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EX-32.2 - EXHIBIT 32.2 - BILL BARRETT CORPbbg-6302017xex322.htm
EX-32.1 - EXHIBIT 32.1 - BILL BARRETT CORPbbg-6302017xex321.htm
EX-31.2 - EXHIBIT 31.2 - BILL BARRETT CORPbbg-6302017xex312.htm
EX-31.1 - EXHIBIT 31.1 - BILL BARRETT CORPbbg-6302017xex311.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 

FORM 10-Q
 
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2017

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, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer
 
o
  
Accelerated filer
 
x
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
o
 
 
 
 
Emerging growth company
 
o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 76,279,645 shares of $0.001 par value common stock outstanding on July 18, 2017.



INDEX TO FINANCIAL STATEMENTS
 

2


PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

 
June 30, 2017
 
December 31, 2016
 
(in thousands, except share data)
Assets:
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
155,565

 
$
275,841

Accounts receivable, net of allowance for doubtful accounts
30,410

 
32,837

Derivative assets
22,405

 
8,398

Prepayments and other current assets
2,671

 
1,376

Total current assets
211,051

 
318,452

Property and equipment - at cost, successful efforts method for oil and gas properties:
 
 
 
Proved oil and gas properties
1,663,304

 
1,539,373

Unproved oil and gas properties, excluded from amortization
54,758

 
58,830

Furniture, equipment and other
23,837

 
23,636

 
1,741,899

 
1,621,839

Accumulated depreciation, depletion, amortization and impairment
(635,824
)
 
(559,690
)
Total property and equipment, net
1,106,075

 
1,062,149

Deferred income tax asset

 
1,587

Derivative assets
3,011

 

Deferred financing costs and other noncurrent assets
3,057

 
3,153

Total
$
1,323,194

 
$
1,385,341

Liabilities and Stockholders' Equity:
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
60,026

 
$
49,447

Amounts payable to oil and gas property owners
8,865

 
6,192

Production taxes payable
18,506

 
22,992

Derivative liabilities

 
4,346

Deferred income taxes

 
1,587

Current portion of long-term debt
462

 
454

Total current liabilities
87,859

 
85,018

Long-term debt, net of debt issuance costs
668,545

 
711,808

Asset retirement obligations
20,761

 
10,703

Derivatives and other noncurrent liabilities
3,765

 
6,269

Stockholders' equity:
 
 
 
Common stock, $0.001 par value; authorized 300,000,000 and 150,000,000 shares at June 30, 2017 and December 31, 2016, respectively; 76,281,537 and 75,721,360 shares issued and outstanding at June 30, 2017 and December 31, 2016, respectively, with 1,400,260 and 1,325,714 shares subject to restrictions, respectively
75

 
74

Additional paid-in capital
1,116,588

 
1,113,797

Retained earnings (accumulated deficit)
(574,399
)
 
(542,328
)
Treasury stock, at cost: zero shares at June 30, 2017 and December 31, 2016

 

Total stockholders' equity
542,264

 
571,543

Total
$
1,323,194

 
$
1,385,341

See notes to Unaudited Consolidated Financial Statements.

3


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except share and per share data)
Operating Revenues:
 
 
 
 
 
 
 
Oil, gas and NGL production
$
50,941

 
$
47,025

 
$
101,366

 
$
76,146

Other operating revenues
125

 
259

 
236

 
572

Total operating revenues
51,066

 
47,284

 
101,602

 
76,718

Operating Expenses:
 
 
 
 
 
 
 
Lease operating expense
5,506

 
8,479

 
11,368

 
17,306

Gathering, transportation and processing expense
535

 
611

 
1,024

 
1,399

Production tax expense
3,434

 
3,520

 
3,756

 
3,205

Exploration expense
3

 
21

 
30

 
48

Impairment, dry hole costs and abandonment expense
1

 
234

 
8,075

 
792

(Gain) loss on sale of properties

 
(708
)
 
(92
)
 
(708
)
Depreciation, depletion and amortization
39,337

 
40,392

 
77,677

 
82,408

Unused commitments
4,558

 
4,568

 
9,130

 
9,136

General and administrative expense
8,943

 
9,937

 
18,292

 
22,357

Other operating expenses, net
(755
)
 

 
(1,328
)
 

Total operating expenses
61,562

 
67,054

 
127,932

 
135,943

Operating Income (Loss)
(10,496
)
 
(19,770
)
 
(26,330
)
 
(59,225
)
Other Income and Expense:
 
 
 
 
 
 
 
Interest and other income
492

 
57

 
698

 
94

Interest expense
(16,137
)
 
(15,423
)
 
(30,088
)
 
(31,169
)
Commodity derivative gain (loss)
15,598

 
(21,980
)
 
32,062

 
(13,312
)
Gain (loss) on extinguishment of debt
(7,904
)
 
8,697

 
(7,904
)
 
8,697

Total other income and expense
(7,951
)
 
(28,649
)
 
(5,232
)
 
(35,690
)
Income (Loss) before Income Taxes
(18,447
)
 
(48,419
)
 
(31,562
)
 
(94,915
)
(Provision for) Benefit from Income Taxes

 

 

 

Net Income (Loss)
$
(18,447
)
 
$
(48,419
)
 
$
(31,562
)
 
$
(94,915
)
Net Income (Loss) Per Common Share, Basic
$
(0.25
)
 
$
(0.93
)
 
$
(0.42
)
 
$
(1.89
)
Net Income (Loss) Per Common Share, Diluted
$
(0.25
)
 
$
(0.93
)
 
$
(0.42
)
 
$
(1.89
)
Weighted Average Common Shares Outstanding, Basic
74,794,448

 
51,831,688

 
74,669,806

 
50,165,492

Weighted Average Common Shares Outstanding, Diluted
74,794,448

 
51,831,688

 
74,669,806

 
50,165,492

See notes to Unaudited Consolidated Financial Statements.

4


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Net Income (Loss)
$
(18,447
)
 
$
(48,419
)
 
$
(31,562
)
 
$
(94,915
)
Other comprehensive income (loss)

 

 

 

Comprehensive Income (Loss)
$
(18,447
)
 
$
(48,419
)
 
$
(31,562
)
 
$
(94,915
)
See notes to Unaudited Consolidated Financial Statements.

5


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
 
Six Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Operating Activities:
 
 
 
Net Income (Loss)
$
(31,562
)
 
$
(94,915
)
Adjustments to reconcile to net cash provided by operations:
 
 
 
Depreciation, depletion and amortization
77,677

 
82,408

Impairment, dry hole costs and abandonment expense
8,075

 
792

Commodity derivative (gain) loss
(32,062
)
 
13,312

Settlements of commodity derivatives
9,798

 
58,005

Stock compensation and other non-cash charges
3,654

 
5,431

Amortization of deferred financing costs
1,155

 
1,502

(Gain) loss on extinguishment of debt
7,904

 
(8,697
)
(Gain) loss on sale of properties
(92
)
 
(708
)
Change in operating assets and liabilities:
 
 
 
Accounts receivable
2,427

 
9,544

Prepayments and other assets
(1,377
)
 
(902
)
Accounts payable, accrued and other liabilities
(5,585
)
 
(3,943
)
Amounts payable to oil and gas property owners
2,673

 
(3,387
)
Production taxes payable
(4,486
)
 
(9,663
)
Net cash provided by (used in) operating activities
38,199

 
48,779

Investing Activities:
 
 
 
Additions to oil and gas properties, including acquisitions
(104,236
)
 
(86,680
)
Additions of furniture, equipment and other
(201
)
 
(991
)
Proceeds from sale of properties and other investing activities
(615
)
 
(1,225
)
Net cash provided by (used in) investing activities
(105,052
)
 
(88,896
)
Financing Activities:
 
 
 
Proceeds from debt
275,000

 

Principal payments on debt
(322,113
)
 
(218
)
Proceeds from sale of common stock, net of offering costs
(298
)
 

Deferred financing costs and other
(6,012
)
 
(1,078
)
Net cash provided by (used in) financing activities
(53,423
)
 
(1,296
)
Increase (Decrease) in Cash and Cash Equivalents
(120,276
)
 
(41,413
)
Beginning Cash and Cash Equivalents
275,841

 
128,836

Ending Cash and Cash Equivalents
$
155,565

 
$
87,423

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
 
Total
Stockholders'
Equity
Balance at December 31, 2015
$
48

 
$
921,318

 
$
(371,950
)
 
$

 
$
549,416

Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
1

 

 

 
(1,114
)
 
(1,113
)
Stock-based compensation

 
9,455

 

 

 
9,455

Retirement of treasury stock

 
(1,114
)
 

 
1,114

 

Exchange of senior notes for shares of common stock
10

 
74,390

 

 

 
74,400

Issuance of common stock, net of offering costs
15

 
109,748

 

 

 
109,763

Net income (loss)

 

 
(170,378
)
 

 
(170,378
)
Balance at December 31, 2016
74

 
1,113,797

 
(542,328
)
 

 
571,543

Cumulative effect of accounting change (1)

 
180

 
(509
)
 

 
(329
)
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding
1

 

 

 
(1,230
)
 
(1,229
)
Stock-based compensation

 
3,902

 

 

 
3,902

Retirement of treasury stock

 
(1,230
)
 

 
1,230

 

Issuance of common stock, net of offering costs

 
(61
)
 

 

 
(61
)
Net income (loss)

 

 
(31,562
)
 

 
(31,562
)
Balance at June 30, 2017
$
75

 
$
1,116,588

 
$
(574,399
)
 
$

 
$
542,264

See notes to Unaudited Consolidated Financial Statements.

(1)
Cumulative effect of accounting change relates to the adoption of Accounting Standards Update 2016-09. See Note 2 of the Consolidated Financial Statements for further detail on the adoption of this accounting standard.

7


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

June 30, 2017

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 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 consolidated 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 2016 Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company's consolidated 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 net 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 payment awards.

