 
342,110

 
339,898

Property and equipment—at cost, net
 
64,397

 
66,561

Oil and natural gas properties, using the full cost method:
 
 
 
 
Proved
 
3,825,904

 
3,735,817

Unevaluated (excluded from the amortization base)
 
265,109

 
288,425

Accumulated depreciation, depletion, amortization and impairment
 
(1,763,747
)
 
(1,701,851
)
Total oil and natural gas properties
 
2,327,266

 
2,322,391

Derivative instruments
 
70,228

 
71,710

Other assets
 
30,120

 
31,256

 
 
$
2,834,121

 
$
2,831,816

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

6


Chaparral Energy, Inc. and subsidiaries
Consolidated balance sheets—continued
 
 
March 31,
2015
 
December 31,
2014
(dollars in thousands, except share data)
 
(unaudited)
 
Liabilities and stockholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable and accrued liabilities
 
$
90,916

 
$
191,957

Accrued payroll and benefits payable
 
13,550

 
21,654

Accrued interest payable
 
33,724

 
24,106

Revenue distribution payable
 
17,869

 
24,467

Current maturities of long-term debt and capital leases
 
5,138

 
5,377

Derivative instruments
 

 
77

Deferred income taxes
 
60,072

 
60,728

Total current liabilities
 
221,269

 
328,366

Long-term debt and capital leases, less current maturities
 
1,730,166

 
1,628,425

Stock-based compensation
 
537

 
3,131

Asset retirement obligations
 
45,020

 
43,277

Deferred income taxes
 
119,967

 
116,759

Commitments and contingencies (Note 8)
 

 

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 352,792 and 364,896 shares issued and outstanding as of March 31, 2015 and December 31, 2014, respectively
 
4

 
4

Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 344,859 shares issued and outstanding
 
3

 
3

Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding
 
2

 
2

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 shares issued and outstanding
 

 

Additional paid in capital
 
430,734

 
429,678

Retained earnings
 
286,414

 
282,166

 
 
717,162

 
711,858

 
 
$
2,834,121

 
$
2,831,816


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


7


Chaparral Energy, Inc. and subsidiaries
Consolidated statements of operations
 
 
 
Three months ended
 
 
March 31,
(in thousands)
 
2015
 
2014
 
 
(unaudited)
 
 
Revenues:
 
 
 
 
Commodity sales
 
$
93,079

 
$
173,339

Total revenues
 
93,079

 
173,339

Costs and expenses:
 
 
 
 
Lease operating
 
31,632

 
33,655

Transportation and processing
 
2,372

 
1,366

Production taxes
 
4,484

 
6,643

Depreciation, depletion and amortization
 
65,211

 
55,750

General and administrative
 
9,194

 
13,387

Cost reduction initiatives
 
8,774

 

Total costs and expenses
 
121,667

 
110,801

Operating income
 
(28,588
)

62,538

Non-operating income (expense):
 
 
 
 
Interest expense
 
(26,712
)
 
(26,459
)
Non-hedge derivative gains (losses)
 
61,431

 
(29,199
)
Other income, net
 
674

 
160

Net non-operating income (expense)
 
35,393

 
(55,498
)
Income before income taxes
 
6,805

 
7,040

Income tax expense
 
2,557

 
2,635

Net income
 
$
4,248

 
$
4,405

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


8


Chaparral Energy, Inc. and subsidiaries
Consolidated statements of cash flows
 
 
Three months ended
 
 
March 31,
(in thousands)
 
2015
 
2014
 
 
(unaudited)
Cash flows from operating activities
 
 
 
 
Net income
 
$
4,248

 
$
4,405

Adjustments to reconcile net income to net cash provided by operating activities
 
 
 
 
Depreciation, depletion & amortization
 
65,211

 
55,750

Deferred income taxes
 
2,553

 
2,485

Non-hedge derivative (gains) losses
 
(61,431
)
 
29,199

Gain on sale of assets
 
(79
)
 
(84
)
Other
 
1,221

 
492

Change in assets and liabilities
 
 
 
 
Accounts receivable
 
(8,126
)
 
(15,762
)
Inventories
 
(6,431
)
 
(4,234
)
Prepaid expenses and other assets
 
1,116

 
669

Accounts payable and accrued liabilities
 
(2,808
)
 
2,303

Revenue distribution payable
 
(6,598
)
 
(1,679
)
Stock-based compensation
 
(1,898
)
 
695

Net cash (used in) provided by operating activities
 
(13,022
)
 
74,239

Cash flows from investing activities
 
 
 
 
Expenditures for property, plant, and equipment and oil and natural gas properties
 
(156,798
)
 
(138,669
)
Proceeds from asset dispositions
 
3,068

 
16,997

Settlement of non-hedge derivative instruments
 
75,885

 
(8,755
)
Net cash used in investing activities
 
(77,845
)
 
(130,427
)
Cash flows from financing activities
 
 
 
 
Proceeds from long-term debt
 
103,000

 
50,603

Repayment of long-term debt
 
(860
)
 
(3,783
)
Principal payments under capital lease obligations
 
(592
)
 
(570
)
Net cash provided by financing activities
 
101,548

 
46,250

Net increase (decrease) in cash and cash equivalents
 
10,681

 
(9,938
)
Cash and cash equivalents at beginning of period
 
31,492

 
48,595

Cash and cash equivalents at end of period
 
$
42,173

 
$
38,657

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

9

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. Our 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, 2014.
The financial information as of March 31, 2015, and for the three months ended March 31, 2015 and 2014, respectively, is unaudited. The financial information as of December 31, 2014 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2014. In management’s opinion, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2015.
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 March 31, 2015, cash with a recorded balance totaling $38,551 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 our assessment of the owner’s ability to pay its obligation, among other things.

