BILL BARRETT CORP - FORM 10-Q - November 5, 2015

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 

FORM 10-Q
 
(Mark One)
x
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
 
o
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 001-32367

BILL BARRETT CORPORATION
(Exact name of registrant as specified in its charter)

Delaware
 
80-0000545
(State or other jurisdiction of
incorporation
or organization)
 
(IRS Employer
Identification No.)

1099 18th Street, Suite 2300
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)

(303) 293-9100
(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.    x  Yes    o  No

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).    x  Yes    o  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
 
x
  
Accelerated filer
 
o
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
o

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

There were 49,959,996 shares of $0.001 par value common stock outstanding on October 23, 2015.


INDEX TO FINANCIAL STATEMENTS
 

2

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

 
September 30, 2015
 
December 31, 2014
 
(in thousands, except share data)
Assets:
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
92,836

 
$
165,904

Short-term investments
19,992

 
—

Accounts receivable, net of allowance for doubtful accounts
44,070

 
112,209

Derivative assets
109,847

 
145,226

Prepayments and other current assets
3,395

 
2,766

Total current assets
270,140

 
426,105

Property and equipment - at cost, successful efforts method for oil and gas properties:
 
 
 
Proved oil and gas properties
1,942,076

 
2,009,292

Unproved oil and gas properties, excluded from amortization
95,213

 
148,834

Oil and gas properties held for sale, net of amortization and impairment
64,882

 
9,234

Furniture, equipment and other
29,496

 
39,963

 
2,131,667

 
2,207,323

Accumulated depreciation, depletion, amortization and impairment
(892,720
)
 
(454,202
)
Total property and equipment, net
1,238,947

 
1,753,121

Deferred income taxes
42,137

 
—

Derivative assets
32,209

 
49,750

Deferred financing costs and other noncurrent assets
12,827

 
15,508

Total
$
1,596,260

 
$
2,244,484

Liabilities and Stockholders' Equity:
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
111,309

 
$
126,252

Amounts payable to oil and gas property owners
18,337

 
19,187

Production taxes payable
27,416

 
38,060

Deferred income taxes
42,137

 
55,418

Current portion of long-term debt
1,015

 
25,770

Total current liabilities
200,214

 
264,687

Long-term debt
802,894

 
803,222

Asset retirement obligations
14,699

 
21,592

Liabilities associated with assets held for sale
7,641

 
146

Deferred income taxes
—

 
122,350

Derivatives and other noncurrent liabilities
3,046

 
2,999

Stockholders' equity:
 
 
 
Common stock, $0.001 par value; authorized 150,000,000 shares; 49,961,616 and 49,526,637 shares issued and outstanding at September 30, 2015 and December 31, 2014, respectively, with 1,604,739 and 1,407,141 shares subject to restrictions, respectively
48

 
48

Additional paid-in capital
918,523

 
913,619

Retained earnings (Accumulated deficit)
(350,805
)
 
115,821

Treasury stock, at cost: zero shares at September 30, 2015 and December 31, 2014, respectively
—

 
—

Total stockholders' equity
567,766

 
1,029,488

Total
$
1,596,260

 
$
2,244,484

See notes to Unaudited Consolidated Financial Statements.

3

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except share and per
share data)
Operating and Other Revenues:
 
 
 
 
 
 
 
Oil, gas and NGL production
$
48,799

 
$
134,342

 
$
158,667

 
$
397,731

Other
880

 
921

 
2,664

 
7,658

Total operating and other revenues
49,679

 
135,263

 
161,331

 
405,389

Operating Expenses:
 
 
 
 
 
 
 
Lease operating expense
9,638

 
16,284

 
34,834

 
48,367

Gathering, transportation and processing expense
684

 
10,784

 
2,559

 
34,238

Production tax expense
3,670

 
10,495

 
10,020

 
27,770

Exploration expense
20

 
23

 
145

 
442

Impairment, dry hole costs and abandonment expense
572,651

 
29,109

 
574,996

 
32,613

(Gain) Loss on divestitures
(77
)
 
99,466

 
(759
)
 
96,896

Depreciation, depletion and amortization
54,738

 
69,024

 
159,666

 
189,426

Unused commitments
4,388

 
—

 
13,163

 
—

General and administrative expense
11,025

 
11,111

 
39,026

 
41,039

Total operating expenses
656,737

 
246,296

 
833,650

 
470,791

Operating Income (Loss)
(607,058
)
 
(111,033
)
 
(672,319
)
 
(65,402
)
Other Income and Expense:
 
 
 
 
 
 
 
Interest and other income
100

 
264

 
519

 
991

Interest expense
(15,754
)
 
(18,033
)
 
(49,574
)
 
(53,285
)
Commodity derivative gain (loss)
69,133

 
72,299

 
75,914

 
369

Gain (Loss) on extinguishment of debt
—

 
—

 
1,749

 
—

Total other income and expense
53,479

 
54,530

 
28,608

 
(51,925
)
Income (Loss) before Income Taxes
(553,579
)
 
(56,503
)
 
(643,711
)
 
(117,327
)
(Provision for) Benefit from Income Taxes
143,265

 
21,854

 
177,085

 
43,343

Net Income (Loss)
$
(410,314
)
 
$
(34,649
)
 
$
(466,626
)
 
$
(73,984
)
Net Income (Loss) Per Common Share, Basic
$
(8.49
)
 
$
(0.72
)
 
$
(9.67
)
 
$
(1.54
)
Net Income (Loss) Per Common Share, Diluted
$
(8.49
)
 
$
(0.72
)
 
$
(9.67
)
 
$
(1.54
)
Weighted Average Common Shares Outstanding, Basic
48,339,639

 
48,060,086

 
48,279,763

 
47,982,992

Weighted Average Common Shares Outstanding, Diluted
48,339,639

 
48,060,086

 
48,279,763

 
47,982,992

See notes to Unaudited Consolidated Financial Statements.

4

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Net Income (Loss)
$
(410,314
)
 
$
(34,649
)
 
$
(466,626
)
 
$
(73,984
)
Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
Effect of derivative financial instruments
—

 
(219
)
 
—

 
(555
)
Other comprehensive income (loss)
—

 
(219
)
 
—

 
(555
)
Comprehensive Income (Loss)
$
(410,314
)
 
$
(34,868
)
 
$
(466,626
)
 
$
(74,539
)
See notes to Unaudited Consolidated Financial Statements.

5

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
 
Nine Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Operating Activities:
 
 
 
Net Income (Loss)
$
(466,626
)
 
$
(73,984
)
Adjustments to reconcile to net cash provided by operations:
 
 
 
Depreciation, depletion and amortization
159,666

 
189,426

Deferred income tax benefit
(176,797
)
 
(43,604
)
Impairment, dry hole costs and abandonment expense
574,996

 
32,613

Total commodity derivative (gain) loss
(75,914
)
 
(369
)
Gain (Loss) on settlements of commodity derivatives
128,834

 
(21,580
)
Stock compensation and other non-cash charges
7,281

 
9,651

Amortization of debt discounts and deferred financing costs
3,983

 
3,200

(Gain) Loss on extinguishment of debt
(1,749
)
 
—

(Gain) Loss on sale of properties
(759
)
 
96,896

Change in operating assets and liabilities:
 
 
 
Accounts receivable
20,394

 
9,025

Prepayments and other assets
(261
)
 
914

Accounts payable, accrued and other liabilities
4,347

 
20,723

Amounts payable to oil and gas property owners
(850
)
 
1,936

Production taxes payable
(10,644
)
 
6,455

Net cash provided by (used in) operating activities
165,901

 
231,302

Investing Activities:
 
 
 
Additions to oil and gas properties, including acquisitions
(256,059
)
 
(425,978
)
Additions of furniture, equipment and other
(1,036
)
 
(2,110
)
Proceeds from sale of properties and other investing activities
66,617

 
557,747

Cash paid for short-term investments
(114,883
)
 
—

Proceeds from the sale of short-term investments
95,000

 
—

Net cash provided by (used in) investing activities
(210,361
)
 
129,659

Financing Activities:
 
 
 
Proceeds from debt
—

 
165,000

Principal payments on debt
(25,083
)
 
(283,442
)
Proceeds from stock option exercises
—

 
126

Deferred financing costs and other
(3,525
)
 
(2,462
)
Net cash provided by (used in) financing activities
(28,608
)
 
(120,778
)
Increase (Decrease) in Cash and Cash Equivalents
(73,068
)
 
240,183

Beginning Cash and Cash Equivalents
165,904

 
54,595

Ending Cash and Cash Equivalents
$
92,836

 
$
294,778

See notes to Unaudited Consolidated Financial Statements.

6

BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(UNAUDITED)
(In thousands)
 
 
Common
Stock
 
Additional
Paid-In
Capital
 
Retained
Earnings (Accumulated Deficit)
 
Treasury
Stock
 
Accumulated
Other
Comprehensive
Income
 
Total
Stockholders'
Equity
Balance at December 31, 2013
$
48

 
$
904,261

 
$
100,740

 
$
—

 
$
669

 
$
1,005,718

Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
—

 
126

 
—

 
(2,684
)
 
—

 
(2,558
)
Stock-based compensation
—

 
11,916

 
—

 
—

 
—

 
11,916

Retirement of treasury stock
—

 
(2,684
)
 
—

 
2,684

 
—

 
—

Net income (loss)
—

 
—

 
15,081

 
—

 
—

 
15,081

Effect of derivative financial instruments, net of $410 of taxes
—

 
—

 
—

 
—

 
(669
)
 
(669
)
Balance at December 31, 2014
$
48

 
$
913,619

 
$
115,821

 
$
—

 
$
—

 
$
1,029,488

Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
—

 
—

 
—

 
(1,100
)
 
—

 
(1,100
)
Stock-based compensation
—

 
7,600

 
—

 
—

 
—

 
7,600

Retirement of treasury stock
—

 
(1,100
)
 
—

 
1,100

 
—

 
—

Settlement of convertible notes
—

 
(1,596
)
 
—

 
—

 
—

 
(1,596
)
Net income (loss)
—

 
—

 
(466,626
)
 
—

 
—

 
(466,626
)
Balance at September 30, 2015
$
48

 
$
918,523

 
$
(350,805
)
 
$
—

 
$
—

 
$
567,766

See notes to Unaudited Consolidated Financial Statements.

7

BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

September 30, 2015

1. Organization

Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the "Company"), is an independent oil and gas company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids ("NGLs"). Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company's interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company's Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company's 2014 Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company's financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future cash flows used in determining possible impairments of proved oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining asset retirement obligations, the timing of dry hole costs, impairments of unproved oil and gas properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based compensation awards.

Short-term Investments. Short-term investments have maturities of more than three months and less than one year. The Company's held-to-maturity securities have a carrying value of $20.0 million, which approximates fair value, as of September 30, 2015, and all have maturity dates of less than one year.

Accounts Receivable. Accounts receivable is comprised of the following:

 
As of September 30, 2015
 
As of December 31, 2014
 
(in thousands)
Accrued oil, gas and NGL sales
$
33,018

 
$
35,099

Due from joint interest owners
9,333

 
27,937

Other (1)
1,733

 
49,187

Allowance for doubtful accounts
(14
)
 
(14
)
Total accounts receivable
$
44,070

 
$
112,209


(1)
Other as of December 31, 2014 includes a receivable of $47.6 million (including $4.7 million due to another industry partner) related to a settlement agreement with the Department of Interior resulting in the cancellation of certain Cottonwood Gulch natural gas leases during the three months ended December 31, 2014.

8


Oil and Gas Properties. The Company's oil, gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized and are included within additions to oil and gas properties and remain within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether proved reserves are added or not. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage and other relevant matters.

Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market value, on a first-in, first-out basis.

The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company's oil, natural gas and NGL producing activities:

 
As of September 30, 2015
 
As of December 31, 2014
 
(in thousands)
Proved properties
$
321,201

 
$
390,482

Wells and related equipment and facilities
1,536,447

 
1,537,370

Support equipment and facilities
74,438

 
68,371

Materials and supplies
9,990

 
13,069

Total proved oil and gas properties
$
1,942,076

 
$
2,009,292

Unproved properties
28,514

 
78,898

Wells and facilities in progress
66,699

 
69,936

Total unproved oil and gas properties, excluded from amortization
$
95,213

 
$
148,834

Assets held for sale
64,882

 
9,234

Accumulated depreciation, depletion, amortization and impairment
(875,852
)
 
(427,954
)
Total oil and gas properties, net
$
1,226,319

 
$
1,739,406


The Company reviews proved oil and gas properties on a field-by-field basis for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future net cash flows of its oil and gas properties based on the Company's best estimate of development plans, future production, commodity pricing, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the proved oil and gas properties, no impairment is taken. If the carrying value of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The Company does not believe that the undiscounted future net cash flows analysis of its proved property represents the applicable market value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of

9

reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

The Company recognized non-cash impairment, dry hole costs and abandonment expense in the Unaudited Consolidated Statements of Operations, as follows:
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands)
 
Non-cash impairment of proved oil and gas properties
$
556,291

(1) 
$
11,493

(2) 
$
556,563

(1) 
$
12,531

(2)(3) 
Non-cash impairment of unproved oil and gas properties
15,572

(1) 
15,250

(2) 
15,803

(1) 
15,250

(2) 
Non-cash impairment of inventory
—

 
—

 
—

 
340

 
Dry hole costs
14

 
3

 
(29
)
 
96

 
Abandonment expense and lease expirations
774

 
2,363

 
2,659

 
4,396

 
Total non-cash impairment, dry hole costs and abandonment expense
$
572,651

 
$
29,109

 
$
574,996

 
$
32,613

 

(1)
Due to the continued decline in oil prices, the Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved and unproved oil and gas properties for the three and nine months ended September 30, 2015.
(2)
As a result of the sale or exchange of the majority of the Company's Powder River Basin assets ("Powder River Oil Divestiture") and results of drilling and completion activity in the Paradox Basin during the three months ended September 30, 2014, the remaining carrying values of Powder River Oil and Paradox Basin assets were analyzed relative to their estimated fair market values. As a result, the Company recognized proved and unproved property impairments of $11.5 million and $15.3 million, respectively.
(3)
The amount shown reflects $1.0 million of proved impairment expense that was incurred during the nine months ended September 30, 2014 related to the sale of the Company's West Tavaputs natural gas assets in the Uinta Basin ("West Tavaputs Divestiture") based upon a true up of previously estimated fair value relative to carrying value. These assets were sold in December 2013.