Accounts Receivable. Accounts receivable is comprised of the following:

 
As of June 30, 2017
 
As of December 31, 2016
 
(in thousands)
Accrued oil, gas and NGL sales
$
22,812

 
$
26,542

Due from joint interest owners
7,442

 
4,366

Other
415

 
1,952

Allowance for doubtful accounts
(259
)
 
(23
)
Total accounts receivable
$
30,410

 
$
32,837


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

8


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, recent sales prices of comparable properties 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.

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 June 30, 2017
 
As of December 31, 2016
 
(in thousands)
Proved properties
$
319,939

 
$
306,075

Wells and related equipment and facilities
1,274,339

 
1,164,354

Support equipment and facilities
63,747

 
63,238

Materials and supplies
5,279

 
5,706

Total proved oil and gas properties
$
1,663,304

 
$
1,539,373

Unproved properties
32,046

 
27,790

Wells and facilities in progress
22,712

 
31,040

Total unproved oil and gas properties, excluded from amortization
$
54,758

 
$
58,830

Accumulated depreciation, depletion, amortization and impairment
(618,548
)
 
(543,154
)
Total oil and gas properties, net
$
1,099,514

 
$
1,055,049


The Company reviews oil and natural gas properties 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 using proved and risked probable and possible reserves based on the Company's development plans and best estimate of future production, commodity pricing, reserve risking, 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 oil and gas properties, no impairment is taken. If the carrying amount 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 of its oil and gas properties represent the applicable market value. The factors used to determine fair value may 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 commensurate with the risk and current market conditions associated with realizing the projected cash flows.

In addition, oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined 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, which involves

9


calculating the present value of future net cash flows as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

The Company recognized non-cash impairment, dry hole costs and abandonment expense in the Unaudited Consolidated Statements of Operations as follows:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Impairment of unproved oil and gas properties(1)
$

 
$

 
$
8,010


$
183

Dry hole costs

 
13

 
2

 
70

Abandonment expense and lease expirations
1

 
221

 
63

 
539

Total impairment, dry hole costs and abandonment expense
$
1

 
$
234

 
$
8,075

 
$
792


(1)
The Company recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the six months ended June 30, 2017. The Company has no current plan to develop this acreage.

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 June 30, 2017
 
As of December 31, 2016
 
(in thousands)
Accrued drilling, completion and facility costs
$
37,335

 
$
15,594

Accrued lease operating, gathering, transportation and processing expenses
3,915

 
4,261

Accrued general and administrative expenses
4,725

 
6,375

Accrued interest payable
10,221

 
12,264

Trade payables
1,295

 
7,900

Other
2,535

 
3,053

Total accounts payable and accrued liabilities
$
60,026

 
$
49,447


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. Recent case law in Wyoming has exposed us to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contract obligations to the Company as provided for in purchase and sale agreements, regulatory agencies and landowners may demand that the Company perform such activities. The Company recognized $0.8 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the six months ended June 30, 2017.

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 June 30, 2017 and 2016 were not material.

10



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 results of recent operations. The assumptions about future taxable income require significant judgment to determine whether it is more likely than not that the deferred tax asset will be realized. If it is determined that the deferred tax asset will not be realized, then a valuation allowance will be recorded against the deferred tax asset. The Company began recording a full valuation allowance against the deferred tax asset during the period ending September 30, 2015 and continues to do so as of June 30, 2017.

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 June 30, 2017.

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 and in-the-money outstanding stock options to purchase the Company's common stock. 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 six months ended June 30, 2017 and 2016.

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

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands, except per share amounts)
Net income (loss)
$
(18,447
)
 
$
(48,419
)
 
$
(31,562
)
 
$
(94,915
)
Basic weighted-average common shares outstanding in period
74,794

 
51,832

 
74,670

 
50,165

Diluted weighted-average common shares outstanding in period
74,794

 
51,832

 
74,670

 
50,165

Basic net income (loss) per common share
$
(0.25
)
 
$
(0.93
)
 
$
(0.42
)
 
$
(1.89
)
Diluted net income (loss) per common share
$
(0.25
)
 
$
(0.93
)
 
$
(0.42
)
 
$
(1.89
)

New Accounting Pronouncements. In May 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2017-09, Stock Compensation-Scope of Modification Accounting. The objective of this update is to provide clarity and reduce both diversity in practice and cost and complexity when applying a change to the terms or conditions of a share-based payment award. ASU 2017-09 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

In January 2017, the FASB issued ASU 2017-01, Business Combinations: Clarifying the definition of a business. The objective of this update is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company does not expect the standard to have a significant impact on the Company's financial statements or disclosures.


11


In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments. The objective of this update is to address eight specific cash flow issues in order to reduce the existing diversity in practice. ASU 2016-15 is effective for the annual periods beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of adopting this standard.

In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting. The objective of this update is to simplify the current guidance for stock compensation. The areas for simplification involve several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. ASU 2016-09 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted effective January 1, 2017 and did not have a significant impact on the Company's disclosures or financial statements. As of January 1, 2017, the Company did not have excess tax benefits associated with its stock compensation, and therefore, there was no tax impact upon adoption of this standard. In addition, the employee taxes paid on the statement of cash flows when shares were withheld for taxes were already classified as a financing activity, therefore, there was no cash flow statement impact upon adoption of this standard. The Company elected to account for forfeitures as they occur as opposed to estimating the number of awards that are expected to vest. Per ASU 2016-09, the election is considered a change in accounting principle, with the cumulative effect of the change reported as an adjustment to the beginning equity balance. The Company reported an increase to accumulated deficit and additional paid in capital ("APIC") of $0.2 million related to equity award compensation and an increase to accumulated deficit and derivative and other noncurrent liabilities of $0.3 million related to liability award compensation. The cumulative effect of accounting change is reported in the Consolidated Statement of Stockholders' Equity.

In February 2016, the FASB issued ASU 2016-02, Leases. The objective of this update is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company has performed an initial assessment by compiling and analyzing contracts and leasing arrangements that may be affected. The Company is still evaluating the impact of adopting this standard.

In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. The objective of this update is to require deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. ASU 2015-17 was effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard was adopted January 1, 2017 on a prospective basis and did not have a significant impact on the Company's disclosures and financial statements. Prior periods were not retrospectively adjusted.

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. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which provided additional implementation guidance and deferred the effective date of ASU 2014-09. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard will be adopted using the modified retrospective transition method, effective January 1, 2018. The Company has performed an initial assessment of its current existing revenue contracts and does not expect the standard to have a significant impact on the Company's financial statements or disclosures.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:


12


 
Six Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Cash paid for interest
$
30,976

 
$
31,287

Cash paid for income taxes

 

Supplemental disclosures of non-cash investing and financing activities:
 
 
 
Accrued liabilities - oil and gas properties
37,175

 
7,452

Change in asset retirement obligations, net of disposals
10,545

 
21

Retirement of treasury stock
(1,230
)
 
(1,042
)
Fair value of properties exchanged in non-cash transactions
11,790

 

Fair value of debt exchanged for common stock (1)

 
74,400


(1)
See Note 5 for additional information regarding the Debt Exchange.

4. Acquisitions, Exchanges and Divestitures

On February 28, 2017, the Company acquired acreage in the DJ Basin for $12.0 million, after initial closing adjustments. The transaction was considered an asset acquisition, and therefore, the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. The acquisition included $9.1 million and $11.6 million of proved and unevaluated properties, respectively, and asset retirement obligations of $8.7 million.

During the six months ended June 30, 2017, the Company completed two acreage exchange transactions to consolidate certain acreage positions in the DJ Basin. Pursuant to the transactions, the Company exchanged leasehold acreage and, to a lesser extent, interests in certain proved undeveloped acreage. The assets exchanged were all in the same unit of production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets the Company exchanged.

On July 14, 2016, the Company sold certain non-core assets in the Uinta Basin. The Company received $27.8 million in cash proceeds, after closing adjustments. In addition to the cash proceeds, the Company recognized non-cash proceeds of $4.8 million related to the relief from the Company's asset retirement obligation. Assets sold included $30.6 million in proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment, and $2.0 million in unproved oil and gas properties. Liabilities sold included $4.8 million of asset retirement obligations. The transaction was accounted for as a cost recovery, therefore, no gain or loss was recognized.

5. Long-Term Debt

The Company's outstanding debt is summarized below:

13


 
 
 
As of June 30, 2017
 
As of December 31, 2016
 
Maturity Date
Principal
 
Debt Issuance Costs
 
Carrying
Amount
 
Principal
 
Debt Issuance Costs
 
Carrying
Amount
 
 
(in thousands)
Amended Credit Facility
April 9, 2020
$

 
$

 
$

 
$

 
$

 
$

Convertible Notes (1)
March 15, 2028

 

 

 
579

 

 
579

7.625% Senior Notes (2)
October 1, 2019

 

 

 
315,300

 
(2,169
)
 
313,131

7.0% Senior Notes (3)
October 15, 2022
400,000

 
(3,865
)
 
396,135

 
400,000

 
(4,227
)
 
395,773

8.75% Senior Notes (4)
June 15, 2025
275,000

 
(4,684
)
 
270,316

 

 

 

Lease Financing Obligation (5)
August 10, 2020
2,558

 
(2
)
 
2,556

 
2,782

 
(3
)
 
2,779

Total Debt
 
$
677,558

 
$
(8,551
)
 
$
669,007

 
$
718,661

 
$
(6,399
)
 
$
712,262

Less: Current Portion of Long-Term Debt (6)
 
462

 

 
462

 
454

 

 
454

Total Long-Term Debt
 
$
677,096

 
$
(8,551
)
 
$
668,545

 
$
718,207

 
$
(6,399
)
 
$
711,808

 
(1)
The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of December 31, 2016 based on reported market trades of these instruments.
(2)
The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately $314.5 million as of December 31, 2016 based on reported market trades of these instruments.
(3)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $368.8 million and $384.5 million as of June 30, 2017 and December 31, 2016, respectively, based on reported market trades of these instruments.
(4)
The aggregate estimated fair value of the 8.75% Senior Notes was approximately $234.6 million as of June 30, 2017 based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.4 million and $2.6 million as of June 30, 2017 and December 31, 2016, respectively. As 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 long-term debt includes the current portion of the Lease Financing Obligation.

