10-Q 1 bbg-3312014x10xq.htm 10-Q BBG-3.31.2014-10-Q

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

FORM 10-Q
 
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2014
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from             to             
Commission file number 001-32367
BILL BARRETT CORPORATION
(Exact name of registrant as specified in its charter)
  
 
Delaware
 
80-0000545
(State or other jurisdiction of
incorporation
or organization)
 
(IRS Employer
Identification No.)
 
1099 18th Street, Suite 2300
Denver, Colorado
 
80202
(Address of principal executive offices)
 
(Zip Code)
(303) 293-9100
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x  Yes    o  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    x  Yes    o  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
x
  
Accelerated filer
 
o
Non-accelerated filer
 
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
 
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    o  Yes    x  No
There were 49,697,526 shares of $0.001 par value common stock outstanding on April 18, 2014.



INDEX TO FINANCIAL STATEMENTS
 

2


PART I. FINANCIAL INFORMATION

ITEM 1.
Consolidated Financial Statements.
BILL BARRETT CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
 
March 31, 2014
 
December 31, 2013
 
(in thousands, except share data)
Assets:
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
62,232

 
$
54,595

Accounts receivable, net of allowance for doubtful accounts
92,049

 
97,586

Derivative assets

 
173

Prepayments and other current assets
4,086

 
4,893

Total current assets
158,367

 
157,247

Property and equipment - at cost, successful efforts method for oil and gas properties:
 
 
 
Proved oil and gas properties
2,967,585

 
2,863,923

Unproved oil and gas properties, excluded from amortization
323,994

 
296,599

Furniture, equipment and other
42,083

 
41,726

 
3,333,662

 
3,202,248

Accumulated depreciation, depletion, amortization and impairment
(1,051,555
)
 
(999,752
)
Total property and equipment, net
2,282,107

 
2,202,496

Deferred financing costs and other noncurrent assets
19,501

 
21,770

Total
$
2,459,975

 
$
2,381,513

Liabilities and Stockholders’ Equity:
 
 
 
Current liabilities:
 
 
 
Accounts payable and accrued liabilities
$
129,128

 
$
115,928

Amounts payable to oil and gas property owners
36,493

 
26,778

Production taxes payable
37,967

 
39,235

Derivative liabilities
20,388

 
5,988

Deferred income taxes
141

 
199

Current portion of long-term debt
4,647

 
4,591

Total current liabilities
228,764

 
192,719

Long-term debt
1,042,889

 
979,082

Asset retirement obligations
39,011

 
39,200

Deferred income taxes
151,081

 
161,326

Derivatives and other noncurrent liabilities
3,305

 
3,468

Stockholders’ equity:
 
 
 
Common stock, $0.001 par value; authorized 150,000,000 shares; 49,713,361 and 49,152,448 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively, with 1,735,984 and 1,340,060 shares subject to restrictions, respectively
48

 
48

Additional paid-in capital
906,314

 
904,261

Retained earnings
87,991

 
100,740

Treasury stock, at cost: zero shares at March 31, 2014 and December 31, 2013, respectively

 

Accumulated other comprehensive income
572

 
669

Total stockholders’ equity
994,925

 
1,005,718

Total
$
2,459,975

 
$
2,381,513

See notes to Unaudited Consolidated Financial Statements.

3


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands, except share and per
share data)
Operating and Other Revenues:
 
 
 
Oil, gas and NGL production
$
127,169

 
$
134,405

Other
519

 
3,872

Total operating and other revenues
127,688

 
138,277

Operating Expenses:
 
 
 
Lease operating expense
16,164

 
18,746

Gathering, transportation and processing expense
11,704

 
15,588

Production tax expense
7,624

 
5,951

Exploration expense
303

 
95

Impairment, dry hole costs and abandonment expense
1,761

 
7,101

Depreciation, depletion and amortization
55,508

 
68,438

General and administrative expense
15,407

 
20,582

Total operating expenses
108,471

 
136,501

Operating Income
19,217

 
1,776

Other Income and Expense:
 
 
 
Interest and other income
375

 
39

Interest expense
(17,431
)
 
(24,542
)
Commodity derivative loss
(25,155
)
 
(29,851
)
Total other income and expense
(42,211
)
 
(54,354
)
Loss before Income Taxes
(22,994
)
 
(52,578
)
Benefit from Income Taxes
(10,245
)
 
(19,427
)
Net Loss
$
(12,749
)
 
$
(33,151
)
Net Loss Per Common Share, Basic
$
(0.27
)
 
$
(0.70
)
Net Loss Per Common Share, Diluted
$
(0.27
)
 
$
(0.70
)
Weighted Average Common Shares Outstanding, Basic
47,890,224

 
47,352,900

Weighted Average Common Shares Outstanding, Diluted
47,890,224

 
47,352,900

See notes to Unaudited Consolidated Financial Statements.

4


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Net Loss
$
(12,749
)
 
$
(33,151
)
Other Comprehensive Loss, net of tax:
 
 
 
Effect of derivative financial instruments
(97
)
 
(1,292
)
Other comprehensive loss
(97
)
 
(1,292
)
Comprehensive Loss
$
(12,846
)
 
$
(34,443
)

See notes to Unaudited Consolidated Financial Statements.

5


BILL BARRETT CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Operating Activities:
 
 
 
Net Loss
$
(12,749
)
 
$
(33,151
)
Adjustments to reconcile to net cash provided by operations:
 
 
 
Depreciation, depletion and amortization
55,508

 
68,438

Deferred income tax benefit
(10,245
)
 
(19,427
)
Impairment, dry hole costs and abandonment expense
1,761

 
7,101

Total commodity derivative loss
25,155

 
29,851

Settlements of commodity derivatives
(9,200
)
 
6,453

Stock compensation and other non-cash charges
3,692

 
6,070

Amortization of debt discounts and deferred financing costs
1,067

 
1,732

Gain on sale of properties

 
(3,519
)
Change in operating assets and liabilities:
 
 
 
Accounts receivable
5,530

 
19,235

Prepayments and other assets
408

 
818

Accounts payable, accrued and other liabilities
6,134

 
(14,089
)
Amounts payable to oil and gas property owners
9,401

 
2,406

Production taxes payable
(1,268
)
 
(4,992
)
Net cash provided by operating activities
75,194

 
66,926

Investing Activities:
 
 
 
Additions to oil and gas properties, including acquisitions
(128,938
)
 
