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EX-32.2 - EXHIBIT 32.2 - Chaparral Energy, Inc.cprex32209302015.htm
EX-32.1 - EXHIBIT 32.1 - Chaparral Energy, Inc.cprex32109302015.htm
EX-10.2 - EXHIBIT 10.2 - Chaparral Energy, Inc.cprex10209302015.htm
EX-31.1 - EXHIBIT 31.1 - Chaparral Energy, Inc.cprex31109302015.htm
EX-31.2 - EXHIBIT 31.2 - Chaparral Energy, Inc.cprex31209302015.htm
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 September 30, 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 November 16, 2015:
Class
 
Number of
shares
Class A Common Stock, $0.01 par value
 
345,289

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 in Item 1A of this report and 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.
STACK. An acronym standing for Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate.
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


 
 
September 30,
2015
 
December 31,
2014
(dollars in thousands, except share data)
 
(unaudited)
 
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
37,783

 
$
31,492

Accounts receivable, net
 
77,583

 
98,444

Inventories, net
 
17,020

 
25,557

Prepaid expenses
 
2,055

 
4,484

Derivative instruments
 
142,944

 
179,921

Total current assets
 
277,385

 
339,898

Property and equipment—at cost, net
 
53,669

 
66,561

Oil and natural gas properties, using the full cost method:
 
 
 
 
Proved
 
4,049,859

 
3,735,817

Unevaluated (excluded from the amortization base)
 
98,032

 
288,425

Accumulated depreciation, depletion, amortization and impairment
 
(2,820,454
)
 
(1,701,851
)
Total oil and natural gas properties
 
1,327,437

 
2,322,391

Derivative instruments
 
40,766

 
71,710

Deferred income taxes
 
35,622

 

Other assets
 
29,019

 
31,256

 
 
$
1,763,898

 
$
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
 
 
September 30,
2015
 
December 31,
2014
(dollars in thousands, except share data)
 
(unaudited)
 
Liabilities and stockholders’ equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable and accrued liabilities
 
$
50,608

 
$
191,957

Accrued payroll and benefits payable
 
10,485

 
21,654

Accrued interest payable
 
33,578

 
24,106

Revenue distribution payable
 
12,023

 
24,467

Current maturities of long-term debt and capital leases
 
4,619

 
5,377

Derivative instruments
 
39

 
77

Deferred income taxes
 
51,629

 
60,728

Total current liabilities
 
162,981

 
328,366

Long-term debt and capital leases, less current maturities
 
1,671,920

 
1,628,425

Stock-based compensation
 
1,620

 
3,131

Asset retirement obligations
 
46,518

 
43,277

Deferred income taxes
 

 
116,759

Commitments and contingencies (Note 9)
 

 

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 345,336 and 364,896 shares issued and outstanding as of September 30, 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
 
430,609

 
429,678

Retained earnings
 
(549,764
)
 
282,166

 
 
(119,141
)
 
711,858

 
 
$
1,763,898

 
$
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
 
Nine months ended
 
 
September 30,
 
September 30,
(in thousands)
 
2015
 
2014
 
2015
 
2014
 
 
 
 
(unaudited)
 
 
Revenues:
 
 
 
 
 
 
 
 
Commodity sales
 
$
74,512

 
$
179,383

 
$
261,801

 
$
545,698

Total revenues
 
74,512

 
179,383

 
261,801

 
545,698

Costs and expenses:
 
 
 
 
 
 
 
 
Lease operating
 
24,881

 
38,915

 
83,921

 
107,650

Transportation and processing
 
1,902

 
3,162

 
6,246

 
6,012

Production taxes
 
2,795

 
7,133

 
11,123

 
21,935

Depreciation, depletion and amortization
 
52,027

 
61,527

 
173,694

 
180,631

Loss on impairment of oil and gas assets
 
737,758

 

 
955,320

 

Loss on impairment of other assets
 

 

 
13,311

 

General and administrative
 
7,389

 
14,820

 
25,843

 
43,199

Cost reduction initiatives
 
603

 

 
9,739

 

Total costs and expenses
 
827,355

 
125,557

 
1,279,197

 
359,427

Operating (loss) income
 
(752,843
)
 
53,826


(1,017,396
)

186,271

Non-operating income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(28,598
)
 
(25,434
)
 
(83,202
)
 
(78,096
)
Non-hedge derivative gains
 
85,415

 
104,413

 
105,266

 
17,218

Other income, net
 
108

 
442

 
2,088

 
1,407

Net non-operating income (expense)
 
56,925

 
79,421

 
24,152

 
(59,471
)
(Loss) income before income taxes
 
(695,918
)
 
133,247

 
(993,244
)
 
126,800

Income tax (benefit) expense
 
(48,776
)
 
49,734

 
(161,314
)
 
47,315

Net (loss) income
 
$
(647,142
)
 
$
83,513

 
$
(831,930
)
 
$
79,485

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


8


Chaparral Energy, Inc. and subsidiaries
Consolidated statements of cash flows
 
 
Nine months ended
 
 
September 30,
(in thousands)
 
2015
 
2014
 
 
(unaudited)
Cash flows from operating activities
 
 
 
 
Net (loss) income
 
$
(831,930
)
 
$
79,485

Adjustments to reconcile net income to net cash provided by operating activities
 
 
 
 
Depreciation, depletion and amortization
 
173,694

 
180,631

Loss on impairment of assets
 
968,631

 

Deferred income taxes
 
(161,480
)
 
46,894

Non-hedge derivative gains
 
(105,266
)
 