Amended Credit Facility

The Company's amended revolving credit facility ("Amended Credit Facility") had commitments from 13 lenders and a borrowing base of $300.0 million as of June 30, 2017. As credit support for future payments 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 June 30, 2017 to $274.0 million. There have not been any borrowings under the Amended Credit Facility to date in 2017 and there were no such borrowings in 2016.

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.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of the Company's proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. In April 2017, the Company's borrowing base was re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at December 31, 2016. Future borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the Company's lenders, as well as any other outstanding debt. Lower commodity prices could result in a decreased borrowing base.

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 since issuance. If the Company fails to comply with the covenants or other terms of any agreements governing the Company's debt, the Company's lenders and holders of the Company's senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect the Company's financial condition. In September 2015, the Company obtained an amendment to the Amended Credit Facility that replaced the Company's debt-to-EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses) covenant in the facility with a

14


secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that the Company will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

5% Convertible Senior Notes Due 2028

On May 30, 2017, the Company redeemed the $0.6 million of outstanding Convertible Notes with the proceeds of its 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes due 2025" below for additional information.

7.625% Senior Notes Due 2019

On May 30, 2017, the Company redeemed the $315.3 million of outstanding 7.625% Senior Notes with cash on hand and proceeds from its 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes due 2025" below for additional information.

Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, the Company recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the three and six months ended June 30, 2017.

The 7.625% Senior Notes were issued at $400.0 million in principal amount on September 27, 2011. On June 3, 2016, the Company completed a debt exchange with a holder of the 7.625% Senior Notes (the "Debt Exchange"). The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the Company’s common stock. Based on the fair value of the shares issued, the Company recognized an $8.7 million gain on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2016. Following the Debt Exchange, the remaining aggregate principal amount was $315.3 million, which was then redeemed on May 30, 2017.

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 October 15, 2022 at par. The 7.0% Senior Notes mature on October 15, 2022, unless earlier redeemed or purchased by the Company. 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 8.75% Senior Notes. The 7.0% Senior Notes will become redeemable at the Company's option on or after October 15, 2017, 2018, 2019 and 2020 at redemption prices of 103.500%, 102.333%, 101.167% and 100.000% of the principal amount, respectively. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 8.75% 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 covenants and has complied with all covenants since issuance.

8.75% Senior Notes Due 2025

On April 28, 2017, the Company issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year, commencing on December 15, 2017. The 8.75% 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 7.0% Senior Notes.

The 8.75% Senior Notes will become redeemable at the Company's option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, the Company may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, the Company may redeem the notes at a redemption price equal to 100.000% of the principal amount plus a specified "make-whole" premium.

The 8.75% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company's indebtedness under the Amended Credit Facility and the 7.0% Senior Notes. The 8.75% 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 covenants and has complied with all covenants since issuance.


15


Nothing in the 7.0% Senior Notes or the 8.75% Senior Notes prohibits the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

Lease Financing Obligation Due 2020

The Company has a lease financing obligation with a balance of $2.6 million as of June 30, 2017 resulting from the Company's sale and subsequent lease back of certain compressors and related facilities owned by the Company (the "Lease Financing Obligation"). 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 a discussion of aggregate minimum future lease payments.

6. Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the six months ended June 30, 2017 is as follows (in thousands):
As of December 31, 2016
$
11,238

Liabilities incurred (1)
10,129

Liabilities settled
(465
)
Accretion expense
490

Revisions to estimate
881

As of June 30, 2017
$
22,273

Less: current asset retirement obligations
1,512

Long-term asset retirement obligations
$
20,761


(1)
Includes $8.7 million associated with properties acquired in the DJ Basin during the six months ended June 30, 2017. See Note 4 for additional information regarding this acquisition.

7. Fair Value Measurements

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 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. 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 2 – Quoted prices are available in active markets for similar assets or liabilities and in non-active markets for identical or similar instruments. Model-derived valuations have inputs that are observable or whose significant value drivers are observable. 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.

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.


16


The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were measured at fair value in the Unaudited Consolidated Balance Sheets.

 
As of June 30, 2017
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets
 
 
 
 
 
 
 
Cash equivalents (1)
$
120,520

 
$

 
$

 
$
120,520

Deferred compensation plan (1)
1,642

 

 

 
1,642

Commodity derivatives (1)

 
25,512

 

 
25,512

Unproved oil and gas properties (2)

 

 
1,088

 
1,088

Liabilities
 
 
 
 
 
 
 
Commodity derivatives (1)
$

 
$
96

 
$

 
$
96


(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.
(2)
This represents a non-financial asset or liability that is measured at fair value on a nonrecurring basis.

 
As of December 31, 2016
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets
 
 
 
 
 
 
 
Cash equivalents (1)
$
40,115

 
$

 
$

 
$
40,115

Deferred compensation plan (1)
1,447

 

 

 
1,447

Commodity derivatives (1)

 
13,156

 

 
13,156

Liabilities
 
 
 
 
 
 
 
Commodity derivatives (1)
$

 
$
10,003

 
$

 
$
10,003


(1)
This represents a financial asset or liability that is measured at fair value on a recurring basis.

Cash equivalents – The highly liquid cash equivalents are recorded at carrying value. Carrying value approximates fair value, which represents a Level 1 input.

Deferred compensation plan – 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 deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Commodity derivatives – 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. The inputs discussed above all represent Level 2 inputs.

The commodity derivatives 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.

Oil and gas properties 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. If an impairment is necessary, the fair value is estimated by 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

17


production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. During the six months ended June 30, 2017, the Company reduced its unproved Cottonwood Gulch assets in the Piceance Basin to a fair value of $1.1 million, resulting in a non-cash impairment charge of $8.0 million. During the year ended December 31, 2016, no properties were measured at fair value.

Acquisitions of proved and unproved properties – Assets acquired and liabilities assumed under transactions that meet the criteria of a business combination under ASC Topic 805, Business Combinations are recorded at fair value on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and gas properties include estimates of reserves, production rates, future operating and development costs, future commodity prices including price differentials, future cash flows and a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

Assets acquired and liabilities assumed under transactions that do not meet the criteria of a business combination under ASC Topic 805, Business Combinations are accounted for as asset acquisitions and are recorded based on the fair value of the total consideration transferred on the acquisition date using the lowest observable inputs available. The Company acquired proved and unproved properties in the DJ Basin for total cash consideration of $12.0 million during the six months ended June 30, 2017. See Note 4 for additional information regarding this asset acquisition.

Long-term Debt – Long-term debt is not presented at fair value on the Unaudited Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The Company issued 8.75% Senior Notes on April 28, 2017 and redeemed its 7.625% Senior Notes on May 30, 2017. The fair values of the Company's fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $603.4 million as of June 30, 2017. The fair values of the Company's fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $699.0 million as of December 31, 2016. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility or Lease Financing Obligation and there was no such market for the Convertible Notes when they were outstanding. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company's borrowing base utilization. The Amended Credit Facility had a balance of zero as of June 30, 2017 and December 31, 2016. The Convertible Notes were redeemed on May 30, 2017 and had a fair value of $0.5 million as of December 31, 2016. The Lease Financing Obligation fair values of $2.4 million and $2.6 million as of June 30, 2017 and December 31, 2016, 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.

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 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.


18


  
As of June 30, 2017
 
Balance Sheet
Gross Amounts of
Recognized Assets
 
Gross Amounts
Offset in the Balance
Sheet
 
Net Amounts of Assets Presented in the
Balance Sheet
 
 
(in thousands)
 
Derivative assets (current)
$
22,442

 
$
(37
)
(1) 
$
22,405

 
Derivative assets (noncurrent)
3,070

 
(59
)
(1) 
3,011

 
Total derivative assets
$
25,512

 
$
(96
)
 
$
25,416

 
 
Gross Amounts of
Recognized Liabilities
 
Gross Amounts
Offset in the Balance
Sheet
 
Net Amounts of Liabilities Presented in
the Balance Sheet
 
 
(in thousands)
 
Derivative liabilities
$
(37
)
 
$
37

(1) 
$

 
Derivatives and other noncurrent liabilities
(59
)
 
59

(1) 

(2) 
Total derivative liabilities
$
(96
)
 
$
96

  
$

 
 
 
 
 
 
 
 
  
As of December 31, 2016
 
Balance Sheet
Gross Amounts of
Recognized Assets
 
Gross Amounts
Offset in the Balance
Sheet
 
Net Amounts of Assets Presented in the
Balance Sheet
 
 
(in thousands)
 
Derivative assets (current)
$
13,156

 
$
(4,758
)
(1) 
$
8,398

 
Derivative assets (noncurrent)

 

 

 
Total derivative assets
$
13,156

 
$
(4,758
)
 
$
8,398

 
 
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
$
(9,104
)
 
$
4,758

(1) 
$
(4,346
)
 
Derivatives and other noncurrent liabilities
(899
)
 

 
(899
)
(2) 
Total derivative liabilities
$
(10,003
)
 
$
4,758

  
$
(5,245
)
 
 
(1)
Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.
(2)
As of June 30, 2017 and December 31, 2016, this line item on the Unaudited Consolidated Balance Sheet included $3.8 million and $5.4 million, respectively, of other noncurrent liabilities.

As of June 30, 2017, 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:

 
July – December 2017
 
For the year 2018
 
Derivative
Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
Oil (Bbls)
1,311,000

 
$
58.77

 
2,049,750

 
$
52.86

Natural Gas (MMbtu)
1,840,000

 
$
2.96

 

 
$


The Company's derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments 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 six different counterparties as of June 30, 2017. 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 these counterparties.