The provision for DD&A of oil and gas properties is calculated on a field-by-field basis using the unit-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.

Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:

 
As of September 30, 2015
 
As of December 31, 2014
 
(in thousands)
Accrued drilling, completion and facility costs
$
49,664

 
$
68,124

Accrued lease operating, gathering, transportation and processing expenses
10,718

 
12,526

Accrued general and administrative expenses
8,695

 
8,482

Accrued interest payable
28,551

 
14,284

Accrued payables for property sales
—

 
16,296

Trade payables and other
13,681

 
6,540

Total accounts payable and accrued liabilities
$
111,309

 
$
126,252


Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.


10

Revenue Recognition. Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenues are recorded on the basis of gas and NGLs actually sold by the Company. In addition, the Company records revenues for its share of gas and NGLs sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenues for other owners' volumetric share of gas and NGLs sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's remaining over- and under-produced gas and NGLs balancing positions are taken into account in determining the Company's proved oil, gas and NGL reserves. Imbalances at September 30, 2015 and 2014 were not material.

Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities and in the Unaudited Consolidated Statements of Operations as commodity derivative gain (loss).

Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. Deferred tax assets are regularly reviewed, considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, taxable strategies and result of recent operations. The assumptions about future taxable income require significant judgment to determine whether it is more likely than not if the deferred tax asset is expected to be realized.

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of September 30, 2015.

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company's common stock and shares into which the Convertible Notes are convertible. No potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the three and nine months ended September 30, 2015 and 2014.

The following table sets forth the calculation of basic and diluted income (loss) per share:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands, except per share amounts)
Net income (loss)
$
(410,314
)
 
$
(34,649
)
 
$
(466,626
)
 
$
(73,984
)
Basic weighted-average common shares outstanding in period
48,340

 
48,060

 
48,280

 
47,983

Add dilutive effects of stock options and nonvested equity shares of common stock
—

 
—

 
—

 
—

Diluted weighted-average common shares outstanding in period
48,340

 
48,060

 
48,280

 
47,983

Basic net income (loss) per common share
$
(8.49
)
 
$
(0.72
)
 
$
(9.67
)
 
$
(1.54
)
Diluted net income (loss) per common share
$
(8.49
)
 
$
(0.72
)
 
$
(9.67
)
 
$
(1.54
)

New Accounting Pronouncements. In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-03, Simplifying the Presentation of Debt Issuance Costs. The objective of this update is to require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for the annual periods

11

beginning after December 15, 2015, and for interim periods within that annual period. The adoption of the pronouncement will not have a significant impact on the Company’s disclosures and financial statements.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The objective of this update is to provide guidance in GAAP about management's responsibility to evaluate whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. The standard will be adopted prospectively.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. In July 2015, the FASB issued a one year deferral of this standard changing the effective date to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact of adopting this standard.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

 
Nine Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Cash paid for interest
$
31,323

 
$
36,267

Cash paid for income taxes
1,052

 
1

Supplemental disclosures of non-cash investing and financing activities:
 
 
 
Accrued liabilities - oil and gas properties
57,699

 
90,381

Change in asset retirement obligations, net of disposals
(241
)
 
(23,327
)
Retirement of treasury stock
(1,100
)
 
(2,462
)
Fair value of properties exchanged in non-cash transactions
—

 
77,078

Relief from lease financing obligation
—

 
36,106


4. Assets Held for Sale

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty the sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less costs to sell.

At September 30, 2015, the Company had a signed purchase and sale agreement in place for certain assets in the Uinta Basin and certain non-core assets in the DJ Basin. In addition, the Company began marketing the remainder of its non-core assets in the DJ Basin during the three months ended September 30, 2015. Therefore, the related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2015. Assets held for sale are recorded at the lesser of their respective carrying value or fair value less estimated costs to sell. The fair value of the assets held for sale was $57.3 million and was presented as oil and gas properties held for sale, net of amortization and impairment, of $64.9 million and liabilities associated with assets held for sale of $7.6 million on the Unaudited Consolidated Balance Sheet as of September 30, 2015.

5. Long-Term Debt

The Company's outstanding debt is summarized below:

12

 
 
 
As of September 30, 2015
 
As of December 31, 2014
 
Maturity Date
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
 
(in thousands)
Amended Credit Facility
April 9, 2020
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Convertible Notes (1)
March 15, 2028 (2)
579

 
—

 
579

 
25,344

 
—

 
25,344

7.625% Senior Notes (3)
October 1, 2019
400,000

 
—

 
400,000

 
400,000

 
—

 
400,000

7.0% Senior Notes (4)
October 15, 2022
400,000

 
—

 
400,000

 
400,000

 
—

 
400,000

Lease Financing Obligation (5)
August 10, 2020
3,330

 
—

 
3,330

 
3,648

 
—

 
3,648

Total Debt
 
$
803,909

 
$
—

 
$
803,909

 
$
828,992

 
$
—

 
$
828,992

Less: Current Portion of Long-Term Debt (6)
 
1,015

 
—

 
1,015

 
25,770

 
—

 
25,770

Total Long-Term Debt
 
$
802,894

 
$
—

 
$
802,894

 
$
803,222

 
$
—

 
$
803,222

 
(1)
The aggregate estimated fair value of the Convertible Notes was approximately $0.6 million and $25.1 million as of September 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments. On March 20, 2015, the holders put 98% of the Convertible Notes to the Company, leaving $0.6 million principal amount remaining.
(2)
The Company has the right at any time, with at least 30 days' notice, to call the remaining Convertible Notes, and the holders have the right to require the Company to purchase the notes on each of March 20, 2018 and March 20, 2023.
(3)
The aggregate estimated fair value of the 7.625% Senior Notes was approximately $292.8 million and $359.8 million as of September 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.
(4)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $257.0 million and $366.0 million as of September 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.2 million as of September 30, 2015 and $3.5 million as of December 31, 2014. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
(6)
The current portion of the long-term debt as of September 30, 2015 and December 31, 2014 includes the current portion of the Lease Financing Obligation and the principal amount of the Convertible Notes.

Amended Credit Facility

On September 23, 2015, the Company entered into a Fourth Amendment (the "Fourth Amendment") to the Third Amended and Restated Credit Agreement dated March 16, 2010 (the "Amended Credit Facility"). The Fourth Amendment, among other things, reaffirmed the current borrowing base at $375.0 million and amended certain financial covenant requirements. On April 9, 2015, the Company entered into a Third Amendment (the "Third Amendment") to the Amended Credit Facility. The Third Amendment amended the definition of "Maturity Date" in the Amended Credit Facility to mean the earliest of (a) April 9, 2020 or (b) the date 181 days prior to the maturity of certain unsecured senior or senior subordinated debt of the Company in existence as of the date of the Third Amendment or that may be incurred by the Company as of a future date, or any permitted refinancing debt in respect thereof. The Amended Credit Facility currently has commitments and a borrowing base of $375.0 million from 13 lenders based on mid-year 2015 reserves and hedge position. Due to the Third Amendment, the Company recognized interest expense of $1.6 million and a loss on extinguishment of debt of $0.8 million on the Unaudited Consolidated Statements of Operations related to the acceleration of deferred financing charges during the nine months ended September 30, 2015. As of September 30, 2015, the Company had no amounts outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of September 30, 2015 to $349.0 million.

Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the unused commitment fee is between 0.375% and 0.5% based on borrowing base utilization. There have not been any borrowings under the Amended Credit Facility in 2015. The average annual interest rate incurred on the Amended Credit Facility was 2.0% and 1.9% for the three and nine months ended September 30, 2014, respectively.

The borrowing base is required to be re-determined at least twice per year, on or about April 1 and October 1, as well as following any material property sales. Future borrowing bases will be computed based on proved oil, natural gas and NGL

13

reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by our lenders, as well as any other outstanding debt of the Company.

The Amended Credit Facility contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants from the time it entered into the facility.

5% Convertible Senior Notes Due 2028

On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. On March 20, 2015, $24.8 million of the remaining outstanding principal amount, or approximately 98% of the remaining outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. The Company settled the notes in cash and recognized a gain on extinguishment of $2.6 million in the Unaudited Consolidated Statements of Operations for the nine months ended September 30, 2015. After the redemption, $0.6 million aggregate principal amount of the Convertible Notes were outstanding as of September 30, 2015. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company's existing and future senior unsecured indebtedness, are senior in right of payment to all of the Company's future subordinated indebtedness, and are effectively subordinated to all of the Company's secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company's subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.

The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company has the right with at least 30 days' notice to call the Convertible Notes.

7.625% Senior Notes Due 2019

On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are redeemable at the Company's option beginning on October 1, 2015 at an initial redemption price of 103.813% of the principal amount of the notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.

7.0% Senior Notes Due 2022

On March 12, 2012, the Company issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at the Company's option beginning on October 15, 2017 at an initial redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.


14

Lease Financing Obligation Due 2020

The Company has a lease financing obligation with a balance of $3.3 million as of September 30, 2015 whereby the Company sold and subsequently leased back certain compressors and related facilities owned by the Company. The Lease Financing Obligation expires on August 10, 2020, and the Company has the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option pursuant to which the Company may purchase the equipment for $1.8 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. See Note 12 for discussion of aggregate minimum future lease payments.

The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, the outstanding Convertible Notes, the 7.625% Senior Notes, the 7.0% Senior Notes and the Lease Financing Obligation along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Amended Credit Facility (1)
 
 
 
Cash interest
$
443

 
$
1,771

 
$
1,313

 
$
4,392

Non-cash interest (2)
$
165

 
$
586

 
$
2,534

 
$
1,757

Convertible Notes (3)
 
 
 
 
 
 
 
Cash interest
$
22

 
$
306

 
$
308

 
$
940

Non-cash interest
$
1

 
$
1

 
$
6

 
$
4

7.625% Senior Notes (4)
 
 
 
 
 
 
 
Cash interest
$
7,625

 
$
7,625

 
$
22,875

 
$
22,875

Non-cash interest
$
267

 
$
273

 
$
813

 
$
817

7.0% Senior Notes (5)
 
 
 
 
 
 
 
Cash interest
$
7,000

 
$
7,000

 
$
21,000

 
$
21,000

Non-cash interest
$
199

 
$
204

 
$
607

 
$
610

Lease Financing Obligation (6)
 
 
 
 
 
 
 
Cash interest
$
27

 
$
248

 
$
84

 
$
765

Non-cash interest
$
—

 
$
3

 
$
24

 
$
11


(1)
Cash interest includes amounts related to interest and commitment fees incurred on the Amended Credit Facility and participation and fronting fees paid on the letter of credit.
(2)
Amount shown for the nine months ended September 30, 2015 includes $1.6 million related to amending the Amended Credit Facility.
(3)
The stated interest rate for the Convertible Notes is 5% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represented the fair value of the equity conversion feature at the time of issue. The stated interest rate of 5% on the Convertible Notes will be the effective interest rate of the $0.6 million remaining principal balance, as the related debt discount was fully amortized as of March 31, 2012.
(4)
The stated interest rate for the 7.625% Senior Notes is 7.625% per annum with an effective interest rate of 8.0% per annum.
(5)
The stated interest rate for the 7.0% Senior Notes is 7.0% per annum with an effective interest rate of 7.2% per annum.
(6)
The effective interest rate for the Lease Financing Obligation is 3.3% per annum. The decrease in cash interest for the three and nine months ended September 30, 2015 compared to the three and nine months ended September 30, 2014 was due to obligations transferring with the sale of natural gas assets in the Piceance Basin during the third quarter of 2014.

6. Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the nine months ended September 30, 2015 is as follows (in thousands):


15


As of December 31, 2014
$
22,852

Liabilities incurred
754

Liabilities settled
(162
)
Disposition of properties
(745
)
Accretion expense
1,091

Revisions to estimate
(88
)
As of September 30, 2015
$
23,702

Less: liabilities associated with assets held for sale
7,641

Less: current asset retirement obligations
1,362

Long-term asset retirement obligations
$
14,699


7. Fair Value Measurements

Assets and Liabilities Measured on a Recurring Basis

The Company's financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 5, approximates its fair value due to its floating rate structure based on the LIBOR spread and the Company's borrowing base utilization.

Fair value is defined 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 (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Given the Company's historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 – Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

The following tables set forth by level within the fair value hierarchy the Company's financial assets and financial liabilities that were measured at fair value on a recurring basis. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.


16

 
As of September 30, 2015
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets
 
 
 
 
 
 
 
Deferred Compensation Plan
$
1,080

 
$
—

 
$
—

 
$
1,080

Cash Equivalents
40,054

 
—

 
—

 
40,054

Commodity Derivatives
—

 
142,056

 
—

 
142,056


 
As of December 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets
 
 
 
 
 
 
 
Deferred Compensation Plan
$
1,069

 
$
—

 
$
—

 
$
1,069

Cash Equivalents
75,066

 
—

 
—

 
75,066

Commodity Derivatives
—

 
195,176

 
—

 
195,176

Liabilities
 
 
 
 
 
 
 
Commodity Derivatives
$
—

 
$
200

 
$
—

 
$
200


The commodity derivatives reflected in the table above and in the Unaudited Consolidated Balance Sheets have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.