10

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. Recovered amounts previously written off are offset against the allowance and reduce expense in the year of recovery.
Accounts receivable consisted of the following at March 31, 2015 and December 31, 2014: 
 
March 31,
2015
 
December 31,
2014
Joint interests
$
21,844

 
$
30,648

Accrued commodity sales
37,968

 
45,667

Derivative settlements
41,092

 
19,678

Other
2,014

 
2,738

Allowance for doubtful accounts
(337
)
 
(287
)
 
$
102,581

 
$
98,444

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 March 31, 2015 and December 31, 2014 consisted of the following:
 
 
March 31,
2015
 
December 31,
2014
Equipment inventory
 
$
25,518

 
$
24,169

Commodities
 
2,821

 
2,575

Inventory valuation allowance
 
(1,177
)
 
(1,187
)
 
 
$
27,162

 
$
25,557

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 March 31, 2015, include $188,562 of capital costs incurred for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $4,501 for wells and facilities in progress pending determination. As of December 31, 2014, work-in-progress costs included capital costs incurred of $190,356 for undeveloped acreage, $72,046 for the construction of CO2 delivery pipelines and facilities for which there are no reserves, and $26,023 for wells and facilities in progress pending determination.
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.

11

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


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 March 31, 2015 were prepared using an average price for oil and natural gas of each month for the prior twelve months as required by the SEC. The cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of March 31, 2015, and no ceiling test impairment was recorded.
Due to the substantial decline of commodity prices in late 2014, which have remained low into the second quarter of 2015, we anticipate that we will have a ceiling test write-down, which could occur as early as the second quarter of 2015, if prices remain at their depressed levels. 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, stock-based compensation expense could have been significantly impacted if other assumptions had been used.
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.
Cost reduction initiatives
Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. Included in our $8,774 of expenses for cost reduction initiatives are $6,524 in one-time severance and termination benefits in connection with our reduction in force that was implemented in February 2015. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.



12

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.
In August 2014, the FASB issued authoritative guidance that requires entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and requires additional disclosures if certain criteria are met. This guidance is effective for fiscal periods after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.
In April 2015, the FASB issued authoritative guidance that amends the presentation of the cost of issuing debt on the balance sheet. The amendment requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendment. This guidance is effective for fiscal periods after December 15, 2015 and interim periods thereafter. 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:
 
 
Three months ended March 31,
 
 
2015
 
2014
Net cash provided by operating activities included:
 
 
 
 
Cash payments for interest
 
$
19,073

 
$
18,794

Interest capitalized
 
(3,462
)
 
(2,942
)
Cash payments for interest, net of amounts capitalized
 
$
15,611

 
$
15,852

Non-cash investing activities included:
 
 
 
 
Asset retirement obligation additions and revisions
 
$
539

 
$
139

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

 
$
18,629


13

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


Note 3: Long-term debt
As of the dates indicated, long-term debt consisted of the following:
 
 
March 31, 2015
 
December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,706 and $4,861, respectively
 
$
295,294

 
$
295,139

8.25% Senior Notes due 2021
 
400,000

 
400,000

7.625% Senior Notes due 2022, including premium of $4,666 and $4,869, respectively
 
554,666

 
554,869

Senior secured revolving credit facility
 
450,000

 
347,000

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
 
10,577

 
10,705

Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due April 2015 through February 2018; collateralized by automobiles, machinery and equipment
 
3,522

 
4,252

Capital lease obligations
 
21,245

 
21,837

 
 
1,735,304

 
1,633,802

Less current maturities
 
5,138

 
5,377

 
 
$
1,730,166

 
$
1,628,425

Senior Notes
The senior notes, which, as of March 31, 2015, 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 three months ended March 31, 2015, we borrowed $103,000 on our senior secured revolving credit facility. As of March 31, 2015, the weighted average interest rate was 2.2% on outstanding borrowings under the 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 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. Our first semiannual borrowing base redetermination for the current year was finalized ahead of schedule in conjunction with an amendment to our senior secured revolving credit facility (the “Fifteenth Amendment”), effective on April 1, 2015. As of result of our semiannual redetermination, our borrowing base was decreased from $650,000 to $550,000 effective on April 1, 2015.
In connection with the Fifteenth Amendment, the Consolidated Net Debt to Consolidated EBITDAX covenant required by our senior secured revolving credit facility will be replaced by a covenant based on the ratio of Consolidated Net Secured Debt to Consolidated EBITDAX, as defined in the amendment. Under this covenant, we are required to maintain a ratio of Consolidated Net Secured Debt to Consolidated EBITDAX no greater than 2.25 to 1.0 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. For the same applicable periods, the Fifteenth Amendment also requires us to maintain an Interest Coverage Ratio, as defined in the amendment, of no less than 2.00 to 1.0. Under the Fifteenth Amendment, we are allowed to incur an additional $300,000 in Additional Permitted Debt, as revised in the amendment to now include both secured and unsecured debt.