19


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. 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, the Company may not be able to set-off amounts owed by it 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 six months ended June 30, 2017 and 2016, 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 six months ended June 30, 2017 and 2016.

Income tax benefit for the three and six months ended June 30, 2017 and 2016 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 six months ended June 30, 2017 and 2016, the effective tax rate remained at zero as a result of recording a full valuation allowance against the deferred tax asset balance. 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 judgement is required in considering the relative weight of negative and positive evidence. 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.

10. Stockholders' Equity

Common and Preferred Stock. The Company's authorized capital structure consists of 75,000,000 shares of preferred stock, par value of $0.001 per share, and 300,000,000 shares of common stock, par value of $0.001 per share. At the annual meeting on May 16, 2017, the proposal to increase the number of authorized shares of common stock from 150,000,000 to 300,000,000 was approved. There are no issued and outstanding shares of preferred stock.

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 June 30, 2017, and the date of this filing, no shares have been sold pursuant to the Agreement.

On June 3, 2016, the Company issued 10,000,000 shares of common stock pursuant to a debt exchange with a holder of the Company's 7.625% Senior Notes. The holder exchanged $84.7 million principal amount of the 7.625% Senior Notes for 10,000,000 newly issued shares of the Company’s common stock.

11. 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

20


straight-line basis over the requisite service period (usually the vesting period). Cash-based compensation is measured at fair value at each reporting date and is recognized on a straight-line basis over the requisite service period (usually the vesting period).

The following table presents the long-term cash and equity incentive compensation related to awards for the periods indicated:

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2017
 
2016
 
2017
 
2016
 
(in thousands)
Common stock options (1)
$

 
$

 
$

 
$
69

Nonvested common stock (1)
1,553

 
1,411

 
3,003

 
3,815

Nonvested common stock units (1)
172

 
256

 
342

 
546

Nonvested performance-based shares (1)
89

 
557

 
558

 
1,235

Nonvested performance cash units (2)(3)
(139
)
 
361

 
(1,100
)
 
846

Total
$
1,675

 
$
2,585

 
$
2,803

 
$
6,511


(1)
Unrecognized compensation cost as of June 30, 2017 was $8.3 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.9 years.
(2)
The nonvested performance-based cash units are accounted for as liability awards with $2.1 million and $2.9 million in derivatives and other noncurrent liabilities in the Unaudited Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016, respectively.
(3)
Liability awards are fair valued at each reporting date. For the three months ended June 30, 2017, the weighted average fair value share price decreased from $4.55 as of March 31, 2017 to $3.41 as of June 30, 2017. For the six months ended June 30, 2017, the weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $3.41 as of June 30, 2017.

Nonvested Equity and Cash Awards. The following table presents the equity and cash awards granted pursuant to the Company's various stock compensation plans:


21


 
 
Three Months Ended June 30, 2017
 
Three Months Ended June 30, 2016
Equity Awards
 
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
 
28,017

 
$
3.62

 

 
$

Nonvested common stock units
 
183,353

 
$
3.50

 
90,714

 
$
7.10

Total granted
 
211,370

 
 
 
90,714

 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2017
 
Three Months Ended June 30, 2016
Cash Awards
 
Number of
Units
 
Fair Value
Per Unit
 
Number of
Units
 
Fair Value
Per Unit
Nonvested performance cash units
 
25,017

 
$
3.07

 

 
$

 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2017
 
Six Months Ended June 30, 2016
Equity Awards
 
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
 
777,244

 
$
6.01

 
686,500

 
$
5.11

Nonvested common stock units
 
186,924

 
$
3.52

 
93,728

 
$
7.07

Total granted
 
964,168

 
 
 
780,228

 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2017
 
Six Months Ended June 30, 2016
Cash Awards
 
Number of
Units
 
Fair Value
Per Unit
 
Number of
Units
 
Fair Value
Per Unit
Nonvested performance cash units
 
658,158

 
$
3.07

 
646,572

 
$
6.39


Performance Cash Program

2017 Program. In February 2017, the Compensation Committee approved a performance cash program (the "2017 Program") granting performance cash units that will settle in cash. The performance-based awards contingently vest in February 2020, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three-year period ending December 31, 2019, will be the Company's total shareholder return ("TSR") based on a matrix measurement of (1) the Company's absolute performance and (2) the Company's ranking relative to a defined peer group's individual TSRs ("Relative TSR"). The Company's absolute performance is measured against the December 30, 2016 closing share price of $6.99. If the Company's absolute performance is lower than the $6.99 share price, the payout is zero for this portion. If the Company's absolute performance is greater than the $6.99 share price, the performance cash units will vest 1% for each 1% in growth, up to 100% of the original grant. If the Company's Relative TSR is less than the median, the payout is zero for this portion. If the Company's Relative TSR is above the median, the payout is equal to twice the Company's percentile rank above the median, up to 100% of the original grant. The Company's combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant. A total of 658,158 units were granted under this program during the six months ended June 30, 2017.

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. The Lease Financing Obligation contains an early buyout option pursuant to which the Company may purchase the equipment for $1.8 million on February 10, 2019.

 
As of June 30, 2017
 
(in thousands)
2017
$
269

2018
537

2019
1,824

Total
$
2,630


22



Transportation Charges. The Company is party to two firm transportation contracts, through July 2021, to provide capacity on natural gas pipeline systems. The contracts require the Company to pay transportation charges regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 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 June 30, 2017
 
(in thousands)
2017
$
9,190

2018
18,691

2019
18,691

2020
18,691

2021
10,902

Thereafter

Total
$
76,165


Lease and Other Commitments. The Company leases office space, vehicles and certain office equipment. In addition, the Company has various long-term agreements for telecommunication services. Future minimum annual payments under lease and other agreements are as follows:

 
As of June 30, 2017
 
(in thousands)
2017
$
1,673

2018
3,019

2019
1,055

2020
100

2021
7

Thereafter

Total
$
5,854


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 7.0% Senior Notes and 8.75% Senior 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 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.

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 June 30, 2017
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
155,565

 
$

 
$

 
$
155,565

Other current assets
55,297

 
189

 

 
55,486

Property and equipment, net
1,100,573

 
5,502

 

 
1,106,075

Intercompany receivable
20,454

 

 
(20,454
)
 

Investment in subsidiaries
(14,823
)
 

 
14,823

 

Noncurrent assets
6,068

 

 

 
6,068

Total assets
$
1,323,134

 
$
5,691

 
$
(5,631
)
 
$
1,323,194

Liabilities and Stockholders' Equity:
 
 
 
 
 
 
 
Current liabilities
$
87,859

 
$

 
$

 
$
87,859

Intercompany payable

 
20,454

 
(20,454
)
 

Long-term debt
668,545

 

 

 
668,545

Other noncurrent liabilities
24,466

 
60

 

 
24,526

Stockholders' equity
542,264

 
(14,823
)
 
14,823

 
542,264

Total liabilities and stockholders' equity
$
1,323,134

 
$
5,691

 
$
(5,631
)
 
$
1,323,194

 
 
As of December 31, 2016
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Cash and cash equivalents
$
275,841

 
$

 
$

 
$
275,841

Other current assets
42,433

 
178

 

 
42,611

Property and equipment, net
1,056,343

 
5,806

 

 
1,062,149

Intercompany receivable
20,678

 

 
(20,678
)
 

Investment in subsidiaries
(14,751
)
 

 
14,751

 

Noncurrent assets
4,740

 

 

 
4,740

Total assets
$
1,385,284

 
$
5,984

 
$
(5,927
)
 
$
1,385,341

Liabilities and Stockholders' Equity:
 
 
 
 
 
 
 
Current liabilities
$
85,018

 
$

 
$

 
$
85,018

Intercompany payable

 
20,678

 
(20,678
)
 

Long-term debt
711,808

 

 

 
711,808

Other noncurrent liabilities
16,915

 
57

 

 
16,972

Stockholders' equity
571,543

 
(14,751
)
 
14,751

 
571,543

Total liabilities and stockholders' equity
$
1,385,284

 
$
5,984

 
$
(5,927
)
 
$
1,385,341


24



Condensed Consolidating Statements of Operations 

 
Three Months Ended June 30, 2017
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
50,919

 
$
147

 
$

 
$
51,066

Operating expenses
(52,452
)
 
(167
)
 

 
(52,619
)
General and administrative
(8,943
)
 

 

 
(8,943
)
Interest income and other income (expense)
(7,951
)
 

 

 
(7,951
)
Income (loss) before income taxes and equity in earnings of subsidiaries
(18,427
)
 
(20
)
 

 
(18,447
)
(Provision for) Benefit from income taxes

 

 

 

Equity in earnings (loss) of subsidiaries
(20
)
 

 
20

 

Net income (loss)
$
(18,447
)
 
$
(20
)
 
$
20

 
$
(18,447
)
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2017
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
101,344

 
$
258

 
$

 
$
101,602

Operating expenses
(109,310
)
 
(330
)
 

 
(109,640
)
General and administrative
(18,292
)
 

 

 
(18,292
)
Interest income and other income (expense)
(5,232
)
 

 

 
(5,232
)
Income (loss) before income taxes and equity in earnings of subsidiaries
(31,490
)
 
(72
)
 

 
(31,562
)
(Provision for) benefit from income taxes

 

 

 

Equity in earnings (loss) of subsidiaries
(72
)
 

 
72

 

Net income (loss)
$
(31,562
)
 
$
(72
)
 
$
72

 
$
(31,562
)


25


 
Three Months Ended June 30, 2016
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
47,139

 
$
145

 
$

 
$
47,284

Operating expenses
(56,956
)
 
(161
)
 

 
(57,117
)
General and administrative
(9,937
)
 

 

 
(9,937
)
Interest and other income (expense)
(28,649
)
 