Level 1 Fair Value Measurements – The Company maintains a non-qualified deferred compensation plan which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets in the Unaudited Consolidated Balance Sheets. The highly liquid cash equivalents are recorded at carrying value, which approximates fair value, which represent Level 1 inputs. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $549.8 million as of September 30, 2015. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $725.8 million as of December 31, 2014. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

Level 2 Fair Value Measurements – The fair value of crude oil, natural gas and NGL forwards and options are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties' valuations to assess the reasonableness of the Company's valuations.

There is no active, public market for the Amended Credit Facility, Convertible Notes or Lease Financing Obligation. The Amended Credit Facility had a balance of zero as of September 30, 2015 and December 31, 2014. The Convertible Notes fair values of $0.6 million and $25.1 million as of September 30, 2015 and December 31, 2014, respectively, are measured based on market-based parameters of the various components of the Convertible Notes and over the counter trades. The Lease Financing Obligation fair values of $3.2 million and $3.5 million as of September 30, 2015 and December 31, 2014, respectively, are measured based on market-based parameters of comparable term secured financing instruments. The fair value measurements for the Amended Credit Facility, Convertible Notes and Lease Financing Obligation represent Level 2 inputs.

Level 3 Fair Value Measurements – As of September 30, 2015 and December 31, 2014, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy.

Assets and Liabilities Measured on a Non-recurring Basis – Oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. The fair value is determined by

17

using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique which involves calculating the present value of future revenues. The present value, net of estimated operating and development costs, is calculated using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows (all of which are designated as Level 3 inputs within the fair value hierarchy). During the nine months ended September 30, 2015, the Company reduced its Uinta Oil Program assets to a fair value of $180.0 million, resulting in a non-cash impairment charge of $571.9 million.

Properties classified as held for sale are valued using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. The fair value of assets classified as held for sale was $64.9 million as of September 30, 2015.

The following tables set forth by level within the fair value hierarchy the Company's non-financial assets and liabilities that were measured at fair value on a nonrecurring basis as of September 30, 2015.

 
Net Carrying Value as of September 30, 2015
 
Fair Value Measurements Using
 
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Proved property (1)(2)
$
225,363

 
$
—

 
$
—

 
$
225,363

Unproved property (1)(2)
19,519

 
—

 
—

 
19,519


(1)
See Note 2 for additional details on impairment expense recognized.
(2)
Includes $50.3 million of net proved property and $14.6 million of net unproved property associated with properties held for sale as of September 30, 2015. See note 4 for additional details related to assets held for sale.

During the year ended December 31, 2014, the Company recognized impairment on proved and unproved property of $39.8 million. Included in the total impairment charge of $39.8 million was $21.1 million of impairment charges related to the remaining Powder River Basin assets for which the Company utilized third party purchase offers as the basis for determining fair value. This property was classified as held for sale as of December 31, 2014.

The following tables set forth by level within the fair value hierarchy the Company's non-financial assets and liabilities that were measured at fair value on a nonrecurring basis as of December 31, 2014.

 
Net Carrying Value as of December 31, 2014
 
Impairment for the Year Ended December 31, 2014
 
 
Level 1
 
Level 2
 
Level 3
 
(in thousands)
Proved property (1)(2)
$
1,588,038

 
$
—

 
$
—

 
$
15,761

Unproved property (1)(2)
151,368

 
—

 
—

 
24,082


(1)
See Note 2 for additional details on impairment expense recognized.
(2)
Includes $6.7 million of net proved property and $2.5 million of net unproved property associated with properties held for sale as of December 31, 2014.

8. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap contracts related to the sale of a portion of the Company's production. The Company does not enter into derivative instruments for speculative or trading purposes.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The

18

financial impact of physical commodity contracts is included in oil, natural gas and NGL production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sale exception, as mentioned above, are recorded at fair value and included in the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts of all derivative instruments presented in the Unaudited Consolidated Balance Sheets as of the dates indicated.

  
As of September 30, 2015
 
Balance Sheet
Gross Amounts of
Recognized
Derivative Assets
 
Gross Amounts
Offset in the Balance
Sheet
 
Net Amounts of Derivative
Assets Presented in the
Balance Sheet
 
 
(in thousands)
 
Derivative assets (current)
$
109,847

 
$
—

 
$
109,847

 
Derivative assets (noncurrent)
32,209

 
—

 
32,209

 
Total derivative assets
$
142,056

 
$
—

 
$
142,056

 
 
 
 
 
 
 
 
  
As of December 31, 2014
 
Balance Sheet
Gross Amounts of
Recognized
Derivative Assets
 
Gross Amounts
Offset in the Balance
Sheet
 
Net Amounts of Derivative
Assets Presented in the
Balance Sheet
 
 
(in thousands)
 
Derivative assets (current)
$
145,426

 
$
(200
)
(1) 
$
145,226

 
Derivative assets (noncurrent)
49,750

 
—

 
49,750

 
Total derivative assets
$
195,176

 
$
(200
)
 
$
194,976

 
 
Gross Amounts of
Recognized
Derivative
Liabilities
 
Gross Amounts
Offset in the Balance
Sheet
 
Net Amounts of Derivative
Liabilities Presented in
the Balance Sheet
 
 
(in thousands)
 
Derivative liabilities
$
(200
)
 
$
200

(2) 
$
—

 
Total derivative liabilities
$
(200
)
 
$
200

  
$
—

 
 
(1)
Amounts are netted against derivative asset balances with the same counterparty and are therefore, presented as a net asset on the Unaudited Consolidated Balance Sheets.
(2)
Amounts are netted against derivative liability balances with the same counterparty and are therefore, presented as a net liability on the Unaudited Consolidated Balance Sheets.

As of September 30, 2015, the Company had financial derivative instruments in place related to the sale of a portion of the Company's production for the following volumes for the periods indicated:

 
October – December 2015
 
For the year 2016
 
For the year 2017
 
Derivative
Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
Oil (Bbls)
993,600

 
$
89.81

 
2,478,600

 
$
80.47

 
683,250

 
$
75.61

Natural Gas (MMbtu)
1,840,000

 
$
4.13

 
1,830,000

 
$
4.10

 
—

 
$
—


The table below summarizes the commodity derivative gains and losses the Company recognized related to its oil, gas and NGL derivative instruments for the periods indicated:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Commodity derivative gain (loss) settlements on derivatives designated as cash flow hedges (1)
$
—

 
$
351

 
$
—

 
$
889

Total commodity derivative gain (loss) (2)
69,133

 
72,299

 
75,914

 
369


19

 
(1)
Included in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations.
(2)
Included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

The Company's derivative financial instruments are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had derivatives in place with eight different counterparties as of September 30, 2015. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

It is the Company's policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility or affiliates of lenders in the Amended Credit Facility. The Company's derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to the Company under the derivative contracts. Where the counterparty is not a lender under the Company's Amended Credit Facility, it may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.

9. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the three and nine months ended September 30, 2015, the Company had no uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and nine months ended September 30, 2015 and 2014.

At September 30, 2015 the Company recorded a non-cash impairment charge of $571.9 million against its proved and unproved oil and gas properties. Primarily as a result of this non-cash impairment charge the Company was put into a net deferred tax asset position after applying the appropriate and expected jurisdictional tax rates at September 30, 2015. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. Accordingly the Company recorded a valuation allowance of $66.4 million against our net deferred tax asset. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

Income tax benefit for the three and nine months ended September 30, 2015 and 2014 differs from the amounts that would be provided by applying the U.S. statutory income tax rates to pretax income or loss principally due to the effect of deferred tax asset valuation allowances, stock based compensation, political lobbying expense, political contributions, nondeductible officer compensation and state income taxes. For the three and nine months ended September 30, 2015 the effective tax rate decreased as a result of recording a valuation allowance of $66.4 million against the deferred tax asset balance.

10. Equity Incentive Compensation Plans and Other Long-term Incentive Programs

The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).

20


The following table presents the non-cash stock-based compensation related to equity awards for the periods indicated:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Common stock options
$
137

 
$
482

 
$
528

 
$
1,608

Nonvested common stock
1,816

 
1,760

 
5,007

 
4,979

Nonvested common stock units 
250

 
274

 
779

 
783

Nonvested performance-based shares
(50
)
 
955

 
903

 
1,919

Total
$
2,153

 
$
3,471

 
$
7,217

 
$
9,289


Unrecognized compensation cost as of September 30, 2015 was $16.5 million related to grants of nonvested stock options and nonvested shares of common stock that are expected to be recognized over a weighted-average period of 2.1 years.

Nonvested Shares. The following table presents the equity awards granted pursuant to the Company's various stock compensation plans:

 
Three Months Ended September 30, 2015
 
Three Months Ended September 30, 2014
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
Nonvested common stock
32,618

 
$
5.24

 
26,828

 
$
21.53

Nonvested common stock units
5,681

 
$
3.30

 
850

 
$
22.04

Nonvested performance-based shares
—

 
$
—

 
10,073

 
$
18.52

Total shares granted
38,299

 
 
 
37,751

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
Nine Months Ended September 30, 2014
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
Nonvested common stock
664,757

 
$
11.91

 
516,768

 
$
22.49

Nonvested common stock units
130,669

 
$
8.47

 
44,282

 
$
24.98

Nonvested performance-based shares
—

 
$
—

 
303,188

 
$
19.77

Total shares granted
795,426

 
 
 
864,238

 
 

Performance Cash Program

2015 Program. In February 2015, the Compensation Committee approved a performance cash program (the "2015 Program") granting performance cash units that will settle in cash. The performance-based awards contingently vest in May 2018, depending on the level at which the performance goals are achieved. The performance goals, which will be measured over the three year period ending December 31, 2017, consist of the Company's total shareholder return ("TSR") ranking relative to a defined peer group's individual TSRs ("Relative TSR") (weighted at 60%) and the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group's percentage calculation ("DCF per Debt Adjusted Share") (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals will vest at 25% or 50% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of units will be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no units will vest. In any event, the total number of units that could vest will not exceed 200% of the original number of performance cash units granted. At the end of the three year vesting period, any units that have not vested will be forfeited. A total of 409,046 units were granted under this program during the nine months ended September 30, 2015. The Company recognized $0.3 million in derivatives and other noncurrent liabilities in the Unaudited Consolidated Balance Sheets as of September 30, 2015 and a $0.1 million decrease in general and administrative expense and $0.3 million in general and administrative expense in the Unaudited Consolidated Statements of Operations for the three and nine months ended September 30, 2015, respectively, for the 2015 Program.

21


11. Equity Distribution Agreement

On June 10, 2015, the Company entered into an Equity Distribution Agreement (the "Agreement") with Goldman, Sachs and Co. (the "Manager"). Pursuant to the terms of the Agreement, the Company may sell, from time to time through or to the Manager, shares of its common stock having an aggregate gross sales price of up to $100.0 million. Sales of the shares, if any, will be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange, at market prices, in block transactions, to or through a market maker, through an electronic communications network or as otherwise agreed by the Company and the Manager. As of September 30, 2015, no shares have been sold pursuant to the Agreement.

12. Commitments and Contingencies

Lease Financing Obligation. The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below:

 
As of September 30, 2015
 
(in thousands)
2015
$
135

2016
537

2017
537

2018
537

2019
1,825

Thereafter
—

Total
$
3,571


Transportation Charges. The Company is party to two firm transportation contracts to provide capacity on natural gas pipeline systems. The remaining term on these contracts is six years. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. Beginning October 1, 2014, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures during 2013 and 2014, the Company will likely not utilize the firm capacity on the natural gas pipelines.
 
The amounts in the table below represent the Company's future minimum transportation charges.

 
As of September 30, 2015
 
(in thousands)
2015
$
4,576

2016
18,692

2017
18,692

2018
18,692

2019
18,692

Thereafter
29,595

Total
$
108,939


Purchase Commitments. The Company has one take-or-pay purchase agreement for supply of carbon dioxide ("CO2"), which has a total financial commitment of $1.5 million. The CO2 is for use in fracture stimulation operations. Under this contract, the Company is obligated to purchase a minimum volume of CO2 at a set price. If the Company takes delivery of less than the minimum required amount, the Company is responsible for full payment (deficiency payment) in December 2015.

Lease and Other Commitments. The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Additionally, the Company has entered into various long-term agreements for telecommunication services as well as other drilling and throughput commitments.


22

Future minimum annual payments under lease and other agreements are as follows:

 
As of September 30, 2015
 
(in thousands)
2015 (1)(2)
$
2,646

2016
2,995

2017
2,892

2018
2,591

2019
633

Thereafter
—

Total
$
11,757


(1)
Includes a contractual obligation of $1.3 million due October 1, 2015 related to certain drilling commitments on sold properties.
(2)
Includes a sales throughput contract in the South Altamont area of the Uinta Oil Basin. Under this contract, the Company is obligated to sell and deliver a minimum volume commitment ("MVC") of 450.0 MMcf for the period of December 1, 2014 to November 30, 2015. If the minimum volume is not delivered, the Company must make a deficiency payment of up to $0.8 million. As of September 30, 2015, the Company had satisfied approximately 190.2 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.4 million due December 1, 2015.

Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. It is the opinion of the Company's management that current claims and litigation involving the Company are not likely to have a material adverse effect on its Unaudited Consolidated Balance Sheet, Cash Flows or Statements of Operations.