(17,218
)
Gain on sale of assets
 
(1,448
)
 
(1,007
)
Other
 
4,013

 
3,033

Change in assets and liabilities
 
 
 
 
Accounts receivable
 
16,625

 
(14,442
)
Inventories
 
(3,642
)
 
(7,287
)
Prepaid expenses and other assets
 
2,258

 
998

Accounts payable and accrued liabilities
 
(15,012
)
 
(906
)
Revenue distribution payable
 
(12,444
)
 
5,446

Stock-based compensation
 
(4,355
)
 
3,504

Net cash provided by operating activities
 
29,644

 
279,131

Cash flows from investing activities
 
 
 
 
Expenditures for property, plant, and equipment and oil and natural gas properties
 
(267,203
)
 
(499,255
)
Proceeds from asset dispositions
 
29,251

 
258,578

Settlement of non-hedge derivative instruments
 
173,149

 
(25,038
)
Net cash used in investing activities
 
(64,803
)
 
(265,715
)
Cash flows from financing activities
 
 
 
 
Proceeds from long-term debt
 
120,000

 
186,999

Repayment of long-term debt
 
(75,354
)
 
(227,572
)
Principal payments under capital lease obligations
 
(1,792
)
 
(1,726
)
Payment of other financing fees
 
(1,404
)
 

Net cash provided by (used in) financing activities
 
41,450

 
(42,299
)
Net increase (decrease) in cash and cash equivalents
 
6,291

 
(28,883
)
Cash and cash equivalents at beginning of period
 
31,492

 
48,595

Cash and cash equivalents at end of period
 
$
37,783

 
$
19,712

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 September 30, 2015, and for the three and nine months ended September 30, 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 and nine months ended September 30, 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 September 30, 2015, cash with a recorded balance totaling $36,124 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.
We write off accounts receivable when they are determined to be uncollectible. When we recover amounts that were previously written off, those amounts are offset against the allowance and reduce expense in the year of recovery.

10

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


Accounts receivable consisted of the following at September 30, 2015 and December 31, 2014 : 
 
September 30,
2015
 
December 31,
2014
Joint interests
$
10,928

 
$
30,648

Accrued commodity sales
28,060

 
45,667

Derivative settlements
37,388

 
19,678

Other
1,694

 
2,738

Allowance for doubtful accounts
(487
)
 
(287
)
 
$
77,583

 
$
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. We recorded a lower of cost or market adjustment of nil and $7,296 on our equipment inventory for the three and nine months ended September 30, 2015, respectively. The adjustment, recorded during the second quarter of 2015, was to reflect lower market prices resulting from a decline in demand for such equipment as drilling activity has decreased in the current low commodity price environment. The adjustment is reflected in “Loss on impairment of other assets” in our consolidated statements of operations.We did not record any significant inventory adjustments in the prior year periods. Inventories at September 30, 2015 and December 31, 2014 consisted of the following:
 
 
September 30,
2015
 
December 31,
2014
Equipment inventory
 
$
23,050

 
$
24,169

Commodities
 
1,839

 
2,575

Inventory valuation allowance
 
(7,869
)
 
(1,187
)
 
 
$
17,020

 
$
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 September 30, 2015, include $95,325 of capital costs incurred for undeveloped acreage and $2,707 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. Our work-in-progress balance at September 30, 2015 no longer includes amounts related to the construction of CO2 delivery pipelines and facilities as those have been reclassified to the full-cost amortization base during the third quarter of 2015 in conjunction with our recognition of proved reserves from the development of all remaining phases at our North Burbank Unit.

11

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


Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.
Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized.
Our estimates of oil and natural gas reserves as of September 30, 2015 were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC.
Due to the substantial decline of commodity prices that began in late 2014 and which remained low through September 30, 2015, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, resulting in a ceiling test write-down during the three and nine months ended September 30, 2015 of $737,758 and $955,320, respectively. Further write-downs are expected to occur in significant amounts if prices remain at their depressed levels. The amount of any future impairment is generally 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.
Impairment of long-lived assets
Impairment losses are recorded on property and equipment used in operations and other long-lived assets held and used when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset. Impairment losses are also recorded on assets classified as held for sale when there is an excess of carrying value over fair value less costs to sell.
We recorded impairment losses of nil and $6,015 related to four drilling rigs not currently in use for the three and nine months ended September 30, 2015. One of the rigs was last deployed in January 2015 while the remaining three have been stacked for two to three years. As a result of the recent deterioration in commodity prices and drilling activity, the value of such equipment has declined while utilizing third party equipment has become more cost effective, resulting in us impairing the value of the rigs to their estimated fair value during the second quarter of 2015. These losses are reflected in “Loss on impairment of other assets” in our consolidated statements of operations. We had previously recorded $3,490 and $1,500 of impairment related to these rigs during the years ended December 31, 2013 and 2012, respectively.
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. We consider the measurement of fair value of our phantom stock, RSU and restricted stock awards, discussed below, to be a Level 3 measurement within the fair value hierarchy.
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 assets 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.