(115,324
)
Additions of furniture, equipment and other
(274
)
 
(445
)
Proceeds from sale of properties and other investing activities
(388
)
 
6,424

Net cash used in investing activities
(129,600
)
 
(109,345
)
Financing Activities:
 
 
 
Proceeds from debt
65,000

 
25,000

Principal payments on debt
(1,137
)
 
(2,241
)
Proceeds from stock option exercises
126

 

Deferred financing costs and other
(1,946
)
 
(1,263
)
Net cash provided by financing activities
62,043

 
21,496

Increase (Decrease) in Cash and Cash Equivalents
7,637

 
(20,923
)
Beginning Cash and Cash Equivalents
54,595

 
79,445

Ending Cash and Cash Equivalents
$
62,232

 
$
58,522

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
 
Treasury
Stock
 
Accumulated
Other
Comprehensive
Income
 
Total
Stockholders’
Equity
Balance at December 31, 2012
$
47

 
$
883,923

 
$
293,473

 
$

 
$
5,332

 
$
1,182,775

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

 
6,384

 

 
(1,778
)
 

 
4,607

APIC pool for excess tax benefits related to share-based compensation

 
(1,259
)
 

 

 

 
(1,259
)
Stock-based compensation

 
16,991

 

 

 

 
16,991

Retirement of treasury stock

 
(1,778
)
 

 
1,778

 

 

Net loss

 

 
(192,733
)
 

 

 
(192,733
)
Effect of derivative financial instruments, net of $2,802 of taxes

 

 

 

 
(4,663
)
 
(4,663
)
Balance at December 31, 2013
$
48

 
$
904,261

 
$
100,740

 
$

 
$
669

 
$
1,005,718

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

 
126

 

 
(1,946
)
 

 
(1,820
)
Stock-based compensation

 
3,873

 

 

 

 
3,873

Retirement of treasury stock

 
(1,946
)
 

 
1,946

 

 

Net loss

 

 
(12,749
)
 

 

 
(12,749
)
Effect of derivative financial instruments, net of $59 of taxes

 

 

 

 
(97
)
 
(97
)
Balance at March 31, 2014
$
48

 
$
906,314

 
$
87,991

 
$

 
$
572

 
$
994,925

See notes to Unaudited Consolidated Financial Statements.

7


BILL BARRETT CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
March 31, 2014
1. Organization
Bill Barrett Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the “Company”) is an independent oil and gas company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (“NGLs”). Since its inception in January 2002, the Company has conducted its activities principally in the Rocky Mountain region of the United States.
2. Summary of Significant Accounting Policies
Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company’s Annual Report on Form 10-K includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2013 Annual Report on Form 10-K.
Use of Estimates. In the course of preparing the Company’s financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.
Areas requiring the use of assumptions, judgments and estimates relate to the expected cash settlement of the Company’s 5% Convertible Senior Notes due 2028 (“Convertible Notes”) in computing diluted earnings per share, volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of 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 undeveloped 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 March 31, 2014
 
As of December 31, 2013
 
(in thousands)
Accrued oil, gas and NGL sales
$
60,015

 
$
67,583

Due from joint interest owners
28,601

 
23,507

Other
3,454

 
6,517

Allowance for doubtful accounts
(21
)
 
(21
)
Total accounts receivable
$
92,049

 
$
97,586

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 included 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 within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows when incurred. The costs of development wells are capitalized whether proved reserves are added or not. Oil and gas lease acquisition costs are also capitalized.


8


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. A gain or loss is recognized for all other sales of proved properties and is classified in other operating revenues. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

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

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

The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company’s oil, natural gas and NGL producing activities:
 
As of March 31, 2014
 
As of December 31, 2013
 
(in thousands)
Proved properties
$
486,080

 
$
485,427

Wells and related equipment and facilities
2,293,630

 
2,192,754

Support equipment and facilities
177,824

 
177,224

Materials and supplies
10,051

 
8,518

Total proved oil and gas properties
$
2,967,585

 
$
2,863,923

Unproved properties
240,455

 
239,925

Wells and facilities in progress
83,539

 
56,674

Total unproved oil and gas properties, excluded from amortization
$
323,994

 
$
296,599

Accumulated depreciation, depletion, amortization and impairment
(1,027,108
)
 
(976,339
)
Total oil and gas properties, net
$
2,264,471

 
$
2,184,183

All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. As of March 31, 2014 and December 31, 2013, there were no exploratory well costs that had been capitalized for a period greater than one year since the completion of drilling.
The Company reviews proved oil and gas properties on a field-by-field basis for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying value of a property exceeds the undiscounted future cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors. The Company has no guarantee that the undiscounted future cash flows analysis of its proved property represents the applicable market value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, 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 expected cash flows projected.

The Company recognized non-cash impairment charges, which were included within impairment, dry hole costs and abandonment expense in the Unaudited Consolidated Statements of Operations, as follows:
 

9


 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Non-cash impairment of proved oil and gas properties (1)
$
1,038

 
$

Non-cash impairment of unproved oil and gas properties

 

Dry hole costs
106

 
851

Abandonment expense
617

 
6,250

Total non-cash impairment, dry hole costs and abandonment expense
$
1,761

 
$
7,101


(1)
Non-cash impairment of proved oil and gas properties for the three months ended March 31, 2014 related to the Company's West Tavaputs properties based upon a true up of previously estimated fair value relative to carrying value. These assets were sold in December 2013. See Note 4.
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 March 31, 2014
 
As of December 31, 2013
 
(in thousands)
Accrued drilling, completion and facility costs
$
73,646

 
$
54,750

Accrued lease operating, gathering, transportation and processing expenses
13,839

 
17,317

Accrued general and administrative expenses
6,249

 
14,605

Trade payables and other
35,394

 
29,256

Total accounts payable and accrued liabilities
$
129,128

 
$
115,928

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.
Revenue Recognition. The Company records revenues from the sales of crude oil, natural gas and NGLs when delivery to the purchaser has occurred. The Company uses the sales method to account for gas and NGL imbalances. Under this method, revenue is 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’ 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 March 31, 2014 and 2013 were not material.
Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities.
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.
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.

10


Earnings/Loss Per Share. Basic net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income per common share is calculated by dividing net income attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested equity shares of common stock, in-the-money outstanding stock options to purchase the Company’s common stock and shares into which the Convertible Notes are convertible.