14

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


We believe we were in compliance with all covenants under our senior secured revolving credit facility as of March 31, 2015.
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 natural 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 4: Derivative instruments
Overview
Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas. and natural gas liquids. 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. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production.
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.
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 pay 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. A put spread may also be constructed by entering into separate sold put and purchased put contracts.
Put options may be purchased from the counterparty by paying a cash premium at the time the put options are purchased or deferring payment until 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 in an environment where prices have declined. In such an environment, put options may also be purchased to offset the downside from sold puts that are originally associated with enhanced swaps or three-way collars. The fair value of our put options include any deferred premiums that are payable under the contract.
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

15

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


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.
The following table summarizes our crude oil derivatives outstanding as of March 31, 2015: 
 
 
 
 
Weighted average fixed price per Bbl
 
Period and type of contract
 
Volume
MBbls
 
Swaps
 
Sold puts
 
Purchased puts
 
Sold calls
Average premium
2015
 
 
 
 
 
 
 
 
 
 
 
Swaps
 
450

 
$
95.25

 
$

 
$

 
$

$

Swaps with deferred premium (1)
 
4,028

 
$
92.78

 
$

 
$

 
$

$
13.80

2016
 
 
 
 
 
 
 
 
 
 
 
Three-way collars
 
240

 
$

 
$
84.00

 
$
92.00

 
$
101.01

$

Enhanced swaps (2)
 
3,720

 
$
92.94

 
$
80.52

 
$

 
$

$

Purchased puts (2)
 
3,720

 
$

 
$

 
$
60.00

 
$

$
5.54

___________
(1)
As a result of the deferred premiums, the above 4,028,000 barrels of crude oil production in 2015 are hedged at an effective price of $78.98/barrel.
(2)
Total premiums of $20,609 for the purchased puts were paid at contract inception in December 2014. Excluding the premiums and utilizing an average NYMEX strip price of $57.74 for 2016 as of March 31, 2015, the average realized price from our 3,720,000 barrels of hedged production that have associated sold puts and purchased puts is $72.42/barrel. This effective price is also the floor on the realized price we would receive in the event of any crude oil price decline below$60.00/barrel. Upon settlement, in the event that prices increase above $60.00/barrel, our effective price would increase by a commensurate amount of the price increase until prices reach the sold put price after which we would receive the swap price.

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2015:
Period and type of contract
 
Volume
BBtu
 
Weighted
average
fixed price
per MMBtu
2015
 
 
 
 
Natural gas swaps
 
12,240

 
$
4.15

Natural gas basis protection swaps
 
10,800

 
$
0.24

2016
 
 
 
 
Natural gas swaps
 
14,000

 
$
4.19

Natural gas basis protection swaps
 
8,400

 
$
0.36

2017
 
 
 
 
Natural gas swaps
 
12,700

 
$
3.64

2018
 
 
 
 
Natural gas swaps
 
8,250

 
$
3.83

On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels of oil and 12,280 Bbtu of natural gas, receiving net proceeds of $15,395, in order to maintain compliance with the hedging limits imposed by covenants under our senior secured credit facility. The proceeds are included in non-hedge derivative gains (losses) disclosed below.

16

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 balance sheets
All derivative financial instruments are recorded on the balance sheet at fair value. See Note 5Fair 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 March 31, 2015
 
As of December 31, 2014
 
Assets
 
Liabilities
 
Net value
 
Assets
 
Liabilities
 
Net value
Natural gas swaps
$
37,843

 
$

 
$
37,843

 
$
32,939

 
$

 
$
32,939

Oil swaps
19,168

 

 
19,168

 
23,465

 

 
23,465

Oil collars
1,700

 

 
1,700

 
1,175

 

 
1,175

Oil enhanced swaps
91,362

 

 
91,362

 
100,724

 

 
100,724

Oil purchased puts
85,987

 

 
85,987

 
93,268

 

 
93,268

Natural gas basis differential swaps
1,041

 

 
1,041

 
292

 
(309
)
 
(17
)
Total derivative instruments
237,101

 

 
237,101

 
251,863

 
(309
)
 
251,554

Less:
 
 
 
 
 
 
 
 
 
 
 
Netting adjustments (1)

 

 

 
232

 
(232
)
 

Current portion asset (liability)
166,873

 

 
166,873

 
179,921

 
(77
)
 
179,844

 
$
70,228

 
$

 
$
70,228

 
$
71,710

 
$

 
$
71,710

___________
(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.
Derivative settlements outstanding at March 31, 2015 and December 31, 2014 were as follows: 
 
March 31,
2015
 
December 31,
2014
Derivative settlements receivable included in accounts receivable
$
41,092

 
$
19,678

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.
Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following: 
 
 
Three months ended
 
 
March 31,
 
 
2015
 
2014
Change in fair value of commodity price swaps
 
$
606

 
$
(5,193
)
Change in fair value of collars
 
525

 
(2,863
)
Change in fair value of enhanced swaps and put options
 
(16,643
)
 