13. Guarantor Subsidiaries

In addition to the Amended Credit Facility, the 7.625% Senior Notes, 7.0% Senior Notes and Convertible Notes, which have been registered under the Securities Act of 1933, are jointly and severally guaranteed on a full and unconditional basis by the Company's 100% owned subsidiaries ("Guarantor Subsidiaries"). Presented below are the Company's unaudited condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) and statements of cash flows, as required by Securities and Exchange Commission ("SEC") Rule 3-10 of Regulation S-X.

During the six months ended June 30, 2014, Bill Barrett Corporation, as parent, merged two of the Company's 100% owned subsidiaries, CBM Production Company and GB Acquisition Corporation, into the parent company. During the six months ended June 30, 2015, Bill Barrett Corporation, as parent, merged another 100% owned subsidiary, Elk Production Uintah, LLC, into the parent company. The unaudited condensed consolidating financial statements reflect the new guarantor structure for all periods presented.

The following unaudited condensed consolidating financial statements have been prepared from the Company's financial information on the same basis of accounting as the Unaudited Consolidated Financial Statements. Investments in the subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Company and the Guarantor Subsidiaries are reflected in the intercompany eliminations column.

Condensed Consolidating Balance Sheets


23

 
As of September 30, 2015
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Current assets
$
270,062

 
$
78

 
$
—

 
$
270,140

Property and equipment, net
1,232,180

 
6,767

 
—

 
1,238,947

Intercompany receivable (payable)
21,416

 
(21,416
)
 
—

 
—

Investment in subsidiaries
(14,716
)
 
—

 
14,716

 
—

Noncurrent assets
87,173

 
—

 
—

 
87,173

Total assets
$
1,596,115

 
$
(14,571
)
 
$
14,716

 
$
1,596,260

Liabilities and Stockholders' Equity:
 
 
 
 
 
 
 
Current liabilities
$
200,120

 
$
94

 
$
—

 
$
200,214

Long-term debt
802,894

 
—

 
—

 
802,894

Other noncurrent liabilities
25,335

 
51

 
—

 
25,386

Stockholders' equity
567,766

 
(14,716
)
 
14,716

 
567,766

Total liabilities and stockholders' equity
$
1,596,115

 
$
(14,571
)
 
$
14,716

 
$
1,596,260

 
 
As of December 31, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Current assets
$
426,103

 
$
2

 
$
—

 
$
426,105

Property and equipment, net
1,730,074

 
23,047

 
—

 
1,753,121

Intercompany receivable (payable)
22,840

 
(22,840
)
 
—

 
—

Investment in subsidiaries
163

 
—

 
(163
)
 
—

Noncurrent assets
65,258

 
—

 
—

 
65,258

Total assets
$
2,244,438

 
$
209

 
$
(163
)
 
$
2,244,484

Liabilities and Stockholders' Equity:
 
 
 
 
 
 
 
Current liabilities
$
264,687

 
$
—

 
$
—

 
$
264,687

Long-term debt
803,222

 
—

 
—

 
803,222

Deferred income taxes
122,350

 
—

 
—

 
122,350

Other noncurrent liabilities
24,691

 
46

 
—

 
24,737

Stockholders' equity
1,029,488

 
163

 
(163
)
 
1,029,488

Total liabilities and stockholders' equity
$
2,244,438

 
$
209

 
$
(163
)
 
$
2,244,484


24


Condensed Consolidating Statements of Operations 

 
Three Months Ended September 30, 2015
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
49,562

 
$
117

 
$
—

 
$
49,679

Operating expenses
(630,783
)
 
(14,929
)
 
—

 
(645,712
)
General and administrative
(11,025
)
 
—

 
—

 
(11,025
)
Interest income and other income (expense)
53,479

 
—

 
—

 
53,479

Income (loss) before income taxes and equity in earnings of subsidiaries
(538,767
)
 
(14,812
)
 
—

 
(553,579
)
(Provision for) Benefit from income taxes
143,265

 
—

 
—

 
143,265

Equity in earnings (loss) of subsidiaries
(14,812
)
 
—

 
14,812

 
—

Net income (loss)
$
(410,314
)
 
$
(14,812
)
 
$
14,812

 
$
(410,314
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
160,963

 
$
368

 
$
—

 
$
161,331

Operating expenses
(779,377
)
 
(15,247
)
 
—

 
(794,624
)
General and administrative
(39,026
)
 
—

 
—

 
(39,026
)
Interest income and other income (expense)
28,608

 
—

 
—

 
28,608

Income (loss) before income taxes and equity in earnings of subsidiaries
(628,832
)
 
(14,879
)
 
—

 
(643,711
)
(Provision for) Benefit from income taxes
177,085

 
—

 
—

 
177,085

Equity in earnings (loss) of subsidiaries
(14,879
)
 
—

 
14,879

 
—

Net income (loss)
$
(466,626
)
 
$
(14,879
)
 
$
14,879

 
$
(466,626
)


25

 
Three Months Ended September 30, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
135,263

 
$
—

 
$
—

 
$
135,263

Operating expenses
(235,123
)
 
(62
)
 
—

 
(235,185
)
General and administrative
(11,111
)
 
—

 
—

 
(11,111
)
Interest and other income (expense)
54,530

 
—

 
—

 
54,530

Income (loss) before income taxes and equity in earnings of subsidiaries
(56,441
)
 
(62
)
 
—

 
(56,503
)
(Provision for) Benefit from income taxes
21,854

 
—

 
—

 
21,854

Equity in earnings of subsidiaries
(62
)
 
—

 
62

 
—

Net income (loss)
$
(34,649
)
 
$
(62
)
 
$
62

 
$
(34,649
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
405,398

 
$
(9
)
 
$
—

 
$
405,389

Operating expenses
(429,560
)
 
(192
)
 
—

 
(429,752
)
General and administrative
(41,039
)
 
—

 
—

 
(41,039
)
Interest and other income (expense)
(51,960
)
 
35

 
—

 
(51,925
)
Income (loss) before income taxes and equity in earnings of subsidiaries
(117,161
)
 
(166
)
 
—

 
(117,327
)
(Provision for) Benefit from income taxes
43,343

 
—

 
—

 
43,343

Equity in earnings (loss) of subsidiaries
(166
)
 
—

 
166

 
—

Net income (loss)
$
(73,984
)
 
$
(166
)
 
$
166

 
$
(73,984
)

Condensed Consolidating Statements of Comprehensive Income (Loss)
 
 
Three Months Ended September 30, 2015
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(410,314
)
 
$
(14,812
)
 
$
14,812

 
$
(410,314
)
Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
Effect of derivative financial instruments
—

 
—

 
—

 
—

Other comprehensive income (loss)
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(410,314
)
 
$
(14,812
)
 
$
14,812

 
$
(410,314
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2015
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(466,626
)
 
$
(14,879
)
 
$
14,879

 
$
(466,626
)
Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
Effect of derivative financial instruments
—

 
—

 
—

 
—

Other comprehensive income (loss)
—

 
—

 
—

 
—

Comprehensive income (loss)
$
(466,626
)
 
$
(14,879
)
 
$
14,879

 
$
(466,626
)


26

 
Three Months Ended September 30, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(34,649
)
 
$
(62
)
 
$
62

 
$
(34,649
)
Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
Effect of derivative financial instruments
(219
)
 
—

 
—

 
(219
)
Other comprehensive income (loss)
(219
)
 
—

 
—

 
(219
)
Comprehensive income (loss)
$
(34,868
)
 
$
(62
)
 
$
62

 
$
(34,868
)
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(73,984
)
 
$
(166
)
 
$
166

 
$
(73,984
)
Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
Effect of derivative financial instruments
(555
)
 
—

 
—

 
(555
)
Other comprehensive income (loss)
(555
)
 
—

 
—

 
(555
)
Comprehensive income (loss)
$
(74,539
)
 
$
(166
)
 
$
166

 
$
(74,539
)

Condensed Consolidating Statements of Cash Flows
 
 
Nine Months Ended September 30, 2015
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Cash flows from operating activities
$
165,911

 
$
(10
)
 
$
—

 
$
165,901

Cash flows from investing activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
(257,399
)
 
1,340

 
—

 
(256,059
)
Additions to furniture, fixtures and other
(1,036
)
 
—

 
—

 
(1,036
)
Proceeds from sale of properties and other investing activities
66,617

 
—

 
—

 
66,617

Cash paid for short-term investments
(114,883
)
 
—

 
—

 
(114,883
)
Proceeds from sale of short-term investments
95,000

 
—

 
—

 
95,000

Intercompany transfers
1,330

 
—

 
(1,330
)
 
—

Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from debt
—

 
—

 
—

 
—

Principal payments on debt
(25,083
)
 
—

 
—

 
(25,083
)
Intercompany transfers
—

 
(1,330
)
 
1,330

 
—

Other financing activities
(3,525
)
 
—

 
—

 
(3,525
)
Change in cash and cash equivalents
(73,068
)
 
—

 
—

 
(73,068
)
Beginning cash and cash equivalents
165,904

 
—

 
—

 
165,904

Ending cash and cash equivalents
$
92,836

 
$
—

 
$
—

 
$
92,836

 

27

 
Nine Months Ended September 30, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Cash flows from operating activities
$
231,274

 
$
28

 
$
—

 
$
231,302

Cash flows from investing activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
(419,268
)
 
(6,710
)
 
—

 
(425,978
)
Additions to furniture, fixtures and other
(2,110
)
 
—

 
—

 
(2,110
)
Proceeds from sale of properties and other investing activities
555,926

 
1,821

 
—

 
557,747

Intercompany transfers
(4,861
)
 
—

 
4,861

 
—

Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from debt
165,000

 
—

 
—

 
165,000

Principal payments on debt
(283,442
)
 
—

 
—

 
(283,442
)
Intercompany transfers
—

 
4,861

 
(4,861
)
 
—

Other financing activities
(2,336
)
 
—

 
—

 
(2,336
)
Change in cash and cash equivalents
240,183

 
—

 
—

 
240,183

Beginning cash and cash equivalents
54,595

 
—

 
—

 
54,595

Ending cash and cash equivalents
$
294,778

 
$
—

 
$
—

 
$
294,778

  
14. Subsequent Events

On October 21, 2015, the Company entered into a purchase and sale agreement for the sale of the Company’s remaining non-core assets in the DJ Basin. Total consideration, prior to customary closing adjustments, was $23.0 million. The transaction is expected to close by the end of 2015. The related assets and liabilities were classified as held for sale in the Unaudited Consolidated Balance Sheet as of September 30, 2015.


28

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

This Quarterly Report on Form 10-Q contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements as to our future plans, estimates, beliefs and expected performance. Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, risks and uncertainties relating to:

•
potential failure to achieve expected production from existing and future exploration or development projects or acquisitions;
•
volatility of market prices received for oil, natural gas and natural gas liquids ("NGLs"), and the risk of a prolonged period of depressed prices;
•
derivative and hedging activities;
•
legislative, judicial or regulatory changes including initiatives related to drilling and completion techniques such as hydraulic fracturing;
•
solely operating in the Rocky Mountain region;
•
compliance with environmental and other regulations;
•
economic and competitive conditions;
•
occurrence of property divestitures or acquisitions;
•
costs and availability of third party facilities for gathering, processing, refining and transportation;
•
future processing volumes and pipeline throughput;
•
impact of health and safety issues on operations;
•
operational risks, including industrial accidents and natural disasters;
•
reductions in the borrowing base under our amended revolving credit facility (the "Amended Credit Facility");
•
debt and equity market conditions;
•
ability to receive drilling and other permits, regulatory approvals and required surface access and rights of way;
•
higher than expected costs and expenses including production, drilling and well equipment costs;
•
declines in the values of our oil and natural gas properties resulting in impairments;
•
changes in estimates of proved reserves;
•
the potential for production decline rates from our wells, or drilling and related costs, to be greater than we expect;
•
ability to replace natural production declines with acquisitions, new drilling or recompletion activities;
•
exploration risks such as drilling unsuccessful wells;
•
capital expenditures and other contractual obligations;
•
liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;
•
changes in tax laws and statutory tax rates; and
•
other uncertainties, including those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2014 under the "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" sections and in Item 1A, "Risk Factors" of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management's views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

Overview

We were formed in January 2002 and are incorporated in the State of Delaware. We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for protection of health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.

We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration

29

and development activities meet stakeholders' expectations and regulatory requirements.

Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, other indebtedness, and/or debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.

Because of our growth through acquisitions and, more recently, development of our properties, sales of properties in 2012, 2013, 2014 and 2015, and with the decline in commodity prices, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not indicative of future results.

Commodity prices are inherently volatile and are influenced by many factors outside of our control. We plan our activities and capital budget using internally generated management estimates regarding sales price assumptions and our existing hedge position. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month to 18-month basis using a combination of swaps and other financial derivative instruments. We currently have hedged approximately 80% of our expected remaining 2015 production and approximately 40% our expected 2016 production at price levels that provide some economic certainty.

We operate in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of our operations are conducted in the Rocky Mountain region of the United States. Consequently, we currently report a single reportable segment.