In satisfaction of its obligation upon conversion of the Convertible Notes, the Company may elect to deliver, at its option, cash, shares of its common stock or a combination of cash and shares of its common stock. As of March 31, 2014, the Company expected to settle the remaining Convertible Notes in cash. Therefore, the treasury stock method was used to measure the potentially dilutive impact of shares associated with that remaining conversion feature. The Company has the right with at least 30 days’ notice to call the Convertible Notes and the holders have the right to require the Company to purchase the notes on March 20, 2015. The Convertible Notes have not been dilutive since their issuance in March 2008 and, therefore, did not impact the diluted net income (loss) per common share calculation for the three months ended March 31, 2014 and 2013. 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 months ended March 31, 2014 and 2013.
The following table sets forth the calculation of basic and diluted loss per share:
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands, except per share amounts)
Net loss
$
(12,749
)
 
$
(33,151
)
Basic weighted-average common shares outstanding in period
47,890

 
47,353

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

 

Diluted weighted-average common shares outstanding in period
47,890

 
47,353

Basic net loss per common share
$
(0.27
)
 
$
(0.70
)
Diluted net loss per common share
$
(0.27
)
 
$
(0.70
)
New Accounting Pronouncements. In July 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The objective of ASU 2013-11 is to provide guidance on financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this standard will not have an impact on the Company’s consolidated financial statements.

3. Supplemental Disclosures of Cash Flow Information
Supplemental cash flow information is as follows:
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Cash paid for interest, net of amount capitalized
$
2,164

 
$
14,506

Cash paid for income taxes

 
1,861

Supplemental disclosures of non-cash investing and financing activities:
 
 
 
Current liabilities
80,356

 
51,942

Net increase in asset retirement obligations
842

 
1,321

Retirement of treasury stock
(1,946
)
 
(1,263
)
4. Divestitures

11


On December 10, 2013, the Company completed the sale of its West Tavaputs natural gas assets in the Uinta Basin (the "West Tavaputs Divestiture"). The Company received $308.7 million in cash proceeds, after closing adjustments. The divestiture proceeds are subject to various purchase price adjustments incurred in the normal course of business and will be finalized during 2014. The Company recognized an impairment loss of $1.0 million during the three months ended March 31, 2014 related to these assets based upon a true up of previously estimated fair value relative to carrying value. The initial impairment loss of $209.5 million was recognized during the year ended December 31, 2013.
5. Long-Term Debt
The Company’s outstanding debt is summarized below:
 
 
 
As of March 31, 2014
 
As of December 31, 2013
 
Maturity Date
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
 
(in thousands)
Amended Credit Facility (1)
October 31, 2016
$
180,000

 
$

 
$
180,000

 
$
115,000

 
$

 
$
115,000

Convertible Notes (2)
March 15, 2028 (3)
25,344

 

 
25,344

 
25,344

 

 
25,344

7.625% Senior Notes (4)
October 1, 2019
400,000

 

 
400,000

 
400,000

 

 
400,000

7.0% Senior Notes (5)
October 15, 2022
400,000

 

 
400,000

 
400,000

 

 
400,000

Lease Financing Obligation (6)
August 10, 2020
42,192

 

 
42,192

 
43,329

 

 
43,329

Total Debt
 
$
1,047,536

 
$

 
$
1,047,536

 
$
983,673

 
$

 
$
983,673

Less: Current Portion of Long-Term Debt
 
4,647

 

 
4,647

 
4,591

 

 
4,591

Total Long-Term Debt
 
$
1,042,889

 
$

 
$
1,042,889

 
$
979,082

 
$

 
$
979,082

 
(1)
The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure.
(2)
The aggregate estimated fair value of the Convertible Notes was approximately $25.5 million and $25.1 million as of March 31, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.
(3)
The Company has the right at any time, with at least 30 days’ notice, to call the Convertible Notes, and the holders have the right to require the Company to purchase the notes on each of March 20, 2015, March 20, 2018 and March 20, 2023.
(4)
The aggregate estimated fair value of the 7.625% Senior Notes was approximately $433.0 million and $430.2 million as of March 31, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $422.0 million and $417.0 million as of March 31, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.
(6)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $40.3 million as of March 31, 2014, and $41.7 million as of December 31, 2013. 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.

Amended Credit Facility
The Company’s Amended Credit Facility has a maturity date of October 31, 2016 and current commitments and borrowing base of $625.0 million. As of March 31, 2014, the Company had $180.0 million outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduced the borrowing capacity of the Amended Credit Facility as of March 31, 2014 to $419.0 million.
Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility were 1.6% and 1.7% for the three months ended March 31, 2014 and 2013, respectively.
The borrowing base is required to be re-determined twice per year. On May 1, 2014, the borrowing base was reaffirmed at $625.0 million based on year-end 2013 reserves and our hedge position. Future semi-annual borrowing bases will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.
The Amended Credit Facility contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.

12


5% Convertible Senior Notes Due 2028
On March 12, 2008, the Company issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to the Company and redeemed by the Company at par. The Company settled the notes in cash. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed or purchased by the Company. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of the Company’s existing and future senior unsecured indebtedness, are senior in right of payment to all of the Company’s future subordinated indebtedness, and are effectively subordinated to all of the Company’s secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of the Company’s subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.
The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require the Company to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. The Company has the right with at least 30 days’ notice to call the Convertible Notes.
7.625% Senior Notes Due 2019
On September 27, 2011, the Company issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The 7.625% Senior Notes are senior unsecured obligations of the Company and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are redeemable at the Company’s option on October 1, 2015 at a redemption price of 103.813% of the principal amount of the notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.
7.0% Senior Notes Due 2022
On March 12, 2012, the Company issued $400.0 million in aggregate principal amount of 7.0% Senior Notes due 2022 at par. The 7.0% Senior Notes mature on October 15, 2022. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the Company’s Convertible Notes and 7.625% Senior Notes. The 7.0% Senior Notes are redeemable at the Company's option on October 15, 2017 at a redemption price of 103.5% of the principal amount of the notes. The 7.0% Senior Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee the Company’s indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.625% Senior Notes. The 7.0% Senior Notes include certain covenants that limit the Company’s ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit the Company from paying dividends. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance.
Lease Financing Obligation Due 2020
On July 23, 2012, the Company entered into the Lease Financing Obligation, whereby the Company received $100.8 million through the sale and subsequent leaseback of existing compressors and related facilities owned by the Company. The Lease Financing Obligation expires on August 10, 2020, and the Company has the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option where the Company may purchase the equipment for $36.6 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 11 for discussion of aggregate minimum future lease payments. As part of the West Tavaputs Divestiture, the purchaser assumed approximately 51% of the Lease Financing Obligation, including the early buyout option related to West Tavaputs.
The following table summarizes, for the periods indicated, the cash or accrued portion of interest expense related to the Amended Credit Facility, the 9.875% Senior Notes that were redeemed in full on July 15, 2013, Convertible Notes, 7.625%