12

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


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.
Income Taxes
For 2015, our annual estimated effective tax rate is forecasted to be a benefit of 28.7%, exclusive of discrete items. We expect to incur both a book and tax loss in year 2015. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the quarter ended September 30, 2015, our overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to valuation allowances and state income tax apportionment. In forecasting the 2015 annual estimated effective tax rate, we believe that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2015. We reached this conclusion considering several factors such as: (i) projected future tax losses, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in our balance sheet (which are primarily related to derivative instruments). At this time, the estimated valuation allowance to be recorded in 2015 would be approximately $225,000 including $126,000 recorded as a discrete item associated with our federal and state net operating loss carryforwards for the year ended December 31, 2014.
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 $9,739 of expenses for cost reduction initiatives for the nine months ended September 30, 2015, are $6,524, $347 and $596 recorded during the first, second and third quarters of 2015, respectively, for one-time severance and termination benefits in connection with our reduction in force that we began implementing 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.
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. The FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, 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.

13

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


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. Adoption of this guidance will only affect the presentation of our consolidated balance sheets and will not have a material impact on our consolidated financial statements. The initial guidance released in April 2015 did not address presentation or subsequent measurement related to line-of-credit arrangements. Recent guidance issued in August 2015 clarifies the issue by allowing an entity to defer and present debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. As our current policy is consistent with the recent guidance, the update regarding debt issuance costs for line-of-credit arrangements will not impact our financial statements or results of operations.
In July 2015, the FASB issued authoritative guidance that amends and simplifies the ways businesses value inventory so that businesses that use the first-in, first-out (FIFO) or average cost method will measure inventory at the lower of its cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. For public business entities, 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.
Note 2: Supplemental disclosures to the consolidated statements of cash flows
Supplemental disclosures to the consolidated statements of cash flows are presented below:
 
 
Nine months ended September 30,
 
 
2015
 
2014
Net cash provided by operating activities included:
 
 
 
 
Cash payments for interest
 
$
77,437

 
$
74,446

Interest capitalized
 
(8,115
)
 
(9,957
)
Cash payments for interest, net of amounts capitalized
 
$
69,322

 
$
64,489

Cash payments for income taxes
 
$
639

 
$
591

Non-cash investing activities included:
 
 
 
 
Asset retirement obligation additions and revisions
 
$
3,637

 
$
7,118

Change in accrued oil and gas capital expenditures
 
$
(116,237
)
 
$
22,458

Note 3: Acquisitions and divestitures
During the nine months ended September 30, 2015 we sold various non-core oil and gas properties for total proceeds of $26,868. The properties sold include acreage in various counties in South-Central Oklahoma in the SCOOP play (“South-Central Oklahoma Oil Province”) and oil and gas properties in Osage County.
As these properties did not represent a material portion of our oil and natural gas reserves, individually or in the aggregate, we did not record any gain or loss on the sales and instead, reduced our full cost pool by the amount of the net proceeds without significant alteration to our depletion rate.

14

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


Note 4: Long-term debt
As of the dates indicated, long-term debt consisted of the following:
 
 
September 30, 2015
 
December 31, 2014
9.875% Senior Notes due 2020, net of discount of $4,382 and $4,861, respectively
 
$
295,618

 
$
295,139

8.25% Senior Notes due 2021
 
400,000

 
400,000

7.625% Senior Notes due 2022, including premium of $4,272 and $4,869, respectively
 
554,272

 
554,869

Senior secured revolving credit facility
 
394,000

 
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
 
10,315

 
10,705

Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.85% to 5.95% , due October 2015 through February 2018; collateralized by automobiles, machinery and equipment
 
2,289

 
4,252

Capital lease obligations
 
20,045

 
21,837

 
 
1,676,539

 
1,633,802

Less current maturities
 
4,619

 
5,377

 
 
$
1,671,920

 
$
1,628,425

Senior Notes
The senior notes, which, as of September 30, 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 nine months ended September 30, 2015, we had additional net borrowings of $47,000 on our senior secured revolving credit facility. As of September 30, 2015, the weighted average interest rate was 2.3% 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 a result of that semiannual redetermination, our borrowing base was decreased from $650,000 to $550,000 effective on April 1, 2015. Our semiannual borrowing base redetermination, which was effective on October 29, 2015, reaffirmed our borrowing base at $550,000.
In connection with the Fifteenth Amendment, effective April 1, 2015, the Consolidated Net Debt to Consolidated EBITDAX covenant previously required by our senior secured revolving credit facility was 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

15

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


Debt, as revised in the amendment to now include both secured and unsecured debt. We incurred $1,404 in fees associated with the Fifteenth Amendment.
We believe we were in compliance with all covenants under our senior secured revolving credit facility as of September 30, 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 5: Derivative instruments
Overview
Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, 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, collars, put options, and basis protection swaps. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production.
From time to time, we may enter into derivative contracts that are not costless but instead require payment of a premium such as purchased puts, collars and three-way collars. The cash premium can be paid at the time the contracts are initiated or deferred until the contracts settle. Payment of deferred premiums at the contract settlement date reduces the proceeds to be received upon settlement of the contracts. The fair value of our derivative contracts are reported net of any deferred premiums that are payable under the contracts.
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.
On a purchased put option, 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 collars.