Results of Operations

The following table sets forth selected operating data for the periods indicated:

30

Three Months Ended September 30, 2015 Compared with Three Months Ended September 30, 2014
 
 
Three Months Ended September 30,
 
Increase (Decrease)
2015
 
2014
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating and Other Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
48,799

 
$
134,342

 
$
(85,543
)
 
(64
)%
Other
880

 
921

 
(41
)
 
(4
)%
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
9,638

 
16,284

 
(6,646
)
 
(41
)%
Gathering, transportation and processing expense (1)
684

 
10,784

 
(10,100
)
 
(94
)%
Production tax expense
3,670

 
10,495

 
(6,825
)
 
(65
)%
Exploration expense
20

 
23

 
(3
)
 
(13
)%
Impairment, dry hole costs and abandonment expense
572,651

 
29,109

 
543,542

 
*nm

(Gain) Loss on divestitures
(77
)
 
99,466

 
(99,543
)
 
(100
)%
Depreciation, depletion and amortization
54,738

 
69,024

 
(14,286
)
 
(21
)%
Unused commitments (1)
4,388

 
—

 
4,388

 
*nm

General and administrative expense (2)
9,018

 
7,591

 
1,427

 
19
 %
Long-term cash and equity incentive compensation (2)
2,007

 
3,520

 
(1,513
)
 
(43
)%
Total operating expenses
$
656,737

 
$
246,296

 
$
410,441

 
167
 %
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
1,066

 
1,107

 
(41
)
 
(4
)%
Natural gas (MMcf)
2,214

 
6,834

 
(4,620
)
 
(68
)%
NGLs (MBbls)
264

 
408

 
(144
)
 
(35
)%
Combined volumes (MBoe)
1,699

 
2,654

 
(955
)
 
(36
)%
Daily combined volumes (Boe/d)
18,467

 
28,848

 
(10,381
)
 
(36
)%
Average Realized Prices Before Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
38.71

 
$
82.83

 
$
(44.12
)
 
(53
)%
Natural gas (per Mcf)
2.08

 
4.24

 
(2.16
)
 
(51
)%
NGLs (per Bbl)
11.17

 
32.65

 
(21.48
)
 
(66
)%
Combined (per Boe)
28.73

 
50.48

 
(21.75
)
 
(43
)%
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
79.15

 
$
79.98

 
$
(0.83
)
 
(1
)%
Natural gas (per Mcf)
3.36

 
4.27

 
(0.91
)
 
(21
)%
NGLs (per Bbl)
11.17

 
33.19

 
(22.02
)
 
(66
)%
Combined (per Boe)
55.77

 
49.46

 
6.31

 
13
 %
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
5.67

 
$
6.14

 
$
(0.47
)
 
(8
)%
Gathering, transportation and processing expense (1)
0.40

 
4.06

 
(3.66
)
 
(90
)%
Production tax expense
2.16

 
3.95

 
(1.79
)
 
(45
)%
Depreciation, depletion and amortization
32.22

 
26.01

 
6.21

 
24
 %
General and administrative expense (3)
5.31

 
2.86

 
2.45

 
86
 %

*
Not meaningful.
(1)
Subsequent to the Piceance Divestiture on September 30, 2014, gathering, transportation and processing expense excludes demand charges associated with unused transportation contracts not included in the sale of certain gas assets during 2013 and 2014. We will continue to incur monthly demand charges of approximately $1.5 million for the remaining term ending July 31, 2021, and these costs are included in unused commitments in the Unaudited Consolidated Statements of Operations.
(2)
Long-term cash and equity incentive compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $11.0 million and $11.1 million for the three months ended September 30, 2015

31

and 2014, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of long-term cash and equity incentive compensation from general and administrative expense allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with cash performance compensation programs and stock-based grants.
(3)
Excludes long-term cash and equity incentive compensation as described in Note 2 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including long-term cash and equity incentive compensation, as presented in the Unaudited Consolidated Statements of Operations, were $6.49 and $4.19 for the three months ended September 30, 2015 and 2014, respectively.

Production Revenues and Volumes. Production revenues decreased to $48.8 million for the three months ended September 30, 2015 from $134.3 million for the three months ended September 30, 2014. The decrease in production revenues was due to a 36% decrease in production volumes and a 43% decrease in average realized prices before hedging. The decrease in production volumes reduced production revenues by approximately $27.4 million, while the decrease in average prices reduced production revenues by approximately $58.1 million.

Total production volumes of 1.7 MMBoe for the three months ended September 30, 2015 decreased from 2.7 MMBoe for the three months ended September 30, 2014. The decrease is primarily related to the sale of our natural gas assets in the Piceance Basin (the "Piceance Divestiture") completed in the third quarter of 2014 and the sale of our oil assets in the Powder River Basin (the "Powder River Oil Divestitures") in the third quarter of 2014 and the first quarter of 2015. These decreases were partially offset by a 72% overall increase in DJ Basin production. Additional information concerning production is in the following table:

 
Three Months Ended September 30, 2015
 
Three Months Ended September 30, 2014
 
% Increase (Decrease)
 
Oil
NGL
Natural
Gas
Total
 
Oil
NGL
Natural
Gas
Total
 
Oil
NGL
Natural
Gas
Total
 
(MBbls)
(MBbls)
(MMcf)
(MBoe)
 
(MBbls)
(MBbls)
(MMcf)
(MBoe)
 
(MBbls)
(MBbls)
(MMcf)
(MBoe)
DJ Basin
762

246

1,818

1,311

 
444

116

1,206

761

 
72
 %
112
 %
51
 %
72
 %
Uinta Oil Program
303

18

384

385

 
489

32

630

626

 
(38
)%
(44
)%
(39
)%
(38
)%
Other (1)
1

—

12

3

 
174

260

4,998

1,267

 
(99
)%
*nm

(100
)%
(100
)%
Total
1,066

264

2,214

1,699

 
1,107

408

6,834

2,654

 
(4
)%
(35
)%
(68
)%
(36
)%

*
Not meaningful.
(1)
Includes oil, NGL and natural gas volumes of 60 MBbls, 253 MBbls and 4,794 MMcf, respectively, from the Piceance Basin and 113 MBbls, 7 MBbls and 198 MMcf, respectively, from the Powder River Basin for the three months ended September 30, 2014.

Hedging Activities. During the three months ended September 30, 2015, approximately 93% of our oil volumes and 83% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $43.1 million and natural gas income of $2.8 million after settlements for all commodity derivatives. The $45.9 million gain on settlements for the three months ended September 30, 2015 was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

During the three months ended September 30, 2014, approximately 88% of our oil volumes, 88% of our natural gas volumes and 23% of our NGL related volumes were subject to financial hedges, which resulted in a decrease in oil income of $3.2 million partially offset by an increase in natural gas income of $0.2 million and NGL income of $0.2 million after settlements for all commodity derivatives. Of the $2.7 million loss on total settlements for the three months ended September 30, 2014, a gain of $0.4 million was included in oil, gas and NGL production revenues and a loss of $3.1 million was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

Other Operating Revenues. Other operating revenues remained consistent at $0.9 million for the three months ended September 30, 2015 and for the three months ended September 30, 2014. Other operating revenues for the three months ended September 30, 2015 consisted of $0.5 million related to gathering and compression fees received from third parties and $0.4 million related to the sale of seismic data.

Other operating revenues for the three months ended September 30, 2014 consisted of income from gathering and compression fees received from third parties.


32

Lease Operating Expense ("LOE"). LOE decreased to $5.67 per Boe for the three months ended September 30, 2015 from $6.14 per Boe for the three months ended September 30, 2014. LOE on a per Boe basis is inherently higher for our oil producing properties such as those in our Uinta and DJ Basin development areas. However, the decrease per Boe for the three months ended September 30, 2015 compared with the three months ended September 30, 2014 is primarily related to operational efficiencies, a decrease in service industry costs, reduced workover activity in the Uinta Basin and our decision to shut-in certain Uinta Basin wells due to the current commodity price environment.

Gathering, Transportation and Processing Expense ("GTP"). GTP expense decreased to $0.40 per Boe for the three months ended September 30, 2015 from $4.06 per Boe for the three months ended September 30, 2014. GTP expense on a per Boe basis decreased due to inherently lower GTP expense from our oil producing properties in the Uinta and DJ Basin development areas and due to the sale of natural gas properties with higher GTP expense per Boe in the Piceance Divestiture. In addition, beginning October 1, 2014, costs associated with unused firm natural gas pipeline transportation contracts have been included in unused commitments in the Unaudited Consolidated Statements of Operations. See "Unused Commitments" below for further information.

Production Tax Expense. Total production taxes decreased to $3.7 million for the three months ended September 30, 2015 from $10.5 million for the three months ended September 30, 2014. The overall decrease in production tax expense is related to the Piceance Divestiture and the Powder River Oil Divestitures and a 43% decrease in average realized prices before hedging. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 7.5% and 7.8% for the three months ended September 30, 2015 and September 30, 2014, respectively.

Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the three months ended September 30, 2015 and 2014 is summarized below:

 
Three Months Ended September 30,
 
 
2015
 
2014
 
 
(in thousands)
 
Non-cash impairment of proved oil and gas properties
$
556,291

(1) 
$
11,493

(2) 
Non-cash impairment of unproved oil and gas properties
15,572

(1) 
15,250

(2) 
Dry hole expense
14

 
3

 
Abandonment expense/ Lease expirations
774

 
2,363

 
Total non-cash impairment, dry hole costs and abandonment expense
$
572,651

 
$
29,109

 

(1)
Due to the continued decline in oil prices, we recognized a non-cash impairment charge associated with the proved and unproved oil and gas properties in the Uinta Oil Program for the three months ended September 30, 2015.
(2)
As a result of the sale or exchange of the majority of our Powder River Basin assets ("Powder River Oil Divestiture") and results of drilling and completion activity in the Paradox Basin during the three months ended September 30, 2014, the remaining carrying values of Powder River Oil and Paradox Basin assets were analyzed relative to their estimated fair market values. As a result, we recognized proved and unproved property impairments of $11.5 million and $15.3 million, respectively.

Given the decline in current and future commodity prices, we will continue to review our acreage position and future drilling plans. In addition, we will assess the carrying value of our properties relative to their estimated future net cash flows. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date. If commodity prices and actual operating results vary from management estimates, we may incur additional non-cash property impairments in future periods, which could have a material adverse effect on our results of operations in the period taken.


33

Our current recoverability test on our existing DJ Basin properties as of September 30, 2015 uses commodity pricing based on a combination of assumptions management uses in its budgeting and forecasting process adjusted for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of September 30, 2015 results in a surplus of future estimated net cash flows over carrying value of approximately $554.0 million. We estimate that the surplus in the DJ Basin would decrease by approximately $45.0 million to $50.0 million for every $1.00 decrease in future oil prices. If impairment is necessary then we would reduce the carrying value to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates used by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.

Due to the impairment to the Uinta Oil Program proved and unproved oil and gas properties during the three months ended September 30, 2015 as discussed above, we believe the carrying value of the Uinta Oil Program approximates the fair value.

In addition to future impairments of the carrying value of our proved oil and gas properties, we may also incur reserve write-downs related to the continued decline in commodity prices. As of December 31, 2014, we had proved reserves of 122.3 MMBoe based on SEC pricing of $94.99 per barrel of oil and $4.35 per MMBtu of natural gas. Using estimated year-end 2015 pricing of $50.00 per barrel of oil and $2.75 per MMBtu of natural gas, we could lose approximately 50% of our proved reserves. This reduction in proved reserves includes approximately 65% of our proved undeveloped ("PUD") locations. In addition to the continued decline in commodity prices, actual 2015 reserves will be impacted by many other variables including, but not limited to, production of existing reserves, extensions, discoveries and improved recovery, quantity revisions, changes in future operating and development costs, along with any purchase or sales of reserves in place. Based on our internal mid-year 2015 reserves forecast and preliminary 2015 year end reserve estimates, we believe that the reduction in proved reserves will more likely be in the 30% - 40% range as a result of changes to proved reserves from the other variables mentioned above rather than 50% solely related to commodity pricing. We believe that we have adequate liquidity to develop the remaining PUDs in our five year drilling plan.


Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $54.7 million for the three months ended September 30, 2015 compared with $69.0 million for the three months ended September 30, 2014. The decrease of $14.3 million was a result of a 36% decrease in production for the three months ended September 30, 2015 compared with the three months ended September 30, 2014 primarily due to the Piceance Divestiture and Powder River Oil Divestitures, partially offset by an increase in the DD&A rate. The decrease in production accounted for a $24.9 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $10.6 million of additional DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended September 30, 2015, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $32.22 per Boe compared with $26.01 per Boe for the three months ended September 30, 2014. The increase in the DD&A rate during the three months ended September 30, 2015 compared with the three months ended September 30, 2014 was due to an increase in oil development, which has higher capital costs per Boe compared to natural gas development, and due to the sale of natural gas properties in the Piceance Divestiture which had lower capital costs per Boe compared to oil development. Due to the continued decline in oil prices, we recognized a non-cash impairment charge associated with the proved oil and gas properties in the Uinta Oil Program for the three months ended September 30, 2015. As a result of the impairment, management believes future depletion rates will be lower; however, the future rates will be adjusted to reflect capital expenditures, proved reserve changes, well performance and any additional proved property impairments or properties that may be sold.

Unused Commitments. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of the previous divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Unaudited Consolidated

34

Statements of Operations. Unused commitments expense for the three months ended September 30, 2015 included $4.4 million related to these contracts.

General and Administrative Expense. General and administrative expense, excluding long-term cash and equity compensation, increased to $9.0 million for the three months ended September 30, 2015 from $7.6 million for the three months ended September 30, 2014 primarily due to an increase in employee compensation and benefits. General and administrative expense, excluding long-term cash and equity compensation, is a non-GAAP measure. See Note 2 to the table on page 31 for a reconciliation and explanation.

Long-term cash and equity incentive compensation for the three months ended September 30, 2015 and 2014 were $2.0 million and $3.5 million, respectively. The components of long-term cash and equity incentive compensation for the three months ended September 30, 2015 and 2014 are shown in the following table:

 
Three Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Stock options and nonvested shares of common stock
$
2,153

 
$
3,395

Shares issued for 401(k) plan (1)
—

 
106

Shares issued for directors' fees
18

 
19

Performance cash units (2)
(164
)
 
—

Total
$
2,007

 
$
3,520


(1)
Beginning in the second quarter of 2015, the employer matching contribution to the employees 401(k) account was paid entirely in cash.
(2)
The performance cash units will be settled in cash for the performance metrics that are met. The fair value share price used to determine the inception to date performance cash unit expense decreased to $3.40 for the three months ended September 30, 2015 from $8.92 for the three months ended June 30, 2015. No performance cash units were granted during 2014.