13


Senior Notes, 7.0% Senior Notes and the Lease Financing Obligation along with the non-cash portion resulting from the amortization of the debt discount and transaction costs through interest expense:
 
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Amended Credit Facility (1)
 
Cash interest
$
1,078

 
$
864

Non-cash interest
$
586

 
$
585

9.875% Senior Notes (2)
 
Cash interest
$

 
$
6,172

Non-cash interest
$

 
$
679

Convertible Notes (3)
 
 
 
Cash interest
$
310

 
$
313

Non-cash interest
$
1

 
$
2

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

 
$
7,625

Non-cash interest
$
272

 
$
263

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

 
$
7,000

Non-cash interest
$
203

 
$
195

Lease Financing Obligation (6)
 
 
 
Cash interest
$
262

 
$
787

Non-cash interest
$
4

 
$
8


(1)
Cash interest includes amounts related to interest and commitment fees paid on the Amended Credit Facility and participation and fronting fees paid on the letter of credit.
(2)
The stated interest rate for the 9.875% Senior Notes was 9.875% per annum with an effective interest rate of 11.2% per annum. The Company redeemed the 9.875% Senior Notes in full on July 15, 2013.
(3)
The stated interest rate for the Convertible Notes is 5% per annum. The effective interest rate of the Convertible Notes includes amortization of the debt discount, which represented the fair value of the equity conversion feature at the time of issue. The stated interest rate of 5% on the Convertible Notes will be the effective interest rate of the $25.3 million remaining principal balance, as the related debt discount was fully amortized as of March 31, 2012.
(4)
The stated interest rate for the 7.625% Senior Notes is 7.625% per annum with an effective interest rate of 8.0% per annum.
(5)
The stated interest rate for the 7.0% Senior Notes is 7.0% per annum with an effective interest rate of 7.2% per annum.
(6)
The effective interest rate for the Lease Financing Obligation is 3.3% per annum. The decrease in cash interest from $0.8 million as of March 31, 2013 to $0.3 million as of March 31, 2014 is due to the West Tavaputs Divestiture. The purchaser assumed approximately 51% of the Lease Financing Obligation, including the buyout option related to West Tavaputs, leaving the Company with a balance of $42.2 million as of March 31, 2014.
6. Asset Retirement Obligations
A reconciliation of the Company’s asset retirement obligations for the three months ended March 31, 2014 is as follows (in thousands):

14



As of December 31, 2013
$
43,005

Liabilities incurred
842

Liabilities settled
(352
)
Disposition of properties

Accretion expense
812

Revisions to estimate

As of March 31, 2014
$
44,307

Less: Current asset retirement obligations
5,296

Long-term asset retirement obligations
$
39,011

7. Fair Value Measurements
Assets and Liabilities Measured on a Recurring Basis
The Company’s financial instruments, including cash and cash equivalents, accounts and notes receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Amended Credit Facility, as discussed in Note 5, approximates its fair value due to its floating rate structure based on the LIBOR spread and the Company's borrowing base utilization.
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes a mid-market pricing convention (the mid-point price between bid and ask prices) for valuation as a practical expedient for assigning fair value. The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the market and income approaches for recurring fair value measurements and utilizes the best available information. Given the Company’s historical market transactions, its markets and instruments are fairly liquid. Therefore, the Company has been able to classify fair value balances based on the observability of those inputs. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed securities and U.S. government treasury securities.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.
Level 3 – Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.
The following tables set forth by level within the fair value hierarchy the Company’s financial assets and financial liabilities that were measured at fair value on a recurring basis. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of assets and liabilities and their placement within the fair value hierarchy levels.

15


 
As of March 31, 2014
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets
 
 
 
 
 
 
 
Deferred Compensation Plan
$
651

 
$

 
$

 
$
651

Cash Equivalents - Money Market Funds
53

 

 

 
53

Commodity Derivatives

 
8,556

 

 
8,556

Liabilities
 
 
 
 
 
 
 
Commodity Derivatives
$

 
$
27,954

 
$

 
$
27,954


 
As of December 31, 2013
 
Level 1
 
Level 2
 
Level 3
 
Total
 
(in thousands)
Assets
 
 
 
 
 
 
 
Deferred Compensation Plan
$
941

 
$

 
$

 
$
941

Cash Equivalents - Money Market Funds
53

 

 

 
53

Commodity Derivatives

 
11,483

 

 
11,483

Liabilities
 
 
 
 
 
 
 
Commodity Derivatives
$

 
$
14,771

 
$

 
$
14,771

All fair values reflected in the table above and on the Unaudited Consolidated Balance Sheets have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company. The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above.
Level 1 Fair Value Measurements – The Company maintains a non-qualified deferred compensation plan (as discussed in more detail in Note 10) 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 on the Unaudited Consolidated Balance Sheets. The Company also has highly liquid short term investments in money market funds. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs. The money market fund investments are recorded at carrying value, which approximates fair value, which represent Level 1 inputs. The fair values of the Company’s fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $855.0 million as of March 31, 2014. The fair values of the Company’s fixed rate 7.625% Senior Notes and 7.0% Senior Notes totaled $847.2 million as of December 31, 2013. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.
Level 2 Fair Value Measurements – The fair value of crude oil, natural gas and NGL forwards and options are estimated using a combined income and market valuation methodology with a mid-market pricing convention based upon forward commodity price and volatility curves. The curves are obtained from independent pricing services reflecting broker market quotes. The Company did not make any adjustments to the obtained curves. The pricing services publish observable market information from multiple brokers and exchanges. No proprietary models are used by the pricing services for the inputs. The Company utilized the counterparties’ valuations to assess the reasonableness of the Company’s valuations.
There is no active, public market for the Company’s Amended Credit Facility, Convertible Notes or Lease Financing Obligation. The Amended Credit Facility balance of $180.0 million and $115.0 million as of March 31, 2014 and December 31, 2013, respectively, approximates its fair value due to its floating rate structure. The Convertible Notes fair value of $25.5 million and $25.1 million as of March 31, 2014 and December 31, 2013, respectively, are measured based on market-based parameters of the various components of the Convertible Notes and over the counter trades. The Lease Financing Obligation fair values of $40.3 million and $41.7 million as of March 31, 2014 and December 31, 2013, respectively, are measured based on market-based parameters of comparable term secured financing instruments. The fair value measurements for the Amended Credit Facility, Convertible Notes and Lease Financing Obligation represent Level 2 inputs.
Level 3 Fair Value Measurements – As of March 31, 2014 and December 31, 2013, the Company did not have assets or liabilities that were measured on a recurring basis classified under a Level 3 fair value hierarchy.