(10,527
)
Change in fair value of natural gas basis differential contracts
 
1,058

 
(1,861
)
Receipts from (payments on) settlement of commodity price swaps
 
19,027

 
(5,850
)
Payments on settlement of collars
 

 
(41
)
Receipts from (payments on) settlement of enhanced swaps and put options
 
56,949

 
(1,992
)
Payments on settlement of natural gas basis differential contracts
 
(91
)
 
(872
)
 
 
$
61,431

 
$
(29,199
)


17

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


Note 5: Fair value measurements
Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.
Fair value measurements are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows:
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability. 
Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Recurring fair value measurements
Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 4Derivative instruments). We have no Level 1 assets or liabilities as of March 31, 2015 or December 31, 2014. Our derivative contracts classified as Level 2 as of March 31, 2015 and December 31, 2014 consist of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate.
As of March 31, 2015 and December 31, 2014, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, sold puts 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 recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or that of our counterparties for derivative assets.
The fair value hierarchy for our financial assets and liabilities is shown by the following table: 
 
As of March 31, 2015
 
As of December 31, 2014
 
Derivative
assets
 
Derivative
liabilities
 
Net assets
(liabilities)
 
Derivative
assets
 
Derivative
liabilities
 
Net assets
(liabilities)
Significant other observable inputs (Level 2)
$
58,052

 
$

 
$
58,052

 
$
56,696

 
$
(309
)
 
$
56,387

Significant unobservable inputs (Level 3)
179,049

 

 
179,049

 
195,167

 

 
195,167

Netting adjustments (1)

 

 

 
(232
)
 
232

 

 
$
237,101

 
$

 
$
237,101

 
$
251,631

 
$
(77
)
 
$
251,554

___________
(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.

18

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


Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2015 and 2014 were: 
 
 
Three months ended March 31,
Net derivative assets (liabilities)
 
2015
 
2014
Beginning balance
 
$
195,167

 
$
3,622

Realized and unrealized gains (losses) included in non-hedge derivative losses
 
40,831

 
(15,423
)
Settlements (received) paid
 
(56,949
)
 
2,033

Ending balance
 
$
179,049

 
$
(9,768
)
Gains relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period
 
$
14,639

 
$
(15,324
)
Nonrecurring fair value measurements
Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first three months of 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95%, respectively, and discounted using our credit-adjusted risk-free interest rate of 12.40% and 5.80%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 6Asset 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 March 31, 2015 and December 31, 2014 were as follows: 
 
 
March 31, 2015
 
December 31, 2014
Level 2
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
9.875% Senior Notes due 2020
 
$
295,294

 
$
228,480

 
$
295,139

 
$
269,091

8.25% Senior Notes due 2021
 
400,000

 
278,000

 
400,000

 
270,000

7.625% Senior Notes due 2022
 
554,666

 
368,500

 
554,869

 
379,775

Senior secured revolving credit facility
 
450,000

 
450,000

 
347,000

 
347,000

Other secured long-term debt
 
14,099

 
14,099

 
14,957

 
14,957

 
 
$
1,714,059

 
$
1,339,079

 
$
1,611,965

 
$
1,280,823

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.

19

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


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 March 31, 2015, the counterparties to our open derivative contracts consisted of eight financial institutions, of which eight were subject to our rights of offset under our senior secured revolving credit facility.
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 March 31, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
237,101

 
$

 
$
237,101

 
$

 
$
(140,962
)
 
$
96,139

Derivative liabilities
 

 

 

 

 

 

 
 
$
237,101

 
$

 
$
237,101

 
$

 
$
(140,962
)
 
$
96,139

As of December 31, 2014
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
251,863

 
$
(232
)
 
$
251,631

 
$

 
$
(118,430
)
 
$
133,201

Derivative liabilities
 
(309
)
 
232

 
(77
)
 

 

 
(77
)
 
 
$
251,554

 
$

 
$
251,554

 
$

 
$
(118,430
)
 
$
133,124

___________
(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 nil at March 31, 2015.

20

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


Note 6: Asset retirement obligations
The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2015 and 2014. 
 
 
Three months ended March 31,
 
 
2015
 
2014
Beginning balance
 
$
47,424

 
$
55,179

Liabilities incurred in current period
 
141

 
139

Liabilities settled and disposed in current period
 
(3,030
)
 
(170
)
Revisions in estimated cash flows
 
398

 

Accretion expense
 
931

 
1,074

Ending balance
 
45,864

 
56,222

Less current portion included in accounts payable and accrued liabilities
 
844

 
1,874

 
 
$
45,020

 
$
54,348

See Note 5Fair value measurements for additional information regarding fair value assumptions associated with our asset retirement obligations.
Note 7: Stock-based compensation
Phantom Stock Plan and Restricted Stock Unit Plan
Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). 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.
Under the RSU Plan, restricted stock units may be awarded to Participants in an aggregate amount of 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.