16

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


We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.
The following table summarizes our crude oil derivatives outstanding as of September 30, 2015: 
 
 
 
 
Weighted average fixed price per Bbl
 
Period and type of contract
 
Volume
MBbls
 
Swaps
 
Sold puts
 
Purchased puts
 
Sold calls
Average deferred premium
2015
 
 
 
 
 
 
 
 
 
 
 
Swaps (1)
 
630

 
$
91.38

 
$

 
$

 
$

$
13.80

Collars (1)
 
130

 
$

 
$

 
$
47.50

 
$
57.50

$
1.71

Purchased puts (1)
 
695

 
$

 
$

 
$
43.05

 
$

$
2.96

2016
 
 
 
 
 
 
 
 
 
 
 
Three-way collars
 
240

 
$

 
$
84.00

 
$
92.00

 
$
101.01

$

Three-way collars (1)
 
480

 
$

 
$
40.00

 
$
52.50

 
$
72.50

$
2.95

Enhanced swaps (2)
 
3,720

 
$
92.94

 
$
80.52

 
$

 
$

$

Purchased puts (2)
 
3,720

 
$

 
$

 
$
60.00

 
$

$

2017
 
 
 
 
 
 
 
 
 
 
 
Three-way collars (1)
 
480

 
$

 
$
42.50

 
$
55.00

 
$
80.00

$
2.78

___________
(1)
These contracts include deferred premiums that are payable upon settlement.
(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 $48.70 for 2016 as of September 30, 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 September 30, 2015:
Period and type of contract
 
Volume
BBtu
 
Weighted
average
fixed price
per MMBtu
2015
 
 
 
 
Natural gas swaps
 
3,940

 
$
4.24

Natural gas basis protection swaps
 
3,600

 
$
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


17

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


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 for the nine months ended September 30, 2015.
Prior to July 2015, our derivative portfolio included certain outstanding swaps, scheduled to mature between September and December 2015, covering 1,100,000 barrels of production. Net of deferred premiums of $12,424, the effective hedged price provided by these swaps was $82.34 per barrel. During the third quarter of 2015, we entered into offset positions on these swaps thereby locking in proceeds based on the difference between the contract price of the initial swaps and the contract price of the offset swaps, which we will receive as the contracts settle. Based on the September through December 2015 average NYMEX strip price of $45.70 per barrel at September 30, 2015, the average realized price, inclusive of the net locked-in proceeds for the 1,100,000 barrels of production, would be $82.68 per barrel. Any difference between settlement prices at contract maturity and the preceding average NYMEX price of $45.70 per barrel would result in a dollar for dollar impact on the realized price we receive. At September 30, 2015, 275,000 barrels of the locked-in swaps had matured for which net proceeds of $10,196 are to be received. Based on the October through December 2015 average NYMEX strip price of $45.77, at September 30, 2015, the average realized price, inclusive of the net locked-in proceeds for the remaining 825,000 barrels of production, will yield an effective price of $82.72. The 825,000 barrels of remaining locked-in swaps are not reflected in the derivatives outstanding table above as the anticipated proceeds no longer vary according to changes in crude oil pricing. However, the anticipated proceeds from the remaining locked-in swaps are reflected in the derivative asset and liability values disclosed in the table below.
Effect of derivative instruments on the consolidated balance sheets
All derivative financial instruments are recorded on the balance sheet at fair value. See Note 6Fair 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 September 30, 2015
 
As of December 31, 2014
 
Assets
 
Liabilities
 
Net value
 
Assets
 
Liabilities
 
Net value
Natural gas swaps
$
39,554

 
$

 
$
39,554

 
$
32,939

 
$

 
$
32,939

Oil swaps
9,386

 
(1,810
)
 
7,576

 
23,465

 

 
23,465

Oil collars (2)
3,483

 

 
3,483

 
1,175

 

 
1,175

Oil enhanced swaps
60,755

 

 
60,755

 
100,724

 

 
100,724

Oil purchased and sold puts
74,386

 
(924
)
 
73,462

 
93,268

 

 
93,268

Natural gas basis differential swaps

 
(1,159
)
 
(1,159
)
 
292

 
(309
)
 
(17
)
Total derivative instruments
187,564

 
(3,893
)
 
183,671

 
251,863

 
(309
)
 
251,554

Less:
 
 
 
 
 
 
 
 
 
 
 
Netting adjustments (1)
3,854

 
(3,854
)
 

 
232

 
(232
)
 

Current portion asset (liability)
142,944

 
(39
)
 
142,905

 
179,921

 
(77
)
 
179,844

 
$
40,766

 
$

 
$
40,766

 
$
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.
(2) Includes collars and 3-way collars.
Derivative settlements outstanding at September 30, 2015 and December 31, 2014 were as follows:
 
September 30,
2015
 
December 31,
2014
Derivative settlements receivable included in accounts receivable
$
37,388

 
$
19,678


18

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


Effect of derivative instruments on the consolidated statements of operations
We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as non-hedge derivative gains in the consolidated statements of operations.
Non-hedge derivative gains in the consolidated statements of operations are comprised of the following:
 
 
Three months ended
 
Nine months ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Change in fair value of commodity price swaps
 
$
6,583

 
$
20,039

 
$
(9,274
)
 
$
16,794

Change in fair value of collars
 
1,803

 
6,870

 
2,307

 
106

Change in fair value of enhanced swaps and put options
 
23,590

 
80,551

 
(59,775
)
 
27,521

Change in fair value of natural gas basis differential contracts
 
(1,035
)
 
9

 
(1,141
)
 
(2,165
)
Receipts from (payments on) settlement of commodity price swaps
 
12,829

 
(1,030
)
 
43,806

 
(12,653
)
Receipts from (payments on) settlement of collars
 
42

 
(77
)
 
42

 
(1,338
)
Receipts from (payments on) settlement of enhanced swaps and put options
 
41,667

 
(1,664
)
 
129,245

 
(10,657
)
(Payments on) receipts from settlement of natural gas basis differential contracts
 
(64
)
 
(285
)
 
56

 
(390
)
 
 
$
85,415

 
$
104,413

 
$
105,266

 
$
17,218

Note 6: Fair value measurements
Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.
Fair value measurements are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows:
Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability. 
Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability.
In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
Recurring fair value measurements
Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see Note 5Derivative instruments). We have no Level 1 assets or liabilities as of September 30, 2015 or December 31, 2014. Our derivative contracts classified as Level 2 as of September 30, 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.