16


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 on 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 on the Unaudited Consolidated Balance Sheets as of the dates indicated.
  
As of March 31, 2014
 
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
$
6,107

 
$
(6,107
)
(1) 
$

 
Deferred financing costs and other noncurrent assets
2,449

 
(1,224
)
(1) 
1,225

(2) 
Total derivative assets
$
8,556

 
$
(7,331
)
 
$
1,225

 
 
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
$
(26,495
)
 
$
6,107

(3) 
$
(20,388
)
 
Derivatives and other noncurrent liabilities
(1,459
)
 
1,224

(3) 
(235
)
(4) 
Total derivative liabilities
$
(27,954
)
 
$
7,331

  
$
(20,623
)
 
 
 
 
 
 
 
 
  
As of December 31, 2013
 
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
$
8,259

 
$
(8,086
)
(1) 
$
173

 
Deferred financing costs and other noncurrent assets
3,224

 
(685
)
(1) 
2,539

(2) 
Total derivative assets
$
11,483

 
$
(8,771
)
 
$
2,712

 
 
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
$
(14,074
)
 
$
8,086

(3) 
$
(5,988
)
 
Derivatives and other noncurrent liabilities
(697
)
 
685

(3) 
(12
)
(4) 
Total derivative liabilities
$
(14,771
)
 
$
8,771

  
$
(6,000
)
 
 
(1)
Amounts are netted against derivative asset balances with the same counterparty, and therefore are presented as a net asset on the Unaudited Consolidated Balance Sheets.
(2)
As of March 31, 2014 and December 31, 2013, this line item on the Unaudited Consolidated Balance Sheets includes $18.3 million and $19.2 million of deferred financing costs and other noncurrent assets, respectively.
(3)
Amounts are netted against derivative liability balances with the same counterparty, and therefore are presented as a net liability on the Unaudited Consolidated Balance Sheets.

17


(4)
As of March 31, 2014 and December 31, 2013, this line item on the Unaudited Consolidated Balance Sheets includes $3.1 million and $3.5 million of other noncurrent liabilities, respectively.
The following table summarizes the cash flow hedge gains, net of tax, and their locations on the Unaudited Consolidated Balance Sheets and Unaudited Consolidated Statements of Operations as of the periods indicated:
 
Derivatives Qualifying as
Cash Flow Hedges
 
Three Months Ended March 31,
2014
 
2013
 
 
 
(in thousands)
Amount of Gain Reclassified from AOCI into Income (net of tax) (1) (2)
Commodity Hedges
 
$
97

 
$
1,292

 
(1)
Gains reclassified from accumulated other comprehensive income ("AOCI") into income are included in the oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations.
(2)
Presented net of income tax expense of $0.1 million and $0.8 million for the three months ended March 31, 2014 and 2013, respectively.

As of March 31, 2014, the Company had financial instruments in place to hedge the following volumes for the periods indicated:
 
April – December
2014
 
For the year
2015
 
For the  year
2016
Oil (Bbls)
2,769,400

 
2,524,000

 
91,000

Natural Gas (MMbtu)
18,485,000

 
7,300,000

 

Natural Gas Liquids (Bbls)
241,071

 

 

The table below summarizes the commodity derivative gains and losses the Company recognized related to its oil, gas and NGL derivative instruments for the periods indicated:
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Commodity derivative gain settlements on derivatives designated as cash flow hedges (1)
$
156

 
$
2,067

Total commodity derivative loss (2)
(25,155
)
 
(29,851
)
 
(1)
Included in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations.
(2)
Included in commodity derivative loss in the Unaudited Consolidated Statements of Operations.
The Company’s derivative financial instruments are generally executed with major financial or commodities trading institutions that expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had hedges in place with nine different counterparties as of March 31, 2014. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk, in the event of non-performance by the counterparties, are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.
It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. (“ISDA”) Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed the Company under derivative contracts. Where the counterparty is not a lender under the Company’s Amended Credit Facility, it may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.

18




9. Income Taxes
Income tax benefit for the three months ended March 31, 2014 and 2013 differs from the amounts that would be provided by applying the U.S. federal income tax rate to income before income taxes principally due to the effect of state income taxes, stock-based compensation and other operating expenses not deductible for income tax purposes. The effective tax rate of 44.6% for the three months ended March 31, 2014 is primarily due to an increase in unfavorable permanent adjustments to taxable income relative to projected pre-tax income.
10. Equity Incentive Compensation Plans and Other Employee Benefits
The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period).
The following table presents the non-cash stock-based compensation related to equity awards for the periods indicated:
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Common stock options
$
629

 
$
2,490

Nonvested equity common stock
1,671

 
2,400

Nonvested equity common stock units 
249

 
400

Nonvested performance-based equity
818

 
168

Total
$
3,367

 
$
5,458


Unrecognized compensation cost as of March 31, 2014 was $27.2 million related to grants of nonvested stock options and nonvested equity shares of common stock that are expected to be recognized over a weighted-average period of 2.9 years.
Nonvested Equity Shares. The following table presents the equity awards granted pursuant to the Company’s various stock compensation plans:

 
Three Months Ended March 31, 2014
 
Three Months Ended March 31, 2013
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
Nonvested equity common stock
466,314

 
$
22.47

 
540,380

 
$
17.26

Nonvested equity common stock units
732

 
$
25.60

 
8,395

 
$
20.27

Nonvested performance-based equity shares
248,575

 
$
19.61

 
274,979

 
$
16.57

Total shares granted
715,621

 
 
 
823,754

 
 