21

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


A summary of our phantom stock and RSU activity during the three months ended March 31, 2015 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, 2015
$
20.18

 
23,179

 
 
 
$
9.91

 
569,160

 
 
Granted

 

 
 
 
15.26

 
52,711

 
 
Vested
24.48

 
(6,649
)
 
$
25

 
10.58

 
(206,332
)
 
$
790

Forfeited
17.99

 
(4,907
)
 
 
 
9.62

 
(105,159
)
 
 
Unvested and outstanding at March 31, 2015
$
18.64

 
11,623

 
 
 
$
10.48

 
310,380

 
 
Based on an estimated fair value of $2.92 per phantom share and RSU as of March 31, 2015, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $940.
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 whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). 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.
Our 2010 Plan allows participants to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.
We have previously modified the vesting conditions of awards granted under the 2010 Plan. Please see “Note 10—Stock-based compensation” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2014, for a discussion of the modifications.
A summary of our restricted stock activity during the three months ended March 31, 2015 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, 2015
$
791.52

 
25,834

 
 
 
$
292.92

 
38,943

Granted
533.80

 
610

 
 
 
306.50

 
599

Vested
794.40

 
(6,354
)
 
$
3,392

 

 

Forfeited
764.16

 
(3,190
)
 
 
 
310.57

 
(8,719
)
Unvested and total outstanding at March 31, 2015
$
786.30

 
16,900

 
 
 
$
288.19

 
30,823


22

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


During the three months ended March 31, 2015 and 2014, respectively, we repurchased and canceled 1,404 and 1,068 vested shares, primarily for tax withholding, and we expect to repurchase and cancel approximately 2,000 restricted shares vesting during the next twelve months. Based on an estimated fair value of $533.80 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $9,021 as of March 31, 2015.
Stock-based compensation cost
Compensation cost is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.
A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the periods indicated:
 
 
Three months ended
 
 
March 31,
 
 
2015
 
2014
Stock-based compensation cost
 
$
(1,500
)
 
$
2,531

Less: stock-based compensation cost capitalized
 
415

 
(962
)
Stock-based compensation expense
 
$
(1,085
)
 
$
1,569

Payments for stock-based compensation

$
812


$
874

We recorded a credit to our stock-based compensation expense for the three months ended March 31, 2015, due to forfeitures that occurred in conjunction with our workforce reduction in February 2015 and due to a decrease in the per-unit value of our phantom stock and RSU awards. As of March 31, 2015 and December 31, 2014, accrued payroll and benefits payable included $4,056 and $4,830, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $14,793 is expected to be recognized over a weighted average period of 2.3 years.
Note 8: 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 $874 and $920 as of March 31, 2015 and December 31, 2014, 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 three months ended March 31, 2015 or 2014.
Litgation and Claims
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, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Farms Case”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. Discovery is ongoing and information and documents continue to be exchanged. The class has not been certified, but the motion for class certification is due in the fourth quarter of 2015. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated that, if the class is certified, they seek damages in excess of

23

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


$5,000 which may increase with the passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
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, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
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, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma (“Donelson Case”), alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring 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. We have joined in Motions to Dismiss filed by the other defendants. 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. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.
We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.
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 CO2 recycle compressors at our EOR facilities and 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 additional debt borrowings during the three months ended March 31, 2015, there were no material changes to our contractual commitments since December 31, 2014.

24



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 Enhanced Oil Recovery (“EOR”) and are now the third largest CO2 EOR operator in the United States based on 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 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, 2014 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 21%, 14% and 12% 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.


25


Business and Industry Outlook
Crude oil prices decreased significantly in the latter part of 2014 and have continued to trend lower in 2015, dropping to their lowest levels since March 2009. Management's plans and related capital projections for 2015 are reflective of lower commodity prices.
In response to the decrease in crude oil prices, in February 2015 we began implementation of a Company-wide effort to decrease our capital, operating and administrative costs. Our cost reduction initiatives included a reduction in our workforce by 180 employees, of which 121 were located in the Oklahoma City headquarters office and 59 were located at various field offices. In connection with our workforce reduction, we recorded a charge of $6.5 million during the first quarter of 2015 related to one-time severance and termination benefits.
Given the weak commodity price environment, we have aggressively pursued price concessions from third-party service vendors. Based on expected cost reductions from service providers and improved operational efficiencies, we anticipate decreases of 20% - 30% in drilling and completion costs and 15% - 20% in lease operating expenses for 2015. We are continuing negotiations with our vendors to receive the best possible pricing.
As part of our cost reduction initiatives, we engaged third party legal and professional services for which we have incurred expenses of approximately $2.3 million for the three months ended March 31, 2015. As discussed below in “Liquidity and capital resources,” we are allowed to exclude up to $25.0 million of expenses incurred in connection with our cost reduction initiatives, including costs related to our workforce reduction, from our EBITDA-based covenant under our senior secured revolving credit facility.
We have significantly reduced our 2015 capital expenditures budget to $177.3 million, nearly one quarter the amount spent in 2014. We expect our operated rig count to average 2 rigs for full-year 2015, down from 10 operated rigs at December 31, 2014. As of April 7, 2015, we are operating one rig. While we have scaled back our 2015 drilling, we plan to continue the momentum of our long-term growth projects in our Mid-Continent area by focusing our drilling efforts in core areas of those plays that have the greatest potential to improve recoveries and rates of return.
Our 2015 capital budget was established based on an expectation of spending within available cash flows from operations, which included additional borrowings under our credit agreement during the first quarter as we reduced our accounts payable, with expected pay-down of those borrowings beginning in the second quarter. We will continue to monitor our capital spending closely based on actual and projected cash flows and could scale back our 2015 spending further should commodity prices fall further. Conversely, a significant improvement in crude oil prices could result in an increase in our capital expenditures.
We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility, as well as by aggressively pursuing cost reductions in a market downturn. However, price volatility impacts our business in various other ways, including our full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. For the year ended December 31, 2014, those prices were $94.99 per Bbl for oil and $4.35 per MMBtu for natural gas, while the unweighted arithmetic average prices of crude oil and natural as of the first day of each month for the 12-month period through March 2015 were $82.72 per Bbl and $3.88 per MMBtu, respectively. Prices have remained low into the second quarter. If commodity prices remain at the current level, the average prices used in the ceiling test calculation will decline and will likely cause write-downs of our oil and natural gas properties, which could occur as early as the second quarter of 2015. Continued write-downs of oil and natural gas properties may occur until such time as commodity prices recover, and remain at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.