19

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


As of September 30, 2015 and December 31, 2014, our derivative contracts classified as Level 3 consisted of collars, 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 September 30, 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)
$
48,940

 
$
(2,969
)
 
$
45,971

 
$
56,696

 
$
(309
)
 
$
56,387

Significant unobservable inputs (Level 3)
138,624

 
(924
)
 
137,700

 
195,167

 

 
195,167

Netting adjustments (1)
(3,854
)
 
3,854

 

 
(232
)
 
232

 

 
$
183,710

 
$
(39
)
 
$
183,671

 
$
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.
Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the nine months ended September 30, 2015 and 2014 were:
 
 
Nine months ended September 30,
Net derivative assets (liabilities)
 
2015
 
2014
Beginning balance
 
$
195,167

 
$
3,622

Realized and unrealized gains (losses) included in non-hedge derivative gains (losses)
 
4,660

 
15,632

Purchases
 

 
1,220

Settlements (received) paid
 
(62,127
)
 
11,995

Ending balance
 
$
137,700

 
$
32,469

Losses relating to instruments still held at the reporting date included in non-hedge derivative gains (losses) for the period
 
$
45,835

 
$
24,156

Nonrecurring fair value measurements
Asset retirement obligations. 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 nine months of 2015 and 2014 were escalated using an annual inflation rate of 2.91% and 2.95%, respectively, and discounted using our weighted average credit-adjusted risk-free interest rate of 13.45% and 6.60%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 7Asset retirement obligations for additional information regarding our asset retirement obligations.
Impairment of long-lived assets. As discussed in Note 1Nature of operations and summary of significant accounting policies, we recorded an impairment on four of our stacked drilling rigs during the second quarter of 2015. The estimated fair value related to the impairment assessment for our four drilling rigs no longer in service was primarily based on internal and external estimates and, therefore, is classified within Level 3 of the fair value hierarchy.

20

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


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 September 30, 2015 and December 31, 2014 were as follows: 
 
 
September 30, 2015
 
December 31, 2014
Level 2
 
Carrying
value
 
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
9.875% Senior Notes due 2020
 
$
295,618

 
$
97,500

 
$
295,139

 
$
269,091

8.25% Senior Notes due 2021
 
400,000

 
122,000

 
400,000

 
270,000

7.625% Senior Notes due 2022
 
554,272

 
154,000

 
554,869

 
379,775

Senior secured revolving credit facility
 
394,000

 
394,000

 
347,000

 
347,000

Other secured long-term debt
 
12,604

 
12,604

 
14,957

 
14,957

 
 
$
1,656,494

 
$
780,104

 
$
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.
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 September 30, 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.

21

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


The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.
 
 
Offset in the consolidated balance sheets
 
Gross amounts not offset in the consolidated balance sheets
 
 
Gross assets (liabilities)
 
Offsetting assets (liabilities)
 
Net assets (liabilities)
 
Derivatives(1)
 
Amounts outstanding under senior secured revolving credit facility
 
Net amount
As of September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
Derivative assets
 
$
187,564

 
$
(3,854
)
 
$
183,710

 
$

 
$
(114,282
)
 
$
69,428

Derivative liabilities
 
(3,893
)
 
3,854

 
(39
)
 

 

 
(39
)
 
 
$
183,671

 
$

 
$
183,671

 
$

 
$
(114,282
)
 
$
69,389

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 $3,893 at September 30, 2015.
Note 7: Asset retirement obligations
The following table provides a summary of our asset retirement obligation activity during the nine months ended September 30, 2015 and 2014. 
 
 
Nine months ended September 30,
 
 
2015
 
2014
Beginning balance
 
$
47,424

 
$
55,179

Liabilities incurred in current period
 
1,852

 
4,844

Liabilities settled and disposed in current period
 
(4,886
)
 
(16,807
)
Revisions in estimated cash flows
 
1,785

 
2,274

Accretion expense
 
2,727

 
2,991

Ending balance
 
48,902

 
48,481

Less current portion included in accounts payable and accrued liabilities
 
2,384

 
4,997

 
 
$
46,518

 
$
43,484

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

22

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


Note 8: Stock-based compensation
Phantom Stock Plan and Restricted Stock Unit Plan
Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). Under the Phantom Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.
Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, we do not expect to make any further awards under the Phantom Plan.
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.
A summary of our phantom stock and RSU activity during the nine months ended September 30, 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
$

 

 
 
 
$
14.88

 
59,571

 
 
Vested
$
24.48

 
(6,456
)
 
$
25

 
$
10.73

 
(216,941
)
 
$
857

Forfeited
$
18.34

 
(6,032
)
 
 
 
$
9.62

 
(133,132
)
 
 
Unvested and outstanding at September 30, 2015
$
18.61

 
10,691

 
 
 
$
10.48

 
278,658

 
 
Due to the severe decline in commodity pricing, which has resulted in a steep decline in our estimated proved reserves, the estimated fair value per phantom share and RSU as of September 30, 2015 is $0.00. The weighted average period until all remaining phantom shares and RSUs vest is 1.3 years.
2015 Cash Incentive Plan
We adopted the Long-Term Cash Incentive Plan (The “2015 Cash LTIP”) on August 7, 2015. The 2015 Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in equal annual increments over a four-year period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We awarded $3,297 of cash incentive awards in September 2015.
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).