Performance Share Programs
2014 Program. In February 2014, the Compensation Committee approved a new performance share program (the “2014 Program”) pursuant to the 2012 Equity Incentive Plan. The performance-based awards contingently vest in May 2017, depending on the level at which the performance goals are achieved. The performance goals, which will be measured over the three year period ending December 31, 2016, consist of the Company’s total shareholder return (“TSR”) ranking relative to a defined peer group’s individual TSRs (“Relative TSR”) (weighted at 60%) and the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group’s percentage calculation (“DCF per Debt Adjusted Share”) (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals will vest at 25% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric are between the threshold and target levels or between the target and stretch levels, the vested number of shares will be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics are not met, no shares will vest. In any event, the total number of shares of common stock that could vest will not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that have not vested will be forfeited. A total of 248,575 shares were granted under this program during the three months ended March 31, 2014. All compensation expense related to the TSR metric will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. All compensation expense related to the discretionary cash flow metric will be based upon the number of shares

19


expected to vest at the end of the three year period. The Company recorded $0.1 million of non-cash stock-based compensation expense related to these awards for the three months ended March 31, 2014.
11. Commitments and Contingencies
Lease Financing Obligation. The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below:
 
As of March 31, 2014
 
(in thousands)
2014
$
4,485

2015
5,979

2016
5,979

2017
5,979

2018
5,979

Thereafter
18,781

Total
$
47,182


Transportation Demand and Firm Processing Charges. The Company has entered into contracts that provide firm transportation capacity on pipeline systems and firm processing charges. The remaining terms on these contracts range from two to seven years and require the Company to pay transportation demand and processing charges regardless of the amount of pipeline capacity utilized by the Company. All transportation costs, including demand charges and processing charges, are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations. The Company paid $7.7 million and $8.8 million of transportation demand charges for the three months ended March 31, 2014 and March 31, 2013, respectively. The Company did not pay firm processing charges for the three months ended March 31, 2014 and paid $0.7 million of firm processing charges for the three months ended March 31, 2013.
The amounts in the table below represent the Company’s gross future minimum transportation demand and firm processing charges. However, the Company will record in its financial statements only the Company’s proportionate share based on the Company’s working interest and net revenue interest, which will vary from property to property. From time to time, we may sell certain portions of firm capacity on various pipelines, as business or operations conditions warrant, to mitigate our exposure on unused transportation capacity.
 
As of March 31, 2014
 
(in thousands)
2014
$
27,320

2015
36,717

2016
35,466

2017
33,085

2018
33,521

Thereafter
63,813

Total
$
229,922


Lease and Other Commitments. The Company has one take-or-pay purchase agreement for supply of carbon dioxide (“CO2”), which has a total financial commitment of $1.7 million. The CO2 is for use in fracture stimulation operations. Under this contract, the Company is obligated to purchase a minimum monthly volume at a set price. If the Company takes delivery of less than the minimum required amount, the Company is responsible for full payment (deficiency payment) in December 2015.
The Company leases office space, vehicles and certain equipment under non-cancelable operating leases. Office lease expense was $0.4 million and $0.5 million for the three months ended March 31, 2014 and 2013, respectively. Additionally, the Company has entered into various long-term agreements for telecommunication services. Future minimum annual payments under lease and other agreements are as follows:

20


 
As of March 31, 2014
 
(in thousands)
2014
$
3,510

2015 (1)
9,943

2016
2,702

2017
2,535

2018
2,528

Thereafter
633

Total
$
21,851


(1)
Includes a drilling carry in the amount of $8.5 million from a purchase, sale and exploration agreement related to acreage in the Powder River Basin. As of March 31, 2014, the Company has satisfied $1.6 million of this carry. The Company will owe the remaining carry balance if not satisfied by October 1, 2015.
Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the course of ordinary 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.
12. Guarantor Subsidiaries
In addition to the Amended Credit Facility, the 7.625% Senior Notes, 7.0% Senior Notes and Convertible Notes, which are registered securities, are jointly and severally guaranteed on a full and unconditional basis by the Company’s 100% owned subsidiaries (“Guarantor Subsidiaries”). Presented below are the Company’s unaudited condensed consolidating balance sheets, statements of operations, statements of other comprehensive income (loss) and statements of cash flows, as required by Rule 3-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

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
 
As of March 31, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Current assets
$
158,005

 
$
362

 
$

 
$
158,367

Property and equipment, net
2,167,454

 
114,653

 

 
2,282,107

Intercompany receivable (payable)
152,350

 
(152,350
)
 

 

Investment in subsidiaries
(42,853
)
 

 
42,853

 

Noncurrent assets
19,501

 

 

 
19,501

Total assets
$
2,454,457

 
$
(37,335
)
 
$
42,853

 
$
2,459,975

Liabilities and Stockholders’ Equity:
 
 
 
 
 
 
 
Current liabilities
$
227,532

 
$
1,232

 
$

 
$
228,764

Long-term debt
1,042,889

 

 

 
1,042,889

Deferred income taxes
148,894

 
2,187

 

 
151,081

Other noncurrent liabilities
40,217

 
2,099

 

 
42,316

Stockholders’ equity
994,925

 
(42,853
)
 
42,853

 
994,925

Total liabilities and stockholders’ equity
$
2,454,457

 
$
(37,335
)
 
$
42,853

 
$
2,459,975

 

21


 
As of December 31, 2013
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Assets:
 
 
 
 
 
 
 
Current assets
$
154,794

 
$
2,453

 
$

 
$
157,247

Property and equipment, net
2,088,591

 
113,905

 

 
2,202,496

Intercompany receivable (payable)
155,909

 
(155,909
)
 

 

Investment in subsidiaries
(44,976
)
 

 
44,976

 

Noncurrent assets
21,770

 

 

 
21,770

Total assets
$
2,376,088

 
$
(39,551
)
 
$
44,976

 
$
2,381,513

Liabilities and Stockholders’ Equity:
 
 
 
 
 
 
 
Current liabilities
$
192,093

 
$
626

 
$

 
$
192,719

Long-term debt
979,082

 

 

 
979,082

Deferred income taxes
159,139

 
2,187

 

 
161,326

Other noncurrent liabilities
40,056

 
2,612

 

 
42,668

Stockholders’ equity
1,005,718

 
(44,976
)
 
44,976

 
1,005,718

Total liabilities and stockholders’ equity
$
2,376,088

 
$
(39,551
)
 