26


2015 Highlights
During the first quarter of 2015, production increased 9% to 2,826 MBoe compared to production of 2,591 MBoe during the first quarter of 2014, primarily due to our drilling activity and increased EOR production response partially offset by our significant property divestitures. Despite production increases, revenue from commodity sales was $(80.3) million lower in the first quarter of 2015 compared to the first quarter in 2014 as a result of the 51% decrease in average realized prices. Additionally, due primarily to downward changes in the NYMEX forward commodity price curves, we had a non-hedge derivative gain of $61.4 million in the first quarter of 2015 compared to $29.2 million of non-hedge derivative losses during the same period last year. As a result of these and other factors, we reported a net gain of $4.2 million during the first quarter of 2015 compared to a net gain of $4.4 million for the comparable period in 2014.
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:
Capital expenditures. Our oil and natural gas property capital expenditure budget for 2015 is set at $177.3 million. Our capital expenditures during the three months ended March 31, 2015 were $71.6 million, consisting primarily of $44.9 million in drilling and completion expenditures in our E&P Areas, $13.8 million for our EOR Project Areas (excluding acquisitions) and $9.2 million for the acquisition of oil and natural gas properties and leasehold.
Senior secured revolving credit facility and liquidity. We have entered into an amendment to our senior secured revolving credit facility effective April 1, 2015, pursuant to which our borrowing base was redetermined to $550.0 million and certain covenants were revised as discussed further in “Liquidity and Capital Resources—Senior secured revolving credit facility” and “Note 3—Long-term debt” in Item 1. Financial Statements and Supplementary Data of this report.
Results of operations
Production
Production volumes by area were as follows (MBoe):
 
 
Three months ended
 
Percent
change
 
 
March 31,
 
 
2015
 
2014
 
E&P Areas
 
 
 
 
 
 
Mississippian
 
810

 
526

 
54.0
 %
Panhandle Marmaton
 
244

 
185

 
31.9
 %
Woodford Shale
 
151

 
23

 
556.5
 %
Oswego
 
112

 
64

 
75.0
 %
Legacy Production Areas
 
647

 
689

 
(6.1
)%
Total E&P Areas
 
1,964

 
1,487

 
32.1
 %
EOR Project Areas
 
 
 
 
 
 
Active EOR Projects
 
538

 
395

 
36.2
 %
Potential EOR Projects
 
317

 
342

 
(7.3
)%
Total EOR Project Areas
 
855

 
737

 
16.0
 %
Non-Core Properties
 
7

 
367

 
(98.1
)%
Total
 
2,826

 
2,591

 
9.1
 %
E&P Areas

E&P Areas includes our Mississippian, Panhandle Marmaton, Oswego and Woodford Shale plays, which are our repeatable resource 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.

The increase in production in our E&P Areas for the three months ended March 31, 2015 compared to the same period in 2014 is primarily due to our drilling and development activities in our Mississippian and Woodford Shale plays, slightly offset by decreased production in our Legacy Production Areas. The Mississippian and Woodford Shale plays accounted for

27


approximately 34%, and 21% of our total production during the three months ended March 31, 2015 and 2014, respectively. The decrease in production in our Legacy Production Areas is primarily due to strategic divestitures within these areas and normal production decline in the last twelve months concentrated in our Anadarko Cleveland Sand and Granite Wash plays.
EOR Project Areas
Our EOR Project Areas include both currently Active EOR Projects and Potential EOR Projects. Potential EOR Projects have no current EOR production or reserves at March 31, 2015. 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 for the three months ended March 31, 2015 compared to the same period in 2014 were primarily due to production response in our North Burbank Unit and in our Farnsworth Unit.
Non-Core Properties
As discussed in our Annual Report on Form 10-K for the year ended December 31, 2014, we sold most of our our Ark-La-Tex, Permian Basin, and North Texas properties during 2014. Production decreases in our Non-Core Properties were primarily due to divestitures within these areas. The remaining production within our Non-Core Properties is primarily attributable to properties we still own in our Gulf Coast areas.
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
 