Interest Expense. Interest expense decreased to $15.8 million for the three months ended September 30, 2015 from $18.0 million for the three months ended September 30, 2014. The decrease for the three months ended September 30, 2015 was primarily due to our use of the proceeds from the Piceance Divestiture to reduce the average debt balance. Our weighted average interest rate for the three months ended September 30, 2015 was 7.8% compared to 6.3% for the three months ended September 30, 2014. The increase in the average interest rate for the three months ended September 30, 2015 was due to paying down our Amended Credit Facility and our Convertible Notes, both of which have lower interest rates than our remaining bonds.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $69.1 million for the three months ended September 30, 2015 compared with a gain of $72.3 million for the three months ended September 30, 2014. The gain or loss on commodity derivatives is related to fluctuations of oil, natural gas and NGL future pricing compared to actual pricing of commodity hedges in place as of September 30, 2015 and 2014 or during the periods then ended.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:

 
Three Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges (1)
$
45,936

 
$
(3,054
)
Unrealized gain (loss) on derivatives not designated as cash flow hedges (1)
23,197

 
75,353

Total commodity derivative gain (loss)
$
69,133

 
$
72,299


(1)
Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better

35

understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

Income Tax (Expense) Benefit. Income tax benefit totaled $143.3 million for the three months ended September 30, 2015 compared with income tax benefit of $21.9 million for the three months ended September 30, 2014, resulting in effective tax rates of 25.9% and 38.7%, respectively. For the three months ended September 30, 2015 the significant increase in the tax benefit was a result of recognizing a $571.9 million non-cash impairment charge against our Uinta Oil Program's proved and unproved oil and gas properties, increasing our projected 2015 pretax loss. Our increased projected 2015 pretax loss puts us in a net deferred tax asset position, before any valuation allowance, at September 30, 2015. In regard to our net deferred tax asset position we considered all available evidence in assessing the need for a valuation allowance against the deferred tax asset. We recorded a $66.4 million valuation allowance for the three months ended September 30, 2015. The valuation allowance decreased our effective tax rate by 12.0% for the three months ended September 30, 2015. Additionally for both the 2015 and 2014 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as the effect of state income taxes.


36

Nine Months Ended September 30, 2015 Compared with Nine Months Ended September 30, 2014

 
Nine Months Ended September 30,
 
Increase (Decrease)
2015
 
2014
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating and Other Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
158,667

 
$
397,731

 
$
(239,064
)
 
(60
)%
Other
2,664

 
7,658

 
(4,994
)
 
(65
)%
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
34,834

 
48,367

 
(13,533
)
 
(28
)%
Gathering, transportation and processing expense (1)
2,559

 
34,238

 
(31,679
)
 
(93
)%
Production tax expense
10,020

 
27,770

 
(17,750
)
 
(64
)%
Exploration expense
145

 
442

 
(297
)
 
(67
)%
Impairment, dry hole costs and abandonment expense
574,996

 
32,613

 
542,383

 
*nm

(Gain) Loss on divestitures
(759
)
 
96,896

 
(97,655
)
 
(101
)%
Depreciation, depletion and amortization
159,666

 
189,426

 
(29,760
)
 
(16
)%
Unused commitments (1)
13,163

 
—

 
13,163

 
*nm

General and administrative expense (2)
31,200

 
31,408

 
(208
)
 
(1
)%
Long-term cash and equity incentive compensation (2)
7,826

 
9,631

 
(1,805
)
 
(19
)%
Total operating expenses
$
833,650

 
$
470,791

 
$
362,859

 
77
 %
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
3,311

 
3,056

 
255

 
8
 %
Natural gas (MMcf)
5,772

 
19,950

 
(14,178
)
 
(71
)%
NGLs (MBbls)
635

 
1,330

 
(695
)
 
(52
)%
Combined volumes (MBoe)
4,908

 
7,711

 
(2,803
)
 
(36
)%
Daily combined volumes (Boe/d)
17,978

 
28,245

 
(10,267
)
 
(36
)%
Average Realized Prices Before Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
41.54

 
$
84.04

 
$
(42.50
)
 
(51
)%
Natural gas (per Mcf)
2.31

 
4.83

 
(2.52
)
 
(52
)%
 NGLs (per Bbl)
12.24

 
32.80

 
(20.56
)
 
(63
)%
 Combined (per Boe)
32.33

 
51.47

 
(19.14
)
 
(37
)%
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
77.93

 
$
79.52

 
$
(1.59
)
 
(2
)%
Natural gas (per Mcf)
3.76

 
4.50

 
(0.74
)
 
(16
)%
NGLs (per Bbl)
12.24

 
32.61

 
(20.37
)
 
(62
)%
Combined (per Boe)
58.58

 
48.78

 
9.80

 
20
 %
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
7.10

 
$
6.27

 
$
0.83

 
13
 %
Gathering, transportation and processing expense (1)
0.52

 
4.44

 
(3.92
)
 
(88
)%
Production tax expense
2.04

 
3.60

 
(1.56
)
 
(43
)%
Depreciation, depletion and amortization
32.53

 
24.57

 
7.96

 
32
 %
General and administrative expense (3)
6.36

 
4.07

 
2.29

 
56
 %

*
Not meaningful.
(1)
Subsequent to the Piceance Divestiture on September 30, 2014, gathering, transportation and processing expense excludes demand charges associated with unused transportation contracts not included in the sale of certain gas assets during 2013 and 2014. We will continue to incur monthly demand charges of approximately $1.5 million for the remaining term ending July 31, 2021, and these costs are included in unused commitments in the Unaudited Consolidated Statements of Operations.

37

(2)
Long-term cash and equity incentive compensation is presented herein as a separate line item but is combined with general and administrative expense for a total of $39.0 million and $41.0 million for the nine months ended September 30, 2015 and 2014, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of long-term cash and equity incentive compensation from general and administrative expense allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with cash performance compensation programs and stock-based grants.
(3)
Excludes long-term cash and equity incentive compensation as described in Note 2 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including long-term cash and equity incentive compensation, as presented in the Unaudited Consolidated Statements of Operations, were $7.95 and $5.32 for the nine months ended September 30, 2015 and 2014, respectively.

Production Revenues and Volumes. Production revenues decreased to $158.7 million for the nine months ended September 30, 2015 from $397.7 million for the nine months ended September 30, 2014. The decrease in production revenues was due to a 36% decrease in production volumes and a 37% decrease in average realized prices before hedging. The decrease in production volumes reduced production revenues by approximately $90.6 million, while the decrease in average realized prices before hedging decreased production revenues by approximately $148.4 million.

Total production volumes of 4.9 MMBoe for the nine months ended September 30, 2015 decreased from 7.7 MMBoe for the nine months ended September 30, 2014. The decrease is primarily related to the Piceance Divestiture and Powder River Oil Divestitures, partially offset by a 76% overall increase in DJ Basin production. Additional information concerning production is in the following table:

 
Nine Months Ended September 30, 2015
 
Nine Months Ended September 30, 2014
 
% Increase (Decrease)
 
Oil
NGL
Natural
Gas
Total
 
Oil
NGL
Natural
Gas
Total
 
Oil
NGL
Natural
Gas
Total
 
(MBbls)
(MBbls)
(MMcf)
(MBoe)
 
(MBbls)
(MBbls)
(MMcf)
(MBoe)
 
(MBbls)
(MBbls)
(MMcf)
(MBoe)
DJ Basin
2,198

569

4,410

3,502

 
1,177

308

3,018

1,988

 
87
 %
85
 %
46
 %
76
 %
Uinta Oil Program
1,092

65

1,344

1,381

 
1,373

94

1,740

1,757

 
(20
)%
(31
)%
(23
)%
(21
)%
Other (1)
21

1

18

25

 
506

928

15,192

3,966

 
(96
)%
(100
)%
(100
)%
(99
)%
Total
3,311

635

5,772

4,908

 
3,056

1,330

19,950

7,711

 
8
 %
(52
)%
(71
)%
(36
)%

(1)
Includes oil, NGL and gas volumes of 174 MBbls, 908 MBbls and 14,724 MMcf, respectively, from the Piceance Basin and 327 MBbls, 20 MBbls and 456 MMcf, respectively, from the Powder River Basin for the nine months ended September 30, 2014.

Hedging Activities. During the nine months ended September 30, 2015, approximately 92% of our oil volumes and 88% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $120.5 million and natural gas income of $8.4 million after settlements for all commodity derivatives. The $128.9 million gain on settlements for the nine months ended September 30, 2015 was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

During the nine months ended September 30, 2014, approximately 85% of our oil volumes, 89% of our natural gas volumes and 20% of our NGL related volumes were subject to financial hedges, which resulted in decreased oil income of $13.8 million, natural gas income of $6.6 million and NGL income of $0.3 million after settlements for all commodity derivatives. Of the $20.7 million loss on settlements for the nine months ended September 30, 2014, a $0.9 million gain was included in oil, gas and NGL production revenues and a $21.6 million loss was included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.

Other Operating Revenues. Other operating revenues decreased to $2.7 million for the nine months ended September 30, 2015 from $7.7 million for the nine months ended September 30, 2014. Other operating revenues for the nine months ended September 30, 2015 included a $1.0 million Utah severance tax refund related to the West Tavaputs area of the Uinta Basin. The West Tavaputs properties were sold in December 2013. Additional income of $1.3 million related to gathering and compression fees received from third parties and $0.4 million related to the sale of seismic data.
 

38

Other operating revenues for the nine months ended September 30, 2014 consisted of a $5.9 million adjustment related to recovery of processing deductions for NGL revenues and $1.8 million of income from gathering and compression fees received from third parties. Based on guidance provided by the Federal Office of Natural Resources Revenue, additional processing deductions were taken against NGL royalties paid on Federal and State leases from 2008 through July 2013 in the West Tavaputs area of the Uinta Basin.

Lease Operating Expense. LOE increased to $7.10 per Boe for the nine months ended September 30, 2015 from $6.27 per Boe for the nine months ended September 30, 2014. LOE on a per Boe basis is inherently higher for our oil producing properties such as those in our Uinta and DJ Basin development areas. The sale of natural gas properties with lower LOE per Boe through the Piceance Divestiture contributed to a higher LOE per Boe for the nine months ended September 30, 2015. This increase is partially offset by operating efficiencies, a decrease in service industry costs, reduced workover activity in the Uinta Basin and our decision to shut-in certain Uinta Basin wells due to the current commodity price environment.

Gathering, Transportation and Processing Expense. GTP expense decreased to $0.52 per Boe for the nine months ended September 30, 2015 from $4.44 per Boe for the nine months ended September 30, 2014. GTP expense on a per Boe basis decreased due to inherently lower GTP expense from our oil producing properties in the Uinta and DJ Basin development areas and due to the sale of natural gas properties with higher GTP expense per Boe in the Piceance Divestiture. In addition, beginning October 1, 2014, costs associated with unused firm natural gas pipeline transportation contracts have been included in unused commitments in the Unaudited Consolidated Statements of Operations. See "Unused Commitments" below for further information.

Production Tax Expense. Total production taxes decreased to $10.0 million for the nine months ended September 30, 2015 from $27.8 million for the nine months ended September 30, 2014. The overall decrease in production tax expense is related to the Piceance Divestiture and the Powder River Oil Divestitures and a 37% decrease in average realized prices before hedging. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 6.3% and 7.0% for the nine months ended September 30, 2015 and 2014, respectively.

Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense for the six months ended September 30, 2015 and 2014 are summarized below:

 
Nine Months Ended September 30,
 
 
2015
 
2014
 
 
(in thousands)
 
Non-cash impairment of proved oil and gas properties
$
556,563

(1) 
$
12,531

(2) 
Non-cash impairment of unproved oil and gas properties
15,803

(1) 
15,250

(2) 
Non-cash impairment of inventory
—

 
340

 
Dry hole expense
(29
)
 
96

 
Abandonment expense
2,659

 
4,396

 
Total non-cash impairment, dry hole costs and abandonment expense
$
574,996

 
$
32,613

 

(1)
Due to the continued decline in oil prices, we recognized a non-cash impairment charge associated with the proved and unproved oil and gas properties in the Uinta Oil Program for the nine months ended September 30, 2015.
(2)
As a result of the Powder River Oil Divestiture and results of drilling and completion activity in the Paradox Basin during the nine months ended September 30, 2014, the remaining carrying values of Powder River Oil and Paradox Basin assets were analyzed relative to their estimated fair market values. As a result, we recognized proved and unproved property impairments of $11.5 million and $15.3 million, respectively. In addition, $1.0 million of proved impairment expense was incurred during the nine months ended September 30, 2014 related to the sale of our West Tavaputs natural gas assets in the Uinta Basin ("West Tavaputs Divestiture") based upon a true up of previously estimated fair value relative to carrying value. These assets were sold in December 2013.

39


Given the decline in current and future commodity prices, we will continue to review our acreage position and future drilling plans. In addition, we will assess the carrying value of our properties relative to their estimated future net cash flows. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date. If commodity prices and actual operating results vary from management estimates, we may incur additional non-cash property impairments in future periods, which could have a material adverse effect on our results of operations in the period taken.

Our current recoverability test on our existing DJ Basin properties as of September 30, 2015 uses commodity pricing based on a combination of assumptions management uses in its budgeting and forecasting process adjusted for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of September 30, 2015 results in a surplus of future estimated net cash flows over carrying value of approximately $554.0 million. We estimate that the surplus in the DJ Basin would decrease by approximately $45.0 million to $50.0 million for every $1.00 decrease in future oil prices. If impairment is necessary then we would reduce the carrying value to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates used by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.