$
44,976

 
$
2,381,513


Condensed Consolidating Statements of Operations 
 
Three Months Ended March 31, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
121,283

 
$
6,405

 
$

 
$
127,688

Operating expenses
(88,782
)
 
(4,282
)
 

 
(93,064
)
General and administrative
(15,407
)
 

 

 
(15,407
)
Interest income and other income (expense)
(42,211
)
 

 

 
(42,211
)
Income (loss) before income taxes and equity in earnings of subsidiaries
(25,117
)
 
2,123

 

 
(22,994
)
Benefit from income taxes
10,245

 

 

 
10,245

Equity in earnings (loss) of subsidiaries
2,123

 

 
(2,123
)
 

Net income (loss)
$
(12,749
)
 
$
2,123

 
$
(2,123
)
 
$
(12,749
)

 
Three Months Ended March 31, 2013
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Operating and other revenues
$
130,140

 
$
8,137

 
$

 
$
138,277

Operating expenses
(112,072
)
 
(3,847
)
 

 
(115,919
)
General and administrative
(20,582
)
 

 

 
(20,582
)
Interest and other income (expense)
(54,354
)
 

 

 
(54,354
)
Income (loss) before income taxes and equity in earnings of subsidiaries
(56,868
)
 
4,290

 

 
(52,578
)
Benefit from income taxes
19,427

 

 

 
19,427

Equity in earnings (loss) of subsidiaries
4,290

 

 
(4,290
)
 

Net income (loss)
$
(33,151
)
 
$
4,290

 
$
(4,290
)
 
$
(33,151
)
Condensed Consolidating Statements of Comprehensive Income (Loss)
 

22


 
Three Months Ended March 31, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(12,749
)
 
$
2,123

 
$
(2,123
)
 
$
(12,749
)
Other Comprehensive Loss, net of tax:
 
 
 
 
 
 
 
Effect of derivative financial instruments
(97
)
 

 

 
(97
)
Other comprehensive loss
(97
)
 

 

 
(97
)
Comprehensive income (loss)
$
(12,846
)
 
$
2,123

 
$
(2,123
)
 
$
(12,846
)
 
Three Months Ended March 31, 2013
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Net income (loss)
$
(33,151
)
 
$
4,290

 
$
(4,290
)
 
$
(33,151
)
Other Comprehensive Loss, net of tax:
 
 
 
 
 
 
 
Effect of derivative financial instruments
(1,292
)
 

 

 
(1,292
)
Other comprehensive loss
(1,292
)
 

 

 
(1,292
)
Comprehensive income (loss)
$
(34,443
)
 
$
4,290

 
$
(4,290
)
 
$
(34,443
)

Condensed Consolidating Statements of Cash Flows
 
 
Three Months Ended March 31, 2014
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Cash flows from operating activities
$
68,304

 
$
6,890

 
$

 
$
75,194

Cash flows from investing activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
(125,284
)
 
(3,654
)
 

 
(128,938
)
Additions to furniture, fixtures and other
(274
)
 

 

 
(274
)
Proceeds from sale of properties and other investing activities
(388
)
 

 

 
(388
)
Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from debt
65,000

 

 

 
65,000

Principal and redemption premium payments on debt
(1,137
)
 

 

 
(1,137
)
Intercompany transfers
3,236

 
(3,236
)
 

 

Other financing activities
(1,820
)
 

 

 
(1,820
)
Change in cash and cash equivalents
7,637

 

 

 
7,637

Beginning cash and cash equivalents
54,545

 
50

 

 
54,595

Ending cash and cash equivalents
$
62,182

 
$
50

 
$

 
$
62,232

 

23


 
Three Months Ended March 31, 2013
 
Parent
Issuer
 
Guarantor
Subsidiaries
 
Intercompany
Eliminations
 
Consolidated
 
(in thousands)
Cash flows from operating activities
$
61,740

 
$
5,186

 
$

 
$
66,926

Cash flows from investing activities:
 
 
 
 
 
 
 
Additions to oil and gas properties, including acquisitions
(104,268
)
 
(11,056
)
 

 
(115,324
)
Additions to furniture, fixtures and other
(445
)
 

 

 
(445
)
Proceeds from sale of properties and other investing activities
6,424

 

 

 
6,424

Cash flows from financing activities:
 
 
 
 
 
 
 
Proceeds from debt
25,000

 

 

 
25,000

Principal and redemption premium payments on debt
(2,241
)
 

 

 
(2,241
)
Intercompany transfers
(5,870
)
 
5,870

 

 

Other financing activities
(1,263
)
 

 

 
(1,263
)
Change in cash and cash equivalents
(20,923
)
 

 

 
(20,923
)
Beginning cash and cash equivalents
79,395

 
50

 

 
79,445

Ending cash and cash equivalents
$
58,472

 
$
50

 
$

 
$
58,522



24


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

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

volatility of market prices received for oil, natural gas and natural gas liquids (“NGLs”);
costs and availability of third party facilities for gathering, processing, refining and transportation;
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;
economic and competitive conditions;
reductions in the borrowing base under our amended revolving bank credit facility (the “Amended Credit Facility”);
declines in the values of our oil and natural gas properties resulting in impairments;
changes in estimates of proved reserves;
compliance with environmental and other regulations;
derivative and hedging activities;
potential failure to achieve expected production from existing and future exploration or development projects or acquisitions;
occurrence of property divestitures or acquisitions;
legislative or regulatory changes including initiatives related to drilling and completion techniques such as hydraulic fracturing;
future processing volumes and pipeline throughput;
the potential for production decline rates from our wells to be greater than we expect;
ability to replace natural production declines with acquisitions, new drilling or recompletion activities;
exploration risks such as drilling unsuccessful wells;
capital expenditures and other contractual obligations;
debt and equity market conditions;
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 rates; and
other uncertainties, as well as those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2013 under the “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” sections and in Item 1A, “Risk Factors” of this Quarterly Report on Form 10-Q, all of which are difficult to predict.
In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to publicly correct or 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
Bill Barrett Corporation together with our wholly-owned subsidiaries (“the Company”, “we”, “our” or “us”) develops oil, natural gas and NGLs in the Rocky Mountain region of the United States. We seek to build stockholder value through profitable growth in cash flow, reserves and production through the development of our oil, natural gas and NGL assets. We seek high quality development projects with the potential to provide long-term drilling inventories that generate high returns. Due to the decline in natural gas prices resulting from the increased supply over the past few years, we have shifted our focus to finding, acquiring and developing oil resources. Therefore, we will have less gas production due to suspended gas drilling, along with the sale of certain gas producing properties. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGLs 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. Since inception, we have built our portfolio of properties primarily through acquisitions where we seek to add value through our geologic and operational expertise. Our acquisitions have included key assets in the Piceance

25


(Colorado), Uinta (Utah), Denver-Julesburg (Colorado and Wyoming) and Powder River (Wyoming) Basins in the Rocky Mountain region (the “Rockies”). We also may sell properties when the opportunity arises or when business conditions warrant, as demonstrated by the sale of our Wind River Basin and Powder River Basin properties and a portion of our Piceance Basin properties in December 2012 and the sale of our West Tavaputs properties in the Uinta Basin (the "West Tavaputs Divestiture") in December 2013.