Increase / (Decrease)
 
Percent change
 
 
March 31,
 
 
 
2015
 
2014
 
 
Commodity sales (in thousands)
 
 
 
 
 
 
 
 
Oil
 
$
71,765

 
$
135,119

 
$
(63,354
)
 
(46.9
)%
Natural gas
 
14,147

 
25,152

 
(11,005
)
 
(43.8
)%
Natural gas liquids
 
7,167

 
13,068

 
(5,901
)
 
(45.2
)%
Total commodity sales
 
$
93,079

 
$
173,339

 
$
(80,260
)
 
(46.3
)%
Production
 
 
 
 
 
 
 
 
Oil (MBbls)
 
1,573

 
1,415

 
158

 
11.2
 %
Natural gas (MMcf)
 
4,958

 
5,173

 
(215
)
 
(4.2
)%
Natural gas liquids (MBbls)
 
427

 
314

 
113

 
36.0
 %
MBoe
 
2,826

 
2,591

 
235

 
9.1
 %
Average daily production (Boe/d)
 
31,400

 
28,789

 
2,611

 
9.1
 %
Average sales prices (excluding derivative settlements)
 
 
 
 
 
 
 
 
Oil per Bbl
 
$
45.62


$
95.49

 
$
(49.87
)
 
(52.2
)%
Natural gas per Mcf
 
$
2.85


$
4.86

 
$
(2.01
)
 
(41.4
)%
NGLs per Bbl
 
$
16.78


$
41.62

 
$
(24.84
)
 
(59.7
)%
Average sales price per Boe
 
$
32.94


$
66.90

 
$
(33.96
)
 
(50.8
)%
Our total commodity sales decreased significantly during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 as a result of a 51% decrease in the average price per Boe offset slightly by a 9% increase in production volumes sold.
Average production volumes sold increased by 2,611 Boe per day, or 9%, during the three months ended March 31, 2015 compared to the three months ended March 31, 2014. The increase in average production volumes sold was primarily a result of new production from wells that were completed during the twelve months ended March 31, 2015 plus response from our EOR Project Areas which more than offset the decrease due to the strategic divestitures of our Non-Core properties during the period

28


and the decline in production in wells that were producing as of March 31, 2014. Average daily production volumes sold in our Mississippian and Woodford Shale plays increased by approximately 3,156 Boe per day, and 1,422 Boe per day, respectively, during the first quarter of 2015 compared to the first quarter of 2014, primarily as a result of our recent well completions. Average daily production volumes sold in our Active EOR project areas increased by approximately 1,589 Boe per day during the first quarter of 2015 compared to the first quarter of 2014, primarily as a result of production response in our North Burbank Unit and in our Farnsworth Unit. These increases were partially offset by a decrease in average production volumes sold in our Non-Core Properties and our Legacy Production Areas primarily due to strategic divestitures combined with declines in production and reduced 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 March 31,
 
 
2015 vs. 2014
(in thousands)
 
Sales
change
 
Percentage
change
in sales
Change in oil sales due to:
 
 
 
 
Prices
 
$
(78,441
)
 
(58.1
)%
Production
 
15,087

 
11.2
 %
Total change in oil sales
 
$
(63,354
)
 
(46.9
)%
Change in natural gas sales due to:
 
 
 
 
Prices
 
$
(9,960
)
 
(39.6
)%
Production
 
(1,045
)
 
(4.2
)%
Total change in natural gas sales
 
$
(11,005
)
 
(43.8
)%
Change in natural gas liquids sales due to:
 
 
 
 
Prices
 
$
(10,604
)
 
(81.2
)%
Production
 
4,703

 
36.0
 %
Total change in natural gas liquids sales
 
$
(5,901
)
 
(45.2
)%
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.
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.

29


Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices: 
 
 
Three months ended
 
 
March 31,
 
 
2015
 
2014
Oil (per Bbl)(1):
 
 
 
 
Before derivative settlements
 
$
39.47

 
$
85.71

After derivative settlements (2)
 
$
66.61

 
$
83.86

Post-settlement to pre-settlement price
 
168.8
%
 
97.8
%
Natural gas (per Mcf):
 
 
 
 
Before derivative settlements
 
$
2.85

 
$
4.86

After derivative settlements (2)
 
$
4.11

 
$
3.79

Post-settlement to pre-settlement price
 
144.2
%
 
78.0
%
(1)
Includes natural gas liquids.
(2)
Does not include settlements received from the early monetization of our derivative contracts discussed below.
The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.
(in thousands)
 
March 31,
2015
 
December 31,
2014
Derivative assets (liabilities):
 
 
 
 
Natural gas swaps
 
$
37,843

 
$
32,939

Oil swaps
 
19,168

 
23,465

Oil collars
 
1,700

 
1,175

Oil enhanced swaps
 
91,362

 
100,724

Oil purchased puts
 
85,987

 
93,268

Natural gas basis differential swaps
 
1,041

 
(17
)
Net derivative assets
 
$
237,101

 
$
251,554

The effects of derivative activities on our results of operations and cash flows were as follows for the periods indicated:
 
 
Three months ended March 31,
 
 
2015
 
2014
(in thousands)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
Non-cash
fair value
adjustment
 