Due to the impairment to the Uinta Oil Program proved and unproved oil and gas properties during the nine months ended September 30, 2015 as discussed above, we believe the carrying value of the Uinta Oil Program approximates the fair value.

In addition to future impairments of the carrying value of our proved oil and gas properties, we may also incur reserve write-downs related to the continued decline in commodity prices. As of December 31, 2014, we had proved reserves of 122.3 MMBoe based on SEC pricing of $94.99 per barrel of oil and $4.35 per MMBtu of natural gas. Using estimated year-end 2015 pricing of $50.00 per barrel of oil and $2.75 per MMBtu of natural gas, we could lose approximately 50% of our proved reserves. This reduction in proved reserves includes approximately 65% of our proved undeveloped ("PUD") locations. In addition to the continued decline in commodity prices, actual 2015 reserves will be impacted by many other variables including, but not limited to, production of existing reserves, extensions, discoveries and improved recovery, quantity revisions, changes in future operating and development costs, along with any purchase or sales of reserves in place. Based on our internal mid-year 2015 reserves forecast and preliminary 2015 year end reserve estimates, we believe that the reduction in proved reserves will more likely be in the 30% - 40% range as a result of changes to proved reserves from the other variables mentioned above rather than 50% solely related to commodity pricing. We believe that we have adequate liquidity to develop the remaining PUDs in our five year drilling plan.




Depreciation, Depletion and Amortization. DD&A decreased to $159.7 million for the nine months ended September 30, 2015 compared with $189.4 million for the nine months ended September 30, 2014. The decrease of $29.8 million was a result of the 36% decrease in production for the nine months ended September 30, 2015 compared with the nine months ended September 30, 2014 primarily due to the Piceance Divestiture and Powder River Oil Divestitures, partially offset by an increase in the DD&A rate. The decrease in production accounted for a $68.9 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $39.1 million of additional DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the nine months ended September 30, 2015, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $32.53 per Boe compared with $24.57 per Boe for the nine months ended September 30, 2014. The increase in the DD&A rate during the nine months ended September 30, 2015 compared with the nine months ended September 30, 2014 was due to an increase in oil development, which has higher capital costs per Boe compared to natural gas development, and to the sale of natural gas properties in the Piceance Divestiture which had lower capital costs per Boe compared to oil development. Due to the continued decline in oil prices, we recognized a non-cash impairment charge associated with the proved oil and gas properties in the Uinta Oil Program for the nine months ended September 30, 2015. As a

40

result of the impairment, management believes future depletion rates will be lower; however, the future rates will be adjusted to reflect capital expenditures, proved reserve changes, well performance and any additional proved property impairments or properties that may be sold.

Unused Commitments. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized and expire July 31, 2021. Beginning October 1, 2014, and as a result of the previous divestitures of the associated gas assets, these transportation costs were excluded from gathering, transportation and processing expense and included in unused commitments expense in the Unaudited Consolidated Statements of Operations. Unused commitments expense for the nine months ended September 30, 2015 included $13.2 million related to these contracts.

General and Administrative Expense. General and administrative expense, excluding long-term cash and equity incentive compensation, decreased slightly to $31.2 million for the nine months ended September 30, 2015 from $31.4 million for the nine months ended September 30, 2014. General and administrative expense, excluding long-term cash and equity incentive compensation, is a non-GAAP measure. See Note 2 to the table on page 37 for a reconciliation and explanation.

Long-term cash and equity incentive compensation for the nine months ended September 30, 2015 and 2014 was $7.8 million and $9.6 million, respectively. The components of long-term cash and equity incentive compensation for the nine months ended September 30, 2015 and 2014 are shown in the following table:

 
Nine Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Stock options and nonvested shares of common stock
$
7,217

 
$
9,075

Shares issued for 401(k) plan (1)
273

 
499

Shares issued for directors' fees
55

 
57

Performance cash units
281

 
—

Total
$
7,826

 
$
9,631


(1)
Beginning in the second quarter of 2015, the employer matching contribution to the employees 401(k) account was paid entirely in cash.

Interest Expense. Interest expense decreased to $49.6 million for the nine months ended September 30, 2015 from $53.3 million for the nine months ended September 30, 2014. The decrease for the nine months ended September 30, 2015 was primarily due to our use of the proceeds from the Piceance Divestiture to reduce the average debt balance. Our weighted average interest rate for the nine months ended September 30, 2015 was 8.1% compared to 6.6% for the nine months ended September 30, 2014. The increase in the average interest rate for the nine months ended September 30, 2015 was due to paying down our Amended Credit Facility and our Convertible Notes, both of which have lower interest rates than our remaining bonds. In addition, we expensed deferred financing charges of $1.6 million related to amending the credit facility during the nine months ended September 30, 2015. See Note 5 to the accompanying Unaudited Consolidated Financial Statements for additional details related to the amendment of the credit facility.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $75.9 million for the nine months ended September 30, 2015 compared with a gain of $0.4 million for the nine months ended September 30, 2014. The gain or loss on commodity derivatives is related to fluctuations of oil, natural gas and NGL future pricing compared to actual pricing of commodity hedges in place as of September 30, 2015 and 2014 and during the periods then ended.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:


41

 
Nine Months Ended September 30,
 
2015
 
2014
 
(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges (1)
$
128,834

 
$
(21,580
)
Unrealized gain (loss) on derivatives not designated as cash flow hedges (1)
(52,920
)
 
21,949

Total commodity derivative gain (loss)
$
75,914

 
$
369


(1)
Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

Income Tax (Expense) Benefit. Income tax benefit totaled $177.1 million for the nine months ended September 30, 2015 compared with an income tax benefit of $43.3 million for the nine months ended September 30, 2014, resulting in effective tax rates of 27.5% and 36.9%, respectively. For the nine months ended September 30, 2015 the significant increase in the tax benefit was a result of recognizing a $571.9 million non-cash impairment charge against our Uinta Oil Program's proved and unproved oil and gas properties, increasing our projected 2015 pretax loss. Our increased projected 2015 pretax loss puts us in a net deferred tax asset position, before any valuation allowance, at September 30, 2015. In regard to our net deferred tax asset position we considered all available evidence in assessing the need for a valuation allowance against the deferred tax asset. We recorded a $66.4 million valuation allowance for the nine months ended September 30, 2015. The valuation allowance decreased our effective tax rate by 10.3% for the nine months ended September 30, 2015. Additionally for both the 2015 and 2014 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as the effect of state income taxes.
Capital Resources and Liquidity

Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, notes and senior notes, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including potential issuances of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility for our planned uses of capital for the remainder of 2015. However, we expect to pursue opportunities to further improve our liquidity position through capital markets or other transactions, such as additional property dispositions, if we believe conditions to be favorable.

At September 30, 2015, we had cash and cash equivalents of $92.8 million, short-term investments of $20.0 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2014, we had cash and cash equivalents of $165.9 million and no amounts outstanding under our Amended Credit Facility. Our borrowing base was $375.0 million as of September 30, 2015. The borrowing base is dependent on our proved reserves and hedge position and is calculated using future commodity pricing provided by our lenders, and may be adjusted in the future at the sole discretion of the lenders. Our remaining borrowing capacity was reduced by $26.0 million to $349.0 million as of September 30, 2015 due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

Cash Flow from Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2015 and 2014 was $165.9 million and $231.3 million, respectively. The decrease in net cash provided by operating activities was primarily due to a decrease in production revenues offset by an increase in commodity derivative settlements.

Commodity Hedging Activities


42

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production revenues. At September 30, 2015, we had in place crude oil swaps covering portions of our 2015, 2016 and 2017 production and natural gas swaps covering portions of our 2015 and 2016 production.

In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil and natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, gas and NGL production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative's fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.

At September 30, 2015, the estimated fair value of all of our commodity derivative instruments was a net asset of $142.1 million, comprised of current and noncurrent assets.

The table below summarizes the realized and unrealized gains and losses that we recognized related to our oil, natural gas and NGL derivative instruments for the periods indicated:

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
 
(in thousands)
Commodity derivative settlements on derivatives designated as cash flow hedges (1)
$
—

 
$
351

 
$
—

 
$
889

Realized gains (losses) on derivatives not designated as cash flow hedges (2)(3)
$
45,936

 
$
(3,054
)
 
$
128,834

 
$
(21,580
)
Unrealized gains (losses) on derivatives not designated as cash flow hedges (2)(3)
23,197

 
75,353

 
(52,920
)
 
21,949

Total commodity derivative gain (loss)
$
69,133

 
$
72,299

 
$
75,914

 
$
369

 
(1)
Included in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations.
(2)
Included in commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations.
(3)
Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.

The following table summarizes all of our hedges in place as of September 30, 2015. There were no hedges entered into subsequent to September 30, 2015 through October 23, 2015.


43

Contract
Total
Hedged
Volumes
 
Quantity
Type
 
Weighted
Average
Fixed
Price
 
Index
Price (1)
 
Fair Market
Value
(in thousands)
Swap Contracts:
 
 
 
 
 
 
 
 
 
2015
 
 
 
 
 
 
 
 
 
Oil
993,600

 
Bbls
 
$
89.81

 
WTI
 
$
43,717

Natural gas
1,840,000

 
MMBtu
 
$
4.13

 
NWPL
 
2,964

2016
 
 
 
 
 
 
 
 
 
Oil
2,478,600

 
Bbls
 
$
80.47

 
WTI
 
77,211

Natural gas
1,830,000

 
MMBtu
 
$
4.10

 
NWPL
 
2,704

2017
 
 
 
 
 
 
 
 
 
Oil
683,250

 
Bbls
 
$
75.61

 
WTI
 
15,460

Total
 
 
 
 
 
 
 
 
$
142,056


(1)
WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange ("NYMEX"). NWPL refers to the Northwest Pipeline Corporation price as quoted in Platt's Inside FERC on the first business day of each month.

By removing the price volatility from a portion of our oil, natural gas and NGL related revenue, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

It is our policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility or affiliates of lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. ("ISDA") Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.

Capital Expenditures

Our capital expenditures are summarized in the following tables for the periods indicated:

 
Nine Months Ended September 30,
Basin/Area
2015
 
2014
 
(in millions)
DJ
$
214.3

 
$
283.5

Uinta Oil Program
26.3

 
119.2

Other
2.0

 
27.3

Total
$
242.6

 
$
430.0



44

 
Nine Months Ended September 30,
 
2015
 
2014
 
(in millions)
Acquisitions of proved and unproved properties and other real estate
$
4.2

 
$
11.1

Drilling, development, exploration and exploitation of oil and natural gas properties
227.0

 
402.4

Gathering and compression facilities
7.4

 
13.3

Geologic and geophysical costs
3.0

 
0.5

Furniture, fixtures and equipment
1.0

 
2.7

Total
$
242.6

 
$
430.0


Our current estimated capital expenditure budget in 2015 is between $315.0 million to $325.0 million. The budget targets exclusively oil activities and includes facilities costs, but excludes acquisitions. We expect our 2015 capital expenditure plan to result in continued growth in production from our DJ Basin assets, in substantial part due to the extended reach lateral wells we are drilling in the area. We also expect to continue to benefit from significant improvements in per well drilling and completion costs relative to the costs experienced in 2014. We may adjust capital expenditures throughout the year as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline further or costs increase relative to levels we consider acceptable, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. We would generally expect to do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures, including those relating to acquisitions and divestitures, in response to changes in prices and other economic and market conditions, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside of our control.

We believe that we have sufficient available liquidity with cash on hand, short-term investments, capacity under the Amended Credit Facility and cash flow from operations to fund our 2015 budgeted capital expenditures. In addition, in June 2015, we entered into an Equity Distribution Agreement with Goldman, Sachs and Co. (the "Equity Distribution Agreement") pursuant to which we may elect to sell from time to time shares of our common stock to the public having an aggregate gross sales price of up to $100.0 million. While we have not sold any shares pursuant to the Equity Distribution Agreement to date, it provides us with another potential source of liquidity. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

Financing Activities

Amended Credit Facility

On September 23, 2015, the Company entered into a Fourth Amendment (the "Fourth Amendment") to the Third Amended and Restated Credit Agreement dated March 16, 2010 (the "Amended Credit Facility"). The Fourth Amendment, among other things, reaffirmed the current borrowing base at $375.0 million and amended certain financial covenant requirements. On April 9, 2015, we entered into a Third Amendment (the "Third Amendment") to the Amended Credit Facility. The Third Amendment amended the definition of "Maturity Date" in the credit agreement to mean the earliest of (a) April 9, 2020 or (b) the date 181 days prior to the maturity of certain unsecured senior or senior subordinated debt of ours in existence as of the date of the Third Amendment or that may be incurred by us as of a future date, or any permitted refinancing debt in respect thereof. The Amended Credit Facility currently has commitments and a borrowing base of $375.0 million from 13 lenders based on mid-year 2015 reserves and hedge position. Due to the Third Amendment, we recognized interest expense of $1.6 million and a loss on extinguishment of debt of $0.8 million on the Unaudited Consolidated Statements of Operations related to expensing deferred financing charges during the nine months ended September 30, 2015. As of September 30, 2015, we had no amounts outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduced the available borrowing capacity of the Amended Credit Facility as of September 30, 2015 to $349.0 million.

Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the unused commitment fee is between 0.375% to 0.5% based on borrowing base utilization. There have not been any borrowings under the Amended

45

Credit Facility in 2015. The average annual interest rate incurred on the Amended Credit Facility was 2.0% and 1.9% for the three and nine months ended September 30, 2014, respectively.