 

 
(28,649
)
Income (loss) before income taxes and equity in earnings of subsidiaries
(48,403
)
 
(16
)
 

 
(48,419
)
(Provision for) Benefit from income taxes

 

 

 

Equity in earnings of subsidiaries
(16
)
 

 
16

 

Net income (loss)
$
(48,419
)
 
$
(16
)
 
$
16

 
$
(48,419
)
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2016
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
76,405

 
$
313

 
$

 
$
76,718

Operating expenses
(113,261
)
 
(325
)
 

 
(113,586
)
General and administrative
(22,357
)
 

 

 
(22,357
)
Interest and other income (expense)
(35,690
)
 

 

 
(35,690
)
Income (loss) before income taxes and equity in earnings of subsidiaries
(94,903
)
 
(12
)
 

 
(94,915
)
(Provision for) benefit from income taxes

 

 

 

Equity in earnings (loss) of subsidiaries
(12
)
 

 
12

 

Net income (loss)
$
(94,915
)
 
$
(12
)
 
$
12

 
$
(94,915
)

Condensed Consolidating Statements of Comprehensive Income (Loss)
 
 
Three Months Ended June 30, 2017
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(18,447
)
 
$
(20
)
 
$
20

 
$
(18,447
)
Other comprehensive income (loss)

 

 

 

Comprehensive income (loss)
$
(18,447
)
 
$
(20
)
 
$
20

 
$
(18,447
)
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2017
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(31,562
)
 
$
(72
)
 
$
72

 
$
(31,562
)
Other comprehensive income (loss)

 

 

 

Comprehensive income (loss)
$
(31,562
)
 
$
(72
)
 
$
72

 
$
(31,562
)


26


 
Three Months Ended June 30, 2016
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(48,419
)
 
$
(16
)
 
$
16

 
$
(48,419
)
Other comprehensive income (loss)

 

 

 

Comprehensive income (loss)
$
(48,419
)
 
$
(16
)
 
$
16

 
$
(48,419
)
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2016
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(94,915
)
 
$
(12
)
 
$
12

 
$
(94,915
)
Other comprehensive income (loss)

 

 

 

Comprehensive income (loss)
$
(94,915
)
 
$
(12
)
 
$
12

 
$
(94,915
)

Condensed Consolidating Statements of Cash Flows
 
 
Six Months Ended June 30, 2017
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Cash flows from operating activities
$
37,975

 
$
224

 
$

 
$
38,199

Cash flows from investing activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
(104,236
)
 

 

 
(104,236
)
Additions to furniture, fixtures and other
(201
)
 

 

 
(201
)
Proceeds from sale of properties and other investing activities
(615
)
 

 

 
(615
)
Intercompany transfers
224

 

 
(224
)
 

Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from debt
275,000

 

 

 
275,000

Principal payments on debt
(322,113
)
 

 

 
(322,113
)
Proceeds from sale of common stock, net of offering costs
(298
)
 

 

 
(298
)
Intercompany transfers

 
(224
)
 
224

 

Other financing activities
(6,012
)
 

 

 
(6,012
)
Change in cash and cash equivalents
(120,276
)
 

 

 
(120,276
)
Beginning cash and cash equivalents
275,841

 

 

 
275,841

Ending cash and cash equivalents
$
155,565

 
$

 
$

 
$
155,565

 

27


 
Six Months Ended June 30, 2016
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Cash flows from operating activities
$
48,426

 
$
353

 
$

 
$
48,779

Cash flows from investing activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
(86,666
)
 
(14
)
 

 
(86,680
)
Additions to furniture, fixtures and other
(991
)
 

 

 
(991
)
Proceeds from sale of properties and other investing activities
(1,225
)
 

 

 
(1,225
)
Intercompany transfers
339

 

 
(339
)
 

Cash flows from financing activities:
 
 
 
 
 
 
 
Principal payments on debt
(218
)
 

 

 
(218
)
Intercompany transfers

 
(339
)
 
339

 

Other financing activities
(1,078
)
 

 

 
(1,078
)
Change in cash and cash equivalents
(41,413
)
 

 

 
(41,413
)
Beginning cash and cash equivalents
128,836

 

 

 
128,836

Ending cash and cash equivalents
$
87,423

 
$

 
$

 
$
87,423

  
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 future plans, estimates, beliefs and expected performance of Bill Barrett Corporation (the "Company", "we", "us" or "our"). 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;
declines in the values of our oil and natural gas properties resulting in impairments;
reduction of proved undeveloped reserves due to failure to develop within the five-year development window defined by the Securities and Exchange Commission;
derivative and hedging activities;
legislative, judicial or regulatory changes including initiatives to impose standard setbacks from occupied structures and other sensitive areas, initiatives to give local governmental authorities the ability to further regulate or to ban oil and gas development activities within their boundaries, and 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;
possible inability to complete planned dispositions;
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 and availability of capital;
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;

28



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 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, 2016 under the headings "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" 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 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 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 were formed in January 2002 and are incorporated in the State of Delaware. In December 2004, we completed our initial public offering. In December 2016, we completed an additional public offering of our common stock, selling 15,525,000 shares at a price of $7.40 per share. The sale included the full exercise by the underwriters of their option to purchase 2,025,000 shares of common stock.

On April 28, 2017, we issued $275.0 million in aggregate principal amount of 8.75% senior unsecured notes due 2025, at par. We used the net proceeds from the offering, together with available cash on hand, to fund the redemption and repurchase of all of our outstanding 7.625% Senior Notes due 2019 and all of our outstanding 5% Convertible Senior Notes due 2028.

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 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, other indebtedness, sales of properties, and/or the issuance of 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.

As a result of acquisitions and dispositions of properties, 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 necessarily indicative of future results.

Commodity prices are inherently volatile and are influenced by many factors outside of our control. As of July 18, 2017, we have hedged 1,311,000 barrels of oil and 1,840,000 MMbtu of natural gas, or approximately 50% of our expected remaining 2017 production, and 2,049,750 barrels of oil for 2018 at price levels that provide some economic certainty to our cash flows. We focus our efforts on increasing oil, natural gas and NGLs reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.

29



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 June 30, 2017 Compared with Three Months Ended June 30, 2016
 
 
Three Months Ended June 30,
 
Increase (Decrease)
2017
 
2016
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
50,941

 
$
47,025

 
$
3,916

 
8
 %
Other operating revenues
125

 
259

 
(134
)
 
(52
)%
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
5,506

 
8,479

 
(2,973
)
 
(35
)%
Gathering, transportation and processing expense
535

 
611

 
(76
)
 
(12
)%
Production tax expense
3,434

 
3,520

 
(86
)
 
(2
)%
Exploration expense
3

 
21

 
(18
)
 
(86
)%
Impairment, dry hole costs and abandonment expense
1

 
234

 
(233
)
 
(100
)%
(Gain) loss on sale of properties

 
(708
)
 
708

 
*nm

Depreciation, depletion and amortization
39,337

 
40,392

 
(1,055
)
 
(3
)%
Unused commitments
4,558

 
4,568

 
(10
)
 
 %
General and administrative expense (1)
8,943

 
9,937

 
(994
)
 
(10
)%
Other operating expense, net
(755
)
 

 
(755
)
 
*nm

Total operating expenses
$
61,562

 
$
67,054

 
$
(5,492
)
 
(8
)%
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
902

 
1,023

 
(121
)
 
(12
)%
Natural gas (MMcf)
1,920

 
1,944

 
(24
)
 
(1
)%
NGLs (MBbls)
304

 
260

 
44

 
17
 %
Combined volumes (MBoe)
1,526

 
1,607

 
(81
)
 
(5
)%
Daily combined volumes (Boe/d)
16,769

 
17,659

 
(890
)
 
(5
)%
Average Realized Prices Before Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
45.83

 
$
39.93

 
$
5.90

 
15
 %
Natural gas (per Mcf)
2.43

 
1.50

 
0.93

 
62
 %
NGLs (per Bbl)
16.20

 
12.55

 
3.65

 
29
 %
Combined (per Boe)
33.38

 
29.26

 
4.12

 
14
 %
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
52.39

 
$
63.34

 
$
(10.95
)
 
(17
)%
Natural gas (per Mcf)
2.56

 
2.07

 
0.49

 
24
 %
NGLs (per Bbl)
16.20

 
12.55

 
3.65

 
29
 %
Combined (per Boe)
37.42

 
44.84

 
(7.42
)
 
(17
)%
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
3.61

 
$
5.28

 
$
(1.67
)
 
(32
)%
Gathering, transportation and processing expense
0.35

 
0.38

 
(0.03
)
 
(8
)%
Production tax expense
2.25

 
2.19

 
0.06

 
3
 %
Depreciation, depletion and amortization (2)
25.78

 
27.05

 
(1.27
)
 
(5
)%
General and administrative expense (1)
5.86

 
6.18

 
(0.32
)
 
(5
)%

*
Not meaningful.
(1)
Included in general and administrative expense is long-term cash and equity incentive compensation of $1.7 million (or $1.10 per Boe) and $2.6 million (or $1.61 per Boe) for the three months ended June 30, 2017 and 2016, respectively.The
(2)
DD&A rate per Boe excludes production of 114 MBoe associated with our properties that were classified as held for sale in the Uinta basin, as these were not depleted throughout the quarter ended June 30, 2016.



31



Production Revenues and Volumes. Production revenues increased to $50.9 million for the three months ended June 30, 2017 from $47.0 million for the three months ended June 30, 2016. The increase in production revenues was due to a 14% increase in average realized prices before hedging, offset by a 5% decrease in production volumes. The increase in average realized prices before hedging increased production revenues by approximately $6.6 million, while the decrease in production volumes reduced production revenues by approximately $2.7 million.