Cash
receipts
(payments)
 
 
 
 
 
 
 
 
 
Non-hedge derivative gains (losses):
 
 
 
 
 
 
 
 
Oil swaps, collars, enhanced swaps and puts
 
$
(20,415
)
 
$
64,403

 
$
(14,040
)
 
$
(3,194
)
Natural gas swaps
 
4,903

 
11,573

 
(4,543
)
 
(4,689
)
Natural gas basis differential contracts
 
1,058

 
(91
)
 
(1,861
)
 
(872
)
Non-hedge derivative (losses) gains
 
$
(14,454
)
 
$
75,885

 
$
(20,444
)
 
$
(8,755
)
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 our consolidated statements of operations. Non-hedge derivative gains (losses) were $61.4 million during the three months ended March 31, 2015 compared to $(29.2) million during the three months ended March 31, 2014. The fluctuation in non-hedge derivative gains (losses) from period to period is due primarily to the significant volatility of oil and natural gas prices and to changes in our outstanding derivative contracts during these periods.

30


On March 26, 2015, we entered into early settlements of certain oil and natural gas derivative contracts originally scheduled to settle between 2015 to 2017 covering 495,000 barrels of oil and 12,280 Bbtu of natural gas for net proceeds of $15,395 in order to maintain compliance with the hedging limits imposed by covenants under our senior secured credit facility. The proceeds are included in the cash receipts related to the gains (losses) from derivative activities in the table above.
Lease operating expenses
 
Three months ended March 31,
 
Increase / (Decrease)
 
Percent
change
 
2015
 
2014
 
 
Lease operating expenses (in thousands, except per Boe data)
 
 
 
 
 
 
 
E&P Areas
$
13,820

 
$
17,664

 
$
(3,844
)
 
(21.8
)%
EOR Project Areas
$
17,812

 
$
15,991

 
$
1,821

 
11.4
 %
Total lease operating expense
$
31,632

 
$
33,655

 
$
(2,023
)
 
(6.0
)%
Lease operating expenses per Boe


 


 
 
 
 
E&P Areas
$
7.01

 
$
9.53

 
$
(2.52
)
 
(26.4
)%
EOR Project Areas
$
20.83

 
$
21.70

 
$
(0.87
)
 
(4.0
)%
Lease operating expenses per Boe
$
11.19

 
$
12.99

 
$
(1.80
)
 
(13.9
)%
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 E&P Areas lease operating expenses decreased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily as a result of the divestiture of certain non-core assets with higher operating costs and temporary shut-in of marginal wells due to the current low price environment partially offset by the incremental cost associated with new wells added during the last twelve months. Our E&P Areas lease operating expenses on a per Boe basis decreased primarily as a result of the divestiture of certain non-core assets with higher operating costs combined with the overall increase in production volumes between periods.
Our EOR Project Areas lease operating expenses increased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to additional costs associated with expansion of our EOR floods at our North Burbank and Farnsworth units. Our EOR Project Areas lease operating expenses on a per Boe basis decreased primarily as a result of the overall increase in production volumes between periods.
Transportation and processing expenses
 
Three months ended March 31,
 
Increase / (Decrease)
 
Percent
change
 
2015
 
2014
 
 
Transportation and processing expenses (in thousands)
$
2,372

 
$
1,366

 
$
1,006

 
73.6
%
Transportation and processing expenses per Boe
$
0.84

 
$
0.53

 
$
0.31

 
58.5
%
Transportation and processing expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. Our transportation and processing expenses increased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 as a result of the overall increase in natural gas liquids volumes processed in between periods primarily from our participation interests in wells drilled in the Cana Woodford Shale during the last twelve months.

31


Production taxes (which include ad valorem taxes)
 
Three months ended March 31,
 
Increase / (Decrease)
 
Percent
change
 
2015
 
2014
 
 
Production taxes (in thousands)
$
4,484

 
$
6,643

 
$
(2,159
)
 
(32.5
)%
Production taxes per Boe
$
1.59

 
$
2.56

 
$
(0.97
)
 
(37.9
)%
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 currently qualify for a tax incentive and are taxed at a lower rate of 1% during their initial 48 months of production. Recent legislation increases the tax incentive rate to 2% for the initial 36 months of production for wells spudded on or after July 1, 2015. After the incentive period expires, the tax rate reverts to the statutory rate.
Our production taxes decreased during the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to our 51% decrease in the average price on our commodity sales. Also contributing to the decline were our strategic divestitures of wells in our Non-Core Properties and Legacy Production Areas, which generally had higher tax rates, and reduced tax rates for horizontal drilling and our EOR projects. These increases were partially offset by the 9% increase in sales volumes.
Depreciation, depletion and amortization (“DD&A”) and losses on impairment
 
Three months ended March 31,
 
Increase / (Decrease)
 
Percent
change
 
2015
 
2014
 
 
DD&A (in thousands):
 
 
 
 
 
 
 
Oil and natural gas properties
$
61,896

 
$
52,159

 
$
9,737

 
18.7
 %
Property and equipment
2,384

 
2,517

 
(133
)
 
(5.3
)%
Accretion of asset retirement obligation