The borrowing base is required to be re-determined at least twice per year, on or about April 1 and October 1, as well as following any material property sales. Future borrowing bases will be computed based on our proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt.

The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants from the time we entered into the facility.

5% Convertible Senior Notes Due 2028

On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to us and redeemed by us at par. On March 20, 2015, $24.8 million of the remaining outstanding principal amount, or approximately 98% of the remaining outstanding Convertible Notes, were put to us and redeemed by us at par. We settled the notes in cash and recognized a gain on extinguishment of $2.6 million in the Unaudited Consolidated Statements of Operations for the nine months ended September 30, 2015. After the redemption, $0.6 million aggregate principal amount of the Convertible Notes were outstanding as of September 30, 2015. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by us. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, are senior in right of payment to all of our future subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.

The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require us to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. We have the right with at least 30 days' notice to call the Convertible Notes.

7.625% Senior Notes Due 2019

On September 27, 2011, we issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 of each year. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are redeemable beginning on October 1, 2015 at our option at an initial redemption price of 103.813% of the principal amount of the notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

7.0% Senior Notes Due 2022

On March 12, 2012, we issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at our option beginning on October 15, 2017 at an initial redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

Lease Financing Obligation Due 2020

46


We have a Lease Financing Obligation with a balance of $3.3 million as of September 30, 2015 whereby we sold and subsequently leased back certain compressors and related facilities owned by us. The Lease Financing Obligation expires on August 10, 2020, and we have the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option pursuant to which we may purchase the equipment for $1.8 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. See Note 12 to the accompanying Unaudited Consolidated Financial Statements for a discussion of aggregate minimum future lease payments.

Our outstanding debt is summarized below:

 
 
As of September 30, 2015
 
As of December 31, 2014
 
Maturity Date
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
 
(in thousands)
Amended Credit Facility
April 9, 2020
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Convertible Notes (1)
March 15, 2028 (2)
579

 
—

 
579

 
25,344

 
—

 
25,344

7.625% Senior Notes (3)
October 1, 2019
400,000

 
—

 
400,000

 
400,000

 
—

 
400,000

7.0% Senior Notes (4)
October 15, 2022
400,000

 
—

 
400,000

 
400,000

 
—

 
400,000

Lease Financing Obligation (5)
August 10, 2020
3,330

 
—

 
3,330

 
3,648

 
—

 
3,648

Total Debt
 
$
803,909

 
$
—

 
$
803,909

 
$
828,992

 
$
—

 
$
828,992

Less: Current Portion of Long-Term Debt (6)
 
1,015

 
—

 
1,015

 
25,770

 
—

 
25,770

     Total Long-Term Debt
 
$
802,894

 
$
—

 
$
802,894

 
$
803,222

 
$
—

 
$
803,222


(1)
The aggregate estimated fair value of the Convertible Notes was approximately $0.6 million and $25.1 million as of September 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments. On March 20, 2015, the holders put 98% of the Notes to us, leaving $0.6 million principal amount remaining.
(2)
We have the right at any time with at least 30 days' notice to call the Convertible Notes, and the holders have the right to require us to purchase the notes on each of March 20, 2018 and March 20, 2023.
(3)
The aggregate estimated fair value of the 7.625% Senior Notes was approximately $292.8 million and $359.8 million as of September 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.
(4)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $257.0 million and $366.0 million as of September 30, 2015 and December 31, 2014, respectively, based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $3.2 million and $3.5 million as of September 30, 2015 and December 31, 2014, respectively. Because there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.
(6)
The current portion of the long-term debt as of September 30, 2015 and December 31, 2014 includes the current portion of the Lease Financing Obligation and the principal amount of the Convertible Notes.

Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody's Investor Services and Standard & Poor's Rating Services currently rate our 7.625% Senior Notes and 7.0% Senior Notes and have assigned a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, Convertible Notes, 7.625% Senior Notes or 7.0% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Contractual Obligations. A summary of our contractual obligations as of and subsequent to September 30, 2015 is provided in the following table:


47

 
Payments Due By Year
Year 1
 
Year 2
 
Year 3
 
Year 4
 
Year 5
 
Thereafter
 
Total
 
Twelve Months Ended September 30, 2016
 
Twelve Months Ended September 30, 2017
 
Twelve Months Ended September 30, 2018
 
Twelve Months Ended September 30, 2019
 
Twelve Months Ended September 30, 2020
 
After
September 30, 2020
 
 
 
(in thousands)
Notes payable (1)
$
553

 
$
553

 
$
321

 
$
—

 
$
—

 
$
—

 
$
1,427

7.625% Senior Notes (2)
30,500

 
30,500

 
30,500

 
30,500

 
415,250

 
—

 
537,250

7.0% Senior Notes (3) 
28,000

 
28,000

 
28,000

 
28,000

 
28,000

 
470,000

 
610,000

Convertible Notes (4)
608

 
—

 
—

 
—

 
—

 
—

 
608

Lease Financing Obligation (5)
537

 
537

 
537

 
1,960

 
—

 
—

 
3,571

Purchase commitments (6)
1,531

 
—

 
—

 
—

 
—

 
—

 
1,531

Office and office equipment leases and other (7)(8)(9)
4,902

 
2,934

 
2,656

 
1,265

 
—

 
—

 
11,757

Firm transportation and processing agreements (10)
18,595

 
18,692

 
18,692

 
18,692

 
18,692

 
15,576

 
108,939

Asset retirement obligations (11)
1,362

 
197

 
218

 
438

 
214

 
21,273

 
23,702

Total
$
86,588

 
$
81,413

 
$
80,924

 
$
80,855

 
$
462,156

 
$
506,849

 
$
1,298,785


(1)
Included in notes payable is a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term of the letter of credit is April 30, 2018. There is currently no balance outstanding under the Amended Credit Facility.
(2)
On September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. We are obligated to make annual interest payments through maturity in 2019 equal to $30.5 million.
(3)
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make annual interest payments through maturity in 2022 equal to $28.0 million.
(4)
On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012 approximately 85% of the outstanding Convertible Notes, representing $147.2 million of the then outstanding principal amount, were put to us. On March 20, 2015, approximately 98% of the remaining outstanding Convertible Notes, representing $24.8 million of the then outstanding principal amount, were put to us, leaving $0.6 million principal amount remaining. We are obligated to make semi-annual interest payments on the Convertible Notes until either we call the remaining Convertible Notes or the holders put the Convertible Notes to us.
(5)
The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.
(6)
We have one take-or-pay CO2 purchasing agreement that expires in December 2015. The agreement imposes a minimum volume commitment ("MVC") to purchase CO2 at a contracted price. The contract provides CO2 used in fracture stimulation operations. If we do not take delivery of the minimum volume required, we are obligated to pay for the deficiency. As of September 30, 2015, $1.5 million of the future commitment is due by December 31, 2015.
(7)
The lease for our principal office in Denver, Colorado extends through March 2019.
(8)
Includes a contractual obligation of $1.3 million due October 1, 2015 related to certain drilling commitments on sold properties.
(9)
Includes a sales throughput contract in the South Altamont area of the Uinta Oil Basin. Under this contract, we are obligated to sell and deliver a MVC of 450.0 MMcf for the period of December 1, 2014 to November 30, 2015. If the minimum volume is not delivered, we must make a deficiency payment of up to $0.8 million. As of September 30, 2015, we have satisfied approximately 190.2 MMcf of this commitment, resulting in an estimated deficiency payment of up to $0.4 million due December 1, 2015.
(10)
We have entered into contracts that provide firm transportation capacity on pipeline systems. The remaining term on these contracts is six years. The contracts require us to pay transportation demand and processing charges regardless of the amount of gas we deliver to the processing facility or pipeline.
(11)
Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2014 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of September 30, 2015.

48


Trends and Uncertainties

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of trends and uncertainties that may affect our financial condition or liquidity.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2014 and the notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly Report on Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our primary market risk exposure is in the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. oil and natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. For example, the West Texas Intermediate price per Bbl as quoted on the NYMEX was $91.16 per Bbl at September 30, 2014 compared to $45.09 per Bbl at September 30, 2015. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the nine months ended September 30, 2015, our income before income taxes would have decreased by approximately $0.1 million for each $1.00 per barrel decrease in crude oil prices, a de minimis amount for each $0.10 decrease per MMBtu in natural gas prices and $0.6 million for each $1.00 per barrel decrease in NGL prices.

We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty. These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations.

As of October 23, 2015, we have financial derivative instruments related to oil and natural gas volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented under "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities."

 
October – December 2015
 
For the year 2016
 
For the year 2017
 
Derivative
Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
Oil (Bbls)
993,600

 
$
89.81

 
2,478,600

 
$
80.47

 
683,250

 
$
75.61

Natural Gas (MMbtu)
1,840,000

 
$
4.13

 
1,830,000

 
$
4.10

 
—

 
$
—


Commodity Price Risk - Carrying Value of Proved Oil and Gas Properties

Our current recoverability test on our existing DJ Basin properties as of September 30, 2015 uses commodity pricing based on a combination of assumptions management uses in its budgeting and forecasting process adjusted for geographical location and quality differentials as well as other factors that management believes will impact realized prices. The application of this test as of September 30, 2015 results in a surplus of future estimated net cash flows over carrying value of approximately $554.0 million. We estimate that the surplus in the DJ Basin would decrease by approximately $45.0 million to $50.0 million

49

for every $1.00 decrease in future oil prices. If impairment is necessary then we would reduce the carrying value to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates used by market participants that are commensurate with the risks inherent in the development and production of the underlying natural gas and oil.

Due to the impairment to the Uinta Oil Program proved and unproved oil and gas properties during the nine months ended September 30, 2015 as discussed above, we believe the carrying value of the Uinta Oil Program approximates the fair value.

In addition to future impairments of the carrying value of our proved oil and gas properties, we may also incur reserve write-downs related to the continued decline in commodity prices. As of December 31, 2014, we had proved reserves of 122.3 MMBoe based on SEC pricing of $94.99 per barrel of oil and $4.35 per MMBtu of natural gas. Using estimated year-end 2015 pricing of $50.00 per barrel of oil and $2.75 per MMBtu of natural gas, we could lose approximately 50% of our proved reserves. This reduction in proved reserves includes approximately 65% of our proved undeveloped ("PUD") locations. In addition to the continued decline in commodity prices, actual 2015 reserves will be impacted by many other variables including, but not limited to, production of existing reserves, extensions, discoveries and improved recovery, quantity revisions, changes in future operating and development costs, along with any purchase or sales of reserves in place. Based on our internal mid-year 2015 reserves forecast and preliminary 2015 year end reserve estimates, we believe that the reduction in proved reserves will more likely be in the 30% - 40% range as a result of changes to proved reserves from the other variables mentioned above rather than 50% solely related to commodity pricing. We believe that we have adequate liquidity to develop the remaining PUDs in our five year drilling plan.
Interest Rate Risks

At September 30, 2015, we had no amounts outstanding under our Amended Credit Facility. Any amounts borrowed will bear interest at floating rates. The average annual interest rate incurred on this debt for the nine months ended September 30, 2014 was 1.9%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2014 would have resulted in an estimated $1.6 million increase in interest expense.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of September 30, 2015, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of September 30, 2015.

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the third fiscal quarter of 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We are not a party to any material pending legal or governmental proceedings, other than ordinary routine litigation incidental to our business. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management does not believe that the resolution of any currently pending proceeding will have a material effect on our financial condition or results of operations.

Item 1A. Risk Factors.

As of the date of this filing, there have been no material changes or updates to the risk factors previously disclosed in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2014. An investment in our securities involves various risks. When considering an investment in our Company, you should carefully consider all of the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2014 and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware

50

of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered Sales of Securities

There were no sales of unregistered equity securities during the period covered by this report.

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended September 30, 2015:

Period
Total
Number of
Shares (1)
 
Weighted
Average Price
Paid Per
Share
 
Total Number of 
Shares (or Units) Purchased as
Part of Publicly
Announced Plans or
Programs
 
Maximum Number 
(or Approximate 
Dollar Value)
of Shares (or Units) that May Yet Be Purchased
Under the Plans or
Programs
July 1 – 31, 2015
6,198

 
$
7.13

 
—

 
—

August 1 – 31, 2015
6,334

 
4.79

 
—

 
—

September 1 – 30, 2015
2,750

 
3.65

 
—

 
—

Total
15,282

 
$
5.53

 
—

 
—


(1)
Represents shares delivered by employees to satisfy tax withholding obligations resulting from the vesting of restricted shares of common stock issued pursuant to our employee incentive plans.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit
Number
 
Description of Exhibits
10.1
 
Fourth Amendment, dated effective as of September 23, 2015, to Third Amended and Restated Credit Agreement, dated as of March 16, 2010, among Bill Barrett Corporation, certain of its subsidiaries party thereto and the bank named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on September 29, 2015.]
 
 
 
31.1
  
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
 
 
 
31.2
  
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
 
 
 
32.1
  
Section 1350 Certification of Chief Executive Officer.
 
 
 

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Exhibit
Number
 
Description of Exhibits
32.2
  
Section 1350 Certification of Chief Financial Officer.
 
 
 
101.INS
  
XBRL Instance Document
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document


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SIGNATURES

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

 
 
 
 
 
 
 
BILL BARRETT CORPORATION
 
 
 
 
Date:
November 5, 2015
By:
 
/s/ R. Scot Woodall
 
 
 
 
R. Scot Woodall
 
 
 
 
Chief Executive Officer and President
 
 
 
 
(Principal Executive Officer)
 
 
 
 
Date:
November 5, 2015
By:
 
/s/ Robert W. Howard
 
 
 
 
Robert W. Howard
 
 
 
 
Chief Financial Officer
 
 
 
 
(Principal Financial Officer)

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