23

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


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 nine months ended September 30, 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

 
 
 
$
113.90

 
599

Vested
$
778.81

 
(8,325
)
 
$
4,444

 
$

 

Forfeited
$
774.21

 
(3,997
)
 
 
 
$
323.53

 
(11,094
)
Unvested and outstanding at September 30, 2015
$
792.78

 
14,122

 
 
 
$
278.97

 
28,448

During the nine months ended September 30, 2015 and 2014, we repurchased and canceled 5,678 and 1,810 vested shares respectively, 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 $373.10 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $5,269 as of September 30, 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
 
Nine months ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Stock-based compensation cost
$
(581
)
 
$
2,309

 
$
(143
)
 
$
9,026

Less: stock-based compensation cost capitalized
(49
)
 
(289
)
 
(352
)
 
(2,735
)
Stock-based compensation expense
$
(630
)
 
$
2,020

 
$
(495
)
 
$
6,291

Payments for stock-based compensation
$
333

 
$
699


$
3,977

 
$
2,787


24

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


Our stock-based compensation expense for the nine months ended September 30, 2015 includes a credit recorded in the first quarter due to forfeitures resulting from our workforce reduction in February 2015 and a credit recorded during the third quarter due to lower valuations of our liability-based awards. As of September 30, 2015 and December 31, 2014, accrued payroll and benefits payable included $1,384 and $4,830, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost of approximately $7,134 is expected to be recognized over a weighted average period of 1.8 years.
Note 9: 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 September 30, 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 nine months ended September 30, 2015 or 2014.
Litigation 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. The plaintiffs filed their motion for class certification on Tuesday, October 13, 2015. The plaintiffs also moved for partial summary judgment, asking the court to determine, as a matter of law, that natural gas is not marketable until it is in a condition and location to be transported in an interstate pipeline and other dispositive issues. The Company is preparing its response to both motions. 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 $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 Plaintiff’s 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 our 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 Plaintiff’s 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

25

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


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. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Donelson Case will have on our 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 properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the Donelson 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. In September 2015, we entered into an interim financing agreement with U.S. Bank for an additional CO2 recycle compressor for our EOR facilities. If we do not enter into a lease once the compressor has been manufactured, we will owe U.S. Bank most of the cost incurred by U.S. Bank for the compressor. Other than additional debt borrowings during the nine months ended September 30, 2015, and our obligation under the interim financing agreement discussed above, there were no material changes to our contractual commitments since December 31, 2014.

26



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 and headquartered in Oklahoma City, we are a pure play Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich Mississippi Lime and STACK, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage, Woodford and Hunton formations. We are also the nation’s third-largest carbon dioxide enhanced oil recovery (“EOR”) producer based on number of active projects. This position is underscored by our activity in our world-class North Burbank Unit in Osage County, Oklahoma, which is the largest oil recovery unit in the state.
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.

Business and Industry Outlook
Crude oil prices decreased significantly in the latter part of 2014 and have remained low 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, ongoing since November 2014, 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 which to date has encompassed 200 employees, of which 131 were located in the Oklahoma City headquarters office and 69 were located at various field offices. In connection with our workforce reduction, we recorded charges of $6.5 million, $0.3 million and $0.6 million during the first, second and third quarters of 2015, respectively, related to one-time severance and termination benefits.
Given the depressed commodity price environment, we have aggressively pursued price concessions from third-party service vendors. We have achieved a target of $2.5 million to $3.0 million in drilling and completion costs per well as a result of cost reductions from service providers and improved operational efficiencies. In a further effort to fully capture gains associated with improved vendor price concessions, we delayed many of our completions of newly drilled wells into the second

27


half of the year. Specifically, out of 20 wells drilled and rig-released during the first half of the year, three wells were completed in the first quarter, eight wells in the third quarter and seven wells are expected to be completed in the fourth quarter. We drilled an additional four wells during the third quarter with three completed in October 2015 and the remaining well is expected to be completed during the fourth quarter.
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 during the first quarter of 2015 and nil during the second and third quarter. 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 compared to the amount spent in 2014. We reduced our operated rig count from 10 operated rigs at December 31, 2014 to one rig as of April 7, 2015 and continuing currently. 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. We have budgeted the addition of a second rig in November and a third rig in December of 2015 and therefore plan to exit the year with three rigs operating. Approximately 85% - 90% of our planned 2015 non-acquisition related capital investments in our E&P Areas will be focused on the high-return STACK and Mississippian Lime plays.
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, followed by a partial pay-down of our borrowings in the second and third quarter. We expect to make further pay-downs on our senior secured credit facility during the fourth quarter of the year. We will continue to monitor our capital spending closely based on actual and projected cash flows and evaluate our liquidity and capital requirements accordingly.
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 gas of the first day of each month for the 12-month period through September 30, 2015 were $59.21 per Bbl and $3.06 per MMBtu, respectively. As a result of the decline in average prices, we recorded a ceiling test write-down of $955.3 million during the nine months ended September 30, 2015, of which $737.8 million was recorded during the third quarter and the remainder of which was recorded in the second quarter. Since the prices used in the cost ceiling are based on a trailing 12-month period, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the price change on the financial statements over several reporting periods. While the amount of any future impairment is generally difficult to predict, if commodity prices remain at the current level, the average prices used in the ceiling test calculation will decline further resulting in a further write-down in the fourth quarter of 2015, which we expect to be in the range of $400 million to $450 million. 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.