The 5% decrease in total production from the three months ended June 30, 2016 to the three months ended June 30, 2017 was primarily due to a 32% decrease in production from the Uinta Oil Program due to the sale of certain non-core Uinta Oil Program assets during July 2016, offset by a slight increase in the DJ Basin as a result of new wells placed into production, and increased production from remaining properties in the Uinta Oil Program as a result of recompletion activity during the three months ended June 30, 2017. Additional information concerning production is in the following table:

 
Three Months Ended June 30, 2017
 
Three Months Ended June 30, 2016
 
% 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
715

301

1,800

1,316

 
783

243

1,584

1,290

 
(9
)%
24
 %
14
 %
2
 %
Uinta Oil Program
186

3

120

209

 
239

16

318

308

 
(22
)%
(81
)%
(62
)%
(32
)%
Other
1



1

 
1

1

42

9

 
 %
*nm

*nm

(89
)%
Total
902

304

1,920

1,526

 
1,023

260

1,944

1,607

 
(12
)%
17
 %
(1
)%
(5
)%

*
Not meaningful.

Lease Operating Expense ("LOE"). LOE decreased to $3.61 per Boe for the three months ended June 30, 2017 from $5.28 per Boe for the three months ended June 30, 2016. The decrease per Boe for the three months ended June 30, 2017 compared with the three months ended June 30, 2016 is primarily related to operational efficiencies and sales of certain non-core assets in the Uinta Oil Program during July 2016, which had relatively high LOE costs on a per Boe basis.

Production Tax Expense. Total production taxes decreased to $3.4 million for the three months ended June 30, 2017 from $3.5 million for the three months ended June 30, 2016. 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 6.7% and 7.5% for the three months ended June 30, 2017 and June 30, 2016, 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 June 30, 2017 and 2016 is summarized below:

 
Three Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Dry hole expense
$

 
$
13

Abandonment expense/ Lease expirations
1

 
221

Total impairment, dry hole costs and abandonment expense
$
1

 
$
234


We review our oil and natural gas properties 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. We estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare 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

32


undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market value. The factors used to determine fair value may 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 commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined 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, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

Unproved oil and gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.

Given current and projected 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.

Our current recoverability test on our existing oil and gas properties as of June 30, 2017 uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments 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 June 30, 2017 results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.


Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $39.3 million for the three months ended June 30, 2017 compared with $40.4 million for the three months ended June 30, 2016. The decrease of $1.1 million was primarily due to a 5% decrease in production volumes for the three months ended June 30, 2017 compared with the three months ended June 30, 2016.

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 June 30, 2017, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $25.78 per Boe compared with $27.05 per Boe for the three months ended June 30, 2016.

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. The agreements expire July 31, 2021. Unused commitments expense for each of the three months ended June 30, 2017 and June 30, 2016 consisted of $4.6 million related to these contracts.


33


General and Administrative Expense. General and administrative expense decreased to $8.9 million for the three months ended June 30, 2017 from $9.9 million for the three months ended June 30, 2016 primarily due to a decrease in long-term cash and equity compensation discussed below.

Included in general and administrative expense is long-term cash and equity incentive compensation of $1.7 million and $2.6 million for the three months ended June 30, 2017 and 2016, respectively. The components of long-term cash and equity incentive compensation for the three months ended June 30, 2017 and 2016 are shown in the following table:

 
Three Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Stock options and nonvested common stock
$
1,642

 
$
1,968

Nonvested common stock units
172

 
256

Performance cash units (1)(2)
(139
)
 
361

Total
$
1,675

 
$
2,585


(1)
The performance cash units will be settled in cash for the performance metrics that are met.
(2)
The performance cash units are accounted for as liability awards and fair valued at each reporting date. The weighted average fair value share price decreased from $4.55 as of March 31, 2017 to $3.41 as of June 30, 2017.

Interest Expense. Interest expense increased to $16.1 million for the three months ended June 30, 2017 from $15.4 million for the three months ended June 30, 2016 primarily due to a charge to interest expense during May 2017 related to our 8.75% Senior Notes issued on April 28, 2017 (see Note 5 to the accompanying financial statements), which were outstanding along with our Convertible Notes and 7.65% Senior Notes. The Convertible Notes and 7.65% Senior Notes were redeemed on May 30, 2017. Interest expense will decrease in future periods due to the redemption of the Convertible Notes and the 7.65% Senior Notes.  

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $15.6 million for the three months ended June 30, 2017 compared with a loss of $22.0 million for the three months ended June 30, 2016. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of June 30, 2017 and 2016 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 June 30,
 
2017
 
2016
 
(in thousands)
Realized gain (loss) on derivatives (1)
$
6,167

 
$
25,043

Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
(737
)
 
(27,863
)
Unrealized gain (loss) on derivatives (1)
10,168

 
(19,160
)
Total commodity derivative gain (loss)
$
15,598

 
$
(21,980
)

(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.

During the three months ended June 30, 2017, approximately 67% of our oil volumes and 45% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $5.9 million and natural gas income of $0.3 million after settlements for all commodity derivatives. During the three months ended June 30, 2016, approximately 65% of our oil volumes and 22% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $23.9 million and natural gas income of $1.1 million after settlements for all commodity derivatives.


34


Income Tax (Expense) Benefit. We recorded an additional valuation allowance of $7.0 million and $18.2 million for the three months ended June 30, 2017 and 2016, respectively, against our deferred tax asset balance, which reduced our effective tax rate to zero. In regard to the valuation allowance recorded against our deferred tax asset balance we considered all available evidence in assessing the need for a valuation allowance. 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. We continue 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. Additionally, for both the 2017 and 2016 periods, our effective tax rate differs from the federal statutory rate 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.


35


Six Months Ended June 30, 2017 Compared with Six Months Ended June 30, 2016

 
Six Months Ended June 30,
 
Increase (Decrease)
2017
 
2016
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
101,366

 
$
76,146

 
$
25,220

 
33
 %
Other operating revenues
236

 
572

 
(336
)
 
(59
)%
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
11,368

 
17,306

 
(5,938
)
 
(34
)%
Gathering, transportation and processing expense
1,024

 
1,399

 
(375
)
 
(27
)%
Production tax expense
3,756

 
3,205

 
551

 
17
 %
Exploration expense
30

 
48

 
(18
)
 
(38
)%
Impairment, dry hole costs and abandonment expense
8,075

 
792

 
7,283

 
*nm

(Gain) loss on sale of properties
(92
)
 
(708
)
 
616

 
87
 %
Depreciation, depletion and amortization
77,677

 
82,408

 
(4,731
)
 
(6
)%
Unused commitments
9,130

 
9,136

 
(6
)
 
 %
General and administrative expense (1)
18,292

 
22,357

 
(4,065
)
 
(18
)%
Other operating expenses, net
(1,328
)
 

 
(1,328
)
 
*nm

Total operating expenses
$
127,932

 
$
135,943

 
$
(8,011
)
 
(6
)%
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
1,727

 
1,909

 
(182
)
 
(10
)%
Natural gas (MMcf)
3,810

 
3,564

 
246

 
7
 %
NGLs (MBbls)
597

 
471

 
126

 
27
 %
Combined volumes (MBoe)
2,959

 
2,974

 
(15
)
 
(1
)%
Daily combined volumes (Boe/d)
16,348

 
16,341

 
7

 
(1
)%
Average Realized Prices Before Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
46.83

 
$
34.20

 
$
12.63

 
37
 %
Natural gas (per Mcf)
2.54

 
1.57

 
0.97

 
62
 %
 NGLs (per Bbl)
18.09

 
11.15

 
6.94

 
62
 %
 Combined (per Boe)
34.25

 
25.60

 
8.65

 
34
 %
Average Realized Prices with Hedging:
 
 
 
 
 
 
 
Oil (per Bbl)
$
52.40

 
$
63.50

 
$
(11.10
)
 
(17
)%
Natural gas (per Mcf)
2.59

 
2.16

 
0.43

 
20
 %
NGLs (per Bbl)
18.09

 
11.15

 
6.94

 
62
 %
Combined (per Boe)
37.56

 
45.11

 
(7.55
)
 
(17
)%
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
3.84

 
$
5.82

 
$
(1.98
)
 
(34
)%
Gathering, transportation and processing expense
0.35

 
0.47

 
(0.12
)
 
(26
)%
Production tax expense
1.27

 
1.08

 
0.19

 
18
 %
Depreciation, depletion and amortization (2)
26.25

 
28.81

 
(2.56
)
 
(9
)%
General and administrative expense (1)
6.18

 
7.52

 
(1.34
)
 
(18
)%

*
Not meaningful.
(1)
Included in general and administrative expense is long-term cash and equity incentive compensation of $2.8 million (or $0.95 per Boe) and $6.5 million (or $2.19 per Boe) for the six months ended June 30, 2017 and 2016, respectively.
(2)
The DD&A rate per Boe excludes production of 114 MBoe associated with our properties that were classified as held for sale in the Uinta Basin, as these were not depleted throughout the quarter ended June 30, 2016.



36



Production Revenues and Volumes. Production revenues increased to $101.4 million for the six months ended June 30, 2017 from $76.1 million for the six months ended June 30, 2016. The increase in production revenues was due to a 34% increase in average realized prices before hedging and a 1% decrease in production volumes. The increase in average realized prices before hedging increased production revenues by approximately $25.7 million, while the decrease in production volumes decreased production revenues by approximately $0.5 million.

The 1% decrease in total production from the six months ended June 30, 2016 to the six months ended June 30, 2017 was primarily due to a 41% decrease in production from the Uinta Oil Program due to the sale of certain non-core Uinta Oil Program assets during July 2016, offset by a 10% increase in the DJ Basin as a result of new wells placed into production, and an increase in production from the remaining properties in the Uinta Oil Program as a result of recompletion activity during the six months ended June 30, 2017. Additional information concerning production is set forth in the following table:

 
Six Months Ended June 30, 2017
 
Six Months Ended June 30, 2016
 
% 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
1,394

592

3,636

2,592

 
1,421

440

2,946

2,352

 
(2
)%
35
 %
23
 %
10
 %
Uinta Oil Program
331

5

168

364

 
487

29

576

612

 
(32
)%
(83
)%
(71
)%
(41
)%
Other
2


6

3

 
1

2

42

10

 
100
 %
*nm

(86
)%
(70
)%
Total
1,727

597

3,810

2,959

 
1,909

471

3,564

2,974

 
(10
)%
27
 %
7
 %
(1
)%

*
Not meaningful.