28


2015 Highlights
During the third quarter of 2015, production decreased 11% to 2,452 MBoe compared to production of 2,767 MBoe during the third quarter of 2014, primarily due to the natural decline of certain wells, our decreased drilling activity, the temporary shut-in of marginal wells and our deferral of completions on wells that were drilled in the first half of the year. Revenue from commodity sales was $104.9 million lower in the third quarter of 2015 compared to the third quarter in 2014, primarily as a result of the 53% decrease in average realized prices. During the third quarter of 2015, we recorded a ceiling test impairment of oil and gas properties of $737.8 million which brings our total ceiling test write-down for the year to $955.3 million. The impairments are a result of the substantial decline in 12-month average commodity prices. Additionally, we had a non-hedge derivative gain of $85.4 million in the third quarter of 2015 compared to a $104.4 million non-hedge derivative gain during the same period last year. As a result of these and other factors, we reported a net loss of $647.1 million during the third quarter of 2015 compared to net income of $83.5 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 expected to range from $175.0 million to $225.0 million. Our capital expenditures during the nine months ended September 30, 2015 were $151.9 million, consisting primarily of $82.8 million in drilling and completion expenditures in our E&P Areas, $42.1 million for our EOR Project Areas and $17.7 million for the acquisition of oil and natural gas properties and leasehold.
Senior secured revolving credit facility and liquidity. We 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 4Long-term debt” in Item 1. Financial Statements and Supplementary Data of this report. Our semi-annual redetermination effective October 29, 2015, kept the borrowing base at the same level.
Proved property impairments. Due to the substantial decline of commodity prices in late 2014, which remained low through September 30, 2015, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties as of September 30, 2015, resulting in a ceiling test write-down during the second quarter of $737.8 million as further discussed in “Results of operations” and “Note 1Nature of operations and summary of significant accounting policies” 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
 
Nine months ended
 
Percent
change
 
September 30,
 
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
E&P Areas
 
 
 
 
 
 
 
 
 
 
 
Mississippi Lime
501

 
447

 
12.1
 %
 
1,688

 
1,359

 
24.2
 %
STACK
360

 
381

 
(5.5
)%
 
1,169

 
899

 
30.0
 %
Panhandle Marmaton
122

 
331

 
(63.1
)%
 
497

 
724

 
(31.4
)%
Legacy Production Areas
612

 
775

 
(21.0
)%
 
1,917

 
2,886

 
(33.6
)%
Total E&P Areas
1,595

 
1,934

 
(17.5
)%
 
5,271

 
5,868

 
(10.2
)%
EOR Project Areas
 
 
 
 
 
 
 
 
 
 
 
Active EOR Projects
562

 
502

 
12.0
 %
 
1,669

 
1,350

 
23.6
 %
Potential EOR Projects
295

 
331

 
(10.9
)%
 
918

 
999

 
(8.1
)%
Total EOR Project Areas
857

 
833

 
2.9
 %
 
2,587

 
2,349

 
10.1
 %
Total
2,452

 
2,767

 
(11.4
)%
 
7,858

 
8,217

 
(4.4
)%

29


E&P Areas

We have recently realigned the plays within our E&P areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. E&P Areas include the following plays: the STACK, Mississippi Lime, Panhandle Marmaton and Legacy Production Areas. During the nine months ended September 30, 2015, capital expenditures on drilling in the Mississippi Lime and STACK plays accounted for 89% of our capital expenditures for drilling in our E&P Areas.

STACK Play - The STACK is an acronym for Sooner Trend Anadarko Canadian Kingfisher which is indicative of a play area in the Anadarko Basin of Oklahoma in which we operate. It is a horizontal drilling play in an area of previously drilled vertical wells with multiple productive reservoirs. It encompasses all or parts of Blaine, Canadian, Garfield, Kingfisher and Major counties in Oklahoma. The STACK’s borders include the Nemaha Ridge (East), the Chester outcrop (North), and deep gas bearing characteristics (South and West). This thick column (500’+) includes multiple, stacked, and productive reservoirs, each with high oil saturations (30-50%) and include the Hunton, Woodford, Osage, Meramec, Oswego, and other intervals within the STACK area. The organic-rich Woodford Shale is the primary source of hydrocarbon migration into and present in the target reservoirs, which act as natural conduits for the oil migration from the Woodford. These complex carbonate-silt-shale stratigraphic intervals have proven to be very conducive to horizontal drilling and completion techniques. We own approximately 100,000 net surface acres and have approximately 4,200 drilling locations in this play.

Mississippi Lime Play - Various Counties, Oklahoma. The Mississippi Lime, located in South-Central Kansas and North-Central Oklahoma, is a shallow carbonate play (mostly Limestone) with depths ranging from 3,000 feet to 6,000 feet. The Mississippian Lime is not a new play, but is now a horizontal development among and bordering on legacy vertical producing fields. This area has a long history of production from vertical wells and a well-developed infrastructure system to support further development. Several companies in the industry are devoting large amounts of capital toward horizontal drilling activities in further developing this shallow, cost-effective resource play. Our operations in the Mississippian Lime are focused in the northwest region of Oklahoma and consist of 48,500 net acres and 575 gross drilling locations.

Panhandle Marmaton Play - Texas and Oklahoma Panhandles. Our Panhandle Marmaton play development program began in 2012. Our leasehold position provides for horizontal drilling opportunities targeting the Marmaton lime, which consists of numerous productive carbonate benches. The multi-stage fracture stimulation jobs performed in the play have increased its productivity considerably. We currently own 89,000 net acres in this play. In addition, we own extensive infrastructure in this play, including saltwater disposal wells and electrical grids.