Lease Operating Expense. LOE decreased to $3.84 per Boe for the six months ended June 30, 2017 from $5.82 per Boe for the six months ended June 30, 2016. The decrease per Boe for the six months ended June 30, 2017 compared with the six months ended June 30, 2016 is primarily related to operational efficiencies and sales of certain non-core assets in the Uinta Oil Program during July 2016, which had relatively high LOE costs on a per Boe basis.

Production Tax Expense. Total production taxes increased to $3.8 million for the six months ended June 30, 2017 from $3.2 million for the six months ended June 30, 2016. Production tax expense for both periods included an annual true-up of Colorado ad valorem tax based on actual assessments and a true-up of the Colorado severance tax. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Excluding the ad valorem and severance tax adjustments, production taxes as a percentage of oil, natural gas and NGL sales were 6.7% and 7.4% for the six months ended June 30, 2017 and June 30, 2016, 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 June 30, 2017 and 2016 are summarized below:

 
Six Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Impairment of unproved oil and gas properties (1)
$
8,010

 
$
183

Dry hole expense
2

 
70

Abandonment expense
63

 
539

Total impairment, dry hole costs and abandonment expense
$
8,075

 
$
792


(1)
We recognized a non-cash impairment charge associated with unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the six months ended June 30, 2017. We have no current plan to develop this acreage.


37


We review our oil and natural gas properties 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. We estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare 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 oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market value. The factors used to determine fair value may 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 commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined 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, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell.

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, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.

Given current and projected 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.

Our current recoverability test on our existing oil and gas properties as of June 30, 2017 uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments 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 June 30, 2017 results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.


Depreciation, Depletion and Amortization. DD&A decreased to $77.7 million for the six months ended June 30, 2017 compared with $82.4 million for the six months ended June 30, 2016. The decrease of $4.7 million was a result of a 9% decrease in the DD&A rate as well as a 1% decrease in production for the six months ended June 30, 2017 compared with the six months ended June 30, 2016. The decrease in the DD&A rate accounted for a $4.3 million decrease in DD&A expense, while the decrease in production accounted for a $0.4 million decrease in 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 six months ended June 30, 2017, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $26.25 per Boe compared with $28.81 per Boe for the six months ended June 30, 2016.

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

38


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 monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021. Unused commitments expense for each of the six months ended June 30, 2017 and 2016 consisted of $9.1 million related to these contracts.

General and Administrative Expense. General and administrative expense decreased to $18.3 million for the six months ended June 30, 2017 from $22.4 million for the six months ended June 30, 2016, primarily due to a decrease in long-term cash and equity compensation discussed below.

Included in general and administrative expense is long-term cash and equity incentive compensation of $2.8 million and $6.5 million for the six months ended June 30, 2017 and 2016, respectively. The components of long-term cash and equity incentive compensation for the six months ended June 30, 2017 and 2016 are shown in the following table:

 
Six Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Stock options and nonvested common stock
$
3,561

 
$
5,119

Nonvested common stock units
342

 
546

Performance cash units (1)(2)
(1,100
)
 
846

Total
$
2,803

 
$
6,511


(1)
The performance cash units will be settled in cash for the performance metrics that are met.
(2)
The performance cash units are accounted for as liability awards and fair valued at each reporting date. The weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $3.41 as of June 30, 2017.

Interest Expense. Interest expense decreased to $30.1 million for the six months ended June 30, 2017 from $31.2 million for the six months ended June 30, 2016 primarily due to the Debt Exchange completed on June 3, 2016 (see Note 5 to the accompanying financial statements), which reduced the principal of our 7.625% Senior Notes by $84.7 million. This decrease was offset by an increase in interest expense during May 2017 due to the issuance of our 8.75% Senior Notes on April 28, 2017, which were outstanding along with our Convertible Notes and 7.65% Senior Notes. The Convertible Notes and 7.65% Senior Notes were redeemed on May 30, 2017.

Commodity Derivative Gain (Loss). Commodity derivative gain (loss) was a gain of $32.1 million for the six months ended June 30, 2017 compared with a loss of $13.3 million for the six months ended June 30, 2016. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of June 30, 2017 and 2016 and during the periods then ended.

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

 
Six Months Ended June 30,
 
2017
 
2016
 
(in thousands)
Realized gain (loss) on derivatives (1)
$
9,799

 
$
58,005

Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
(2,114
)
 
(57,349
)
Unrealized gain (loss) on derivatives (1)
24,377

 
(13,968
)
Total commodity derivative gain (loss)
$
32,062

 
$
(13,312
)

(1)
Realized and unrealized gains and losses on commodity derivatives are presented in the table 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.


39


During the six months ended June 30, 2017, approximately 69% of our oil volumes and 45% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $9.6 million and natural gas income of $0.2 million after settlements for all commodity derivatives. During the six months ended June 30, 2016, approximately 70% of our oil volumes and 24% of our natural gas volumes were subject to financial hedges, which resulted in increased oil income of $55.9 million and natural gas income of $2.1 million after settlements for all commodity derivatives.

Income Tax (Expense) Benefit. We recorded an additional valuation allowance of $11.9 million and $35.8 million for the six months ended June 30, 2017 and 2016, respectively, against our deferred tax asset balance, which reduced our effective tax rate to zero. We consider all available evidence in assessing the need for recording a valuation allowance. 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. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforward, credits and other deferred tax assets will be utilized prior to their expiration. Additionally, for both the six months ended June 30, 2017 and 2016, our effective tax rate before valuation allowance differs from the federal statutory rate because of recording permanent differences for stock-based compensation expense, lobbying and political contributions, and officer compensation as well as state income tax expense.

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, 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, fund planned capital expenditure activities and ensure adequate 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 2017. 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 June 30, 2017, we had cash and cash equivalents of $155.6 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2016, we had cash and cash equivalents of $275.8 million and no amounts outstanding under our Amended Credit Facility. In April 2017, our borrowing base was re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at December 31, 2016. Our effective borrowing capacity is reduced by $26.0 million to $274.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement. 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.

Cash Flow from Operating Activities

Net cash provided by operating activities for the six months ended June 30, 2017 and 2016 was $38.2 million and $48.8 million, respectively. The decrease in net cash provided by operating activities was primarily due to decreases in cash from derivative settlements offset by an increase in production revenues.

Commodity Hedging Activities

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. At June 30, 2017, we had in place crude oil swaps covering portions of our 2017 and 2018 production and natural gas swaps covering portions of our 2017 production.


40


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 June 30, 2017, the estimated fair value of all of our commodity derivative instruments, summarized in the following table, was a net asset of $25.4 million, comprised of current and noncurrent assets. We did not enter into any hedges subsequent to June 30, 2017 through July 18, 2017.

Contract
Total
Hedged
Volumes
 
Quantity
Type
 
Weighted
Average
Fixed
Price
 
Index
Price (1)
 
Fair Market
Value
(in thousands)
Swap Contracts:
 
 
 
 
 
 
 
 
 
2017
 
 
 
 
 
 
 
 
 
Oil
1,311,000

 
Bbls
 
$
58.77

 
WTI
 
$
15,680

Natural gas
1,840,000

 
MMBtu
 
$
2.96

 
NWPL
 
364

2018
 
 
 
 
 
 
 
 
 
Oil
2,049,750

 
Bbls
 
$
52.86

 
WTI
 
9,371

Total
 
 
 
 
 
 
 
 
$
25,415


(1)
WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. 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, affiliates of lenders in the Amended Credit Facility or potential 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. 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, if any, 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:


41


 
Six Months Ended June 30,
Basin/Area
2017
 
2016
 
(in millions)
DJ
$
107.5

 
$
59.3

Uinta Oil Program
10.0

 
1.0

Other
0.2

 
1.1

Total
$
117.7

 
$
61.4


 
Six Months Ended June 30,
 
2017
 
2016
 
(in millions)
Acquisitions of proved and unproved properties and other real estate
$
15.6

 
$
1.1

Drilling, development, exploration and exploitation of oil and natural gas properties
99.2

 
56.3

Gathering and compression facilities
2.7

 
3.1

Furniture, fixtures and equipment
0.2

 
0.9

Total
$
117.7

 
$
61.4


Our current estimated capital expenditure budget in 2017 is $255.0 million to $285.0 million, with all drilling activities targeting oil. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures are generally discretionary and within our control. If oil, natural gas and NGL prices decline below acceptable levels or costs increase above acceptable levels, 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 do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow.

We believe that we have sufficient available liquidity with available cash on hand, available borrowing under the Amended Credit Facility and cash flow from operations to fund our 2017 budgeted capital expenditures. 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. The Amended Credit Facility had commitments from 13 lenders and a borrowing base of $300.0 million as of June 30, 2017. 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 under the Amended Credit Facility as of June 30, 2017 to $274.0 million. There have not been any borrowings under the Amended Credit Facility to date in 2017 and there were no such borrowings in 2016.

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.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of our proved reserves that have been mortgaged to the lenders, and is subject to regular re-determinations on or about April 1 and October 1 of each year, as well as following any property sales. In April 2017, our borrowing base was re-confirmed at $300.0 million based on proved reserves and the commodity hedge position in place at December 31, 2016. Future borrowing bases will be computed based on proved oil, natural gas and NGL 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. Lower commodity prices will generally result in a lower borrowing base.

The Amended Credit Facility contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2017 budget at current commodity prices. However, if commodity prices significantly decline, our EBITDAX, which is a critical underpinning of our required financial covenants, will be significantly reduced. If this were to occur, it may become necessary for us to negotiate an amendment to one or more of these financial covenants. In September

42


2015, we obtained an amendment to the Amended Credit Facility that replaced our debt-to-EBITDAX covenant in the facility with a secured debt-to-EBITDAX covenant and an EBITDAX-to-interest covenant through March 31, 2018. There can be no assurance that we will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

If we fail to comply with the covenants or other terms of any agreements governing our debt, including the Amended Credit Facility, our lenders and holders of our senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect our financial condition.

5% Convertible Senior Notes Due 2028. On May 30, 2017, we redeemed our $0.6 million of outstanding Convertible Notes with the proceeds of our 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes Due 2025" below for additional information.

7.625% Senior Notes Due 2019. On May 30, 2017, we redeemed our $315.3 million of outstanding 7.625% Senior Notes with cash on hand and proceeds from our 8.75% Senior Notes issued on April 28, 2017. See "8.75% Senior Notes Due 2025" below for additional information.

Due to the redemption of the Convertible Notes and the 7.625% Senior Notes, the Company recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the three and six months ended June 30, 2017.

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 October 15, 2022 at par. The 7.0% Senior Notes mature on October 15, 2022, unless earlier redeemed or purchased by us. 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 8.75% Senior Notes. The 7.0% Senior Notes will become redeemable at our option on or after October 15, 2017, 2018, 2019 and 2020 at redemption prices of 103.500%, 102.333%, 101.167% and 100.000% of the principal amount, respectively. The 7.0% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee the Amended Credit Facility and the 8.75% 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 covenants and have complied with all covenants since issuance.

8.75% Senior Notes Due 2025. On April 28, 2017, we issued $275.0 million in aggregate principal amount of 8.75% Senior Notes due June 15, 2025 at par. Interest is payable in arrears semi-annually on June 15 and December 15 of each year, commencing on December 15, 2017. The 8.75% 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 7.0% Senior Notes.

The 8.75% Senior Notes will become redeemable at our option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, we may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, we may redeem the notes at a redemption price equal to 100% of the principal amount plus a specified "make-whole" premium.

The 8.75% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility and the 7.0% Senior Notes. The 8.75% 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 covenants and have complied with all covenants since issuance.

Nothing in the 7.0% Senior Notes or the 8.75% Senior Notes prohibits us from repurchasing any of the notes from time to time at any price in open market purchases or negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

Lease Financing Obligation Due 2020. We have a Lease Financing Obligation with a balance of $2.6 million as of June 30, 2017 resulting from our sale and subsequent lease back of 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.


43


Our outstanding debt is summarized below:

 
 
As of June 30, 2017
 
As of December 31, 2016
 
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

 

 

 
579

 

 
579

7.625% Senior Notes (2)
October 1, 2019

 

 

 
315,300

 
(2,169
)
 
313,131

7.0% Senior Notes (3)
October 15, 2022
400,000

 
(3,865
)
 
396,135

 
400,000

 
(4,227
)
 
395,773

8.75% Senior Notes (4)
June 15, 2025
275,000

 
(4,684
)
 
270,316

 

 

 

Lease Financing Obligation (5)
August 10, 2020
2,558

 
(2
)
 
2,556

 
2,782

 
(3
)
 
2,779

Total Debt
 
$
677,558

 
$
(8,551
)
 
$
669,007

 
$
718,661

 
$
(6,399
)
 
$
712,262

Less: Current Portion of Long-Term Debt (6)
 
462

 

 
462

 
454

 

 
454

Total Long-Term Debt
 
$
677,096

 
$
(8,551
)
 
$
668,545

 
$
718,207

 
$
(6,399
)
 
$
711,808


(1)
The Convertible Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the Convertible Notes was approximately $0.5 million as of December 31, 2016 based on reported market trades of these instruments.
(2)
The 7.625% Senior Notes were redeemed on May 30, 2017. The aggregate estimated fair value of the 7.625% Senior Notes was approximately $314.5 million as of December 31, 2016 based on reported market trades of these instruments.
(3)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $368.8 million and $384.5 million as of June 30, 2017 and December 31, 2016, respectively, based on reported market trades of these instruments.
(4)
The aggregate estimated fair value of the 8.75% Senior Notes was approximately $234.6 million as of June 30, 2017 based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.4 million and $2.6 million as of June 30, 2017 and December 31, 2016, 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 long-term debt includes the current portion of the Lease Financing Obligation.

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 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, 7.0% Senior Notes or 8.75% 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 June 30, 2017 is provided in the following table:

 
Payments Due by Year
Year 1
 
Year 2
 
Year 3
 
Year 4
 
Year 5
 
Thereafter
 
Total
 
Twelve Months Ended June 30, 2018
 
Twelve Months Ended June 30, 2019
 
Twelve Months Ended June 30, 2020
 
Twelve Months Ended June 30, 2021
 
Twelve Months Ended June 30, 2022
 
After
June 30, 2022
 
 
 
(in thousands)
Notes payable (1)
$
460

 
$

 
$

 
$

 
$

 
$

 
$
460

7.0% Senior Notes (2)
28,000

 
28,000

 
28,000

 
28,000

 
28,000

 
414,000

 
554,000

8.75% Senior Notes (3)
27,334

 
24,063

 
24,063

 
24,063

 
24,063

 
347,188

 
470,774

Lease Financing Obligation (4)
537

 
2,093

 

 

 

 

 
2,630

Office and office equipment leases and other (5)
3,195

 
2,354

 
280

 
25

 

 

 
5,854

Firm transportation and processing agreements (6)
18,536

 
18,691

 
18,691

 
18,691

 
1,556

 

 
76,165

Asset retirement obligations (7)
1,512

 
240

 
120

 
470

 
393

 
19,538

 
22,273

Total
$
79,574

 
$
75,441

 
$
71,154

 
$
71,249

 
$
54,012

 
$
780,726

 
$
1,132,156


44



(1)
Notes payable includes interest on 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 due April 9, 2020.
(2)
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make semi-annual interest payments through maturity on October 15, 2022 equal to $14.0 million.
(3)
On April 28, 2017, we issued $275.0 million aggregate principal amount of 8.75% Senior Notes. We are obligated to make semi-annual interest payments through maturity on June 15, 2025 equal to $12.0 million. See Note 5 to the accompanying financial statements for additional information.
(4)
The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.
(5)
The lease for our principal office in Denver, Colorado extends through March 2019.
(6)
We have entered into contracts that provide firm transportation capacity on pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount of gas we deliver to the processing facility or pipeline.
(7)
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, 2016 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 June 30, 2017.

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, 2016 for a discussion of trends and uncertainties that may affect our financial condition or liquidity. Also see "Risk Factors" in Part II of this report.

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, 2016 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. 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 six months ended June 30, 2017, our income before income taxes would have decreased by approximately $0.4 million for each $1.00 per barrel decrease in crude oil prices, approximately $0.2 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.5 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

45


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. We do not enter into any market risk sensitive instruments for trading purposes.

As of July 18, 2017, 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."

 
July – December 2017
 
For the year 2018
 
Derivative
Volumes
 
Weighted Average Price
 
Derivative Volumes
 
Weighted Average Price
Oil (Bbls)
1,311,000

 
$
58.77

 
2,049,750

 
$
52.86

Natural Gas (MMbtu)
1,840,000

 
$
2.96

 

 
$


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

Our current recoverability test on our existing oil and gas properties as of June 30, 2017 uses commodity pricing based on market data and a combination of assumptions, which are closely aligned with the assumptions management uses in its budgeting and forecasting process, including adjustments 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 June 30, 2017 results in a surplus of undiscounted future net cash flows over the carrying amount of our oil and gas properties. If the recoverability test described above would result in the carrying amount exceeding undiscounted future estimated net cash flows, and an impairment is necessary, we would reduce the carrying value to fair value. If future commodity prices assumed in the recoverability test are not realized, we could incur a significant impairment. However, there are many other variables besides oil price that are included in the recoverability test that could impact the results.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of June 30, 2017, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Principal 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 Principal Financial Officer concluded that our disclosure controls and procedures are effective as of June 30, 2017.

Changes in Internal Controls. There has been no change in our internal control over financial reporting during the second fiscal quarter of 2017 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, 2016. 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, 2016 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 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.


46


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 June 30, 2017:

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
April 1 – 30, 2017
1,893

 
$
4.02

 

 

May 1 – 31, 2017
63,441

 
3.69

 

 

June 1 – 30, 2017
6,522

 
3.20

 

 

Total
71,856

 
$
3.66

 

 


(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
3.1
 
Amended and Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.1 to our Annual Report on Form 10-K filed with the Commission on March 2, 2017.]
 
 
 
3.1.1
 
Certificate of Amendment to Amended and Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.3 to our Amended Registration Statement on Form S-4/A filed with the Commission on June 14, 2017.]
 
 
 
4.1
 
Indenture for Senior Debt Securities, dated April 28, 2017, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 25.1 to our Registration Statement on Form S-4 filed with the Commission on June 1, 2017.]
 
 
 
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 Principal Financial Officer.

47


Exhibit
Number
 
Description of Exhibits
 
 
 
32.1
  
Section 1350 Certification of Chief Executive Officer.
 
 
 
32.2
  
Section 1350 Certification of Principal 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


48


SIGNATURES

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

 
 
 
 
 
 
 
BILL BARRETT CORPORATION
 
 
 
 
Date:
August 1, 2017
By:
 
/s/ R. Scot Woodall
 
 
 
 
R. Scot Woodall
 
 
 
 
Chief Executive Officer and President
 
 
 
 
(Principal Executive Officer)
 
 
 
 
Date:
August 1, 2017
By:
 
/s/ David R. Macosko
 
 
 
 
David R. Macosko
 
 
 
 
Senior Vice President-Accounting
 
 
 
 
(Principal Accounting Officer)

49