Legacy Production Areas - Our Legacy Production Areas primarily include mature properties with low production decline curves. These Areas also include our Ark-La-Tex, Permian Basin, and North Texas properties which we divested in 2014. The production volumes from the divested properties are reflected in production volumes for the prior year period. The remaining properties are located in and hold leasehold acreage for future exploration in our existing repeatable resource plays which include our Cleveland Sand and Granite Wash plays .
    
Production in our E&P Areas decreased for both the three and nine months ended September 30, 2015 compared to the same periods in 2014. The quarter-over-quarter decrease in production is primarily due to the natural decline of our wells, the temporary shut-in of marginal wells due to the current pricing environment and the decrease in our drilling activity. Also contributing to the decrease in production was our strategic delay in completing wells drilled in the first half of 2015 into the second half of the year in order to avail ourselves of cost savings from third-party price concessions as well as in anticipation of potentially improved pricing. The natural production decline was most pronounced in our Panhandle Marmaton and Legacy Production Areas for which we did not allocate significant drilling capital in the current year. Production in the STACK play was relatively flat as the natural decline of wells was only partially offset by current year drilling and development due to aforementioned strategic delays in completions of eight wells drilled in 2015. Our Mississippi Lime play had increased production in the current quarter over the prior year quarter as a result of our continued drilling and development activities in this play.

The year-over-year decrease in our E&P Areas is primarily due to our significant strategic divestitures in 2014 along with reduced capital spending and temporary shut-in of marginal wells due to the current pricing environment. These decreases were offset partially by the increased production due to our drilling and development activities in our STACK and Mississippi Lime plays.

30


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 September 30, 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 and nine months ended September 30, 2015 compared to the same periods in 2014 were primarily due to production response in our North Burbank Unit and in our Farnsworth Unit. Production decreases in our Potential EOR Projects were due to natural decline and the temporary shut-in of marginal wells due to the current pricing environment.
On August 25, 2015, our pipeline carrying CO2 from our compressor station in Coffeyville, Kansas, to our North Burbank Unit developed a pinhole leak, releasing approximately 28 barrels of liquid CO2 which subsequently evaporated into the atmosphere. The leak was repaired within 36 hours. No injuries resulted from the leak, and the only property damage was to the pipe itself and the surface which was disturbed to access the pipe for repair. We promptly notified the National Response Center of the incident. On August 28, 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Corrective Action Order, requiring us to shut in the pipeline pending investigation of the cause of the leak. Our investigation revealed that the leak was caused by external corrosion in an area where the external coating of the pipe was damaged during installation. This was exacerbated by an electric current imbalance associated with cathodic protection systems that is typically easy to rectify. All affected areas of the pipeline were dug up and repaired and the line pressure tested to above normal operating conditions. Our Restart Plan was approved by PHMSA on September 18, 2015, and we have received approval and begun to re-establish CO2 delivery through the pipeline. Although no new CO2 was being delivered to the North Burbank Unit for over two months due to the pipeline shutdown, we continued to produce the unit with injection of recycled CO2 and water. We do not expect the required testing and repairs to have a material effect on our financial condition, results of operations or cash flows. We currently expect production levels at the North Burbank Unit at the end of 2015 to be approximately in the range of 2,900 to 3200 gross Boe/day.
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 production and commodity sales before the effects of commodity derivative settlements: 
 
Three months ended
 
Increase / (Decrease)
 
Percent
change
 
Nine months ended
 
Increase / (Decrease)
 
Percent change
 
September 30,
 
 
 
September 30,
 
 
 
2015
 
2014
 
 
2015
 
2014
 
 
Commodity sales (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil
$
58,353

 
$
146,320

 
$
(87,967
)
 
(60.1
)%
 
$
206,948

 
$
434,714

 
$
(227,766
)
 
(52.4
)%
Natural gas
11,402

 
18,949

 
(7,547
)
 
(39.8
)%
 
36,534

 
68,881

 
(32,347
)
 
(47.0
)%
Natural gas liquids
4,757

 
14,114

 
(9,357
)
 
(66.3
)%
 
18,319

 
42,103

 
(23,784
)
 
(56.5
)%
Total commodity sales
$
74,512

 
$
179,383

 
$
(104,871
)
 
(58.5
)%
 
$
261,801

 
$
545,698

 
$
(283,897
)
 
(52.0
)%
Production
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
1,328

 
1,528

 
(200
)
 
(13.1
)%
 
4,283

 
4,471

 
(188
)
 
(4.2
)%
Natural gas (MMcf)
4,624

 
4,986

 
(362
)
 
(7.3
)%
 
14,386

 
15,781

 
(1,395
)
 
(8.8
)%
Natural gas liquids (MBbls)
353

 
408

 
(55
)
 
(13.5
)%
 
1,177

 
1,116

 
61

 
5.5
 %
MBoe
2,452

 
2,767

 
(315
)
 
(11.4
)%
 
7,858

 
8,217

 
(359
)
 
(4.4
)%
Average daily production (Boe/d)
26,652

 
30,076

 
(3,424
)
 
(11.4
)%
 
28,784

 
30,099

 
(1,315
)
 
(4.4
)%
Average sales prices (excluding derivative settlements)
 
 
 
 
 
 
 
 
 
 
Oil per Bbl
$
43.94

 
$
95.76

 
$
(51.82
)
 
(54.1
)%
 
$
48.32


$
97.23

 
$
(48.91
)