We are committed to developing and producing oil, natural gas and NGLs in a responsible and safe manner. We work diligently with environmental, wildlife and community organizations to ensure that our exploration and development activities are designed with all stakeholders in mind.
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.
Three Months Ended March 31, 2014 Compared with Three Months Ended March 31, 2013
 
 
Three Months Ended March 31,
 
Increase (Decrease)
2014
 
2013
 
Amount
 
Percent
($ in thousands, except per unit data)
Operating Results:
 
 
 
 
 
 
 
Operating and Other Revenues
 
 
 
 
 
 
 
Oil, gas and NGL production
$
127,169

 
$
134,405

 
$
(7,236
)
 
(5
)%
Other
519

 
3,872

 
(3,353
)
 
(87
)%
Operating Expenses
 
 
 
 
 
 
 
Lease operating expense
16,164

 
18,746

 
(2,582
)
 
(14
)%
Gathering, transportation and processing expense
11,704

 
15,588

 
(3,884
)
 
(25
)%
Production tax expense
7,624

 
5,951

 
1,673

 
28
 %
Exploration expense
303

 
95

 
208

 
219
 %
Impairment, dry hole costs and abandonment expense
1,761

 
7,101

 
(5,340
)
 
(75
)%
Depreciation, depletion and amortization
55,508

 
68,438

 
(12,930
)
 
(19
)%
General and administrative expense (1)
11,819

 
15,148

 
(3,329
)
 
(22
)%
Non-cash stock-based compensation expense (1)
3,588

 
5,434

 
(1,846
)
 
(34
)%
Total operating expenses
$
108,471

 
$
136,501

 
$
(28,030
)
 
(21
)%
Production Data:
 
 
 
 
 
 
 
Oil (MBbls)
922

 
794

 
128

 
16
 %
Natural gas (MMcf) 
6,420

 
14,664

 
(8,244
)
 
(56
)%
NGLs (MBbls)
442

 
582

 
(140
)
 
(24
)%
Combined volumes (MBoe)
2,434

 
3,820

 
(1,386
)
 
(36
)%
Daily combined volumes (Boe/d)
27,044

 
42,444

 
(15,400
)
 
(36
)%
Average Realized Prices (2):
 
 
 
 
 
 
 
Oil (per Bbl)
$
78.78

 
$
81.74

 
$
(2.96
)
 
(4
)%
Natural gas (per Mcf)
4.79

 
4.10

 
0.69

 
17
 %
NGLs (per Bbl)
33.00

 
25.01

 
7.99

 
32
 %
Combined (per Boe)
48.47

 
36.55

 
11.92

 
33
 %
Average Costs (per Boe):
 
 
 
 
 
 
 
Lease operating expense
$
6.64

 
$
4.91

 
$
1.73

 
35
 %
Gathering, transportation and processing expense
4.81

 
4.08

 
0.73

 
18
 %
Production tax expense
3.13

 
1.56

 
1.57

 
101
 %
Depreciation, depletion and amortization
22.81

 
17.92

 
4.89

 
27
 %
General and administrative expense (3)
4.86

 
3.97

 
0.89

 
22
 %
 

26


(1)
Non-cash stock-based compensation expense is presented herein as a separate line item but is combined with general and administrative expense for a total of $15.4 million and $20.6 million for the three months ended March 31, 2014 and 2013, respectively, in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of our required cash for general and administrative expenses. We also believe that this disclosure allows for a more accurate comparison to our peers, which may have higher or lower expenses associated with stock-based grants.
(2)
Average realized prices shown in the table are net of the effects of all settled commodity hedging transactions related to current period production. This presentation is a non-GAAP measure as it only represents the cash settled portion of our total commodity derivative loss in the Unaudited Consolidated Statements of Operations. Management believes the presentation of average prices including the effects of settled commodity derivative gains and losses is useful because the cash settlement portion provides a better understanding of the Company's average prices received for production volumes. We also believe that this disclosure allows for a more accurate comparison to our peers.
(3)
Excludes non-cash stock-based compensation expense as described in Note 1 above. This presentation is a non-GAAP measure. Average costs per Boe for general and administrative expense, including non-cash stock-based compensation expense, as presented in the Unaudited Consolidated Statements of Operations, were $6.33 and $5.39 for the three months ended March 31, 2014 and 2013, respectively.

Production Revenues and Volumes. Production revenues decreased to $127.2 million for the three months ended March 31, 2014 from $134.4 million for the three months ended March 31, 2013. The decrease in production revenues was primarily due to a 36% decrease in production volumes, offset by an increase in average prices. The decrease in production volumes reduced production revenues by approximately $72.4 million, while the increase in average prices increased production revenues by approximately $65.2 million.
We discontinued hedge accounting as of January 1, 2012. All accumulated gains or losses related to the discontinued cash flow hedges were recorded in AOCI as of January 1, 2012 and will remain in AOCI until the underlying transaction occurs. As the underlying transaction occurs, these gains or losses are reclassified from AOCI into oil, gas and NGL production revenues. The amount reclassified to oil, gas and NGL production revenues was a gain of $0.2 million and $2.0 million for the three months ended March 31, 2014 and 2013, respectively.
Total production volumes of 2.4 MMBoe for the three months ended March 31, 2014 decreased from 3.8 MMBoe for the three months ended March 31, 2013. The decrease relates to the West Tavaputs Divestiture, severe winter weather, downtime and lower NGL yields at our primary NGL processor in the Piceance Basin and unexpected drilling delays associated with remediation of offset wellbores in the DJ Basin that is required by the Colorado Oil and Gas Conservation Commission regulations. These decreases were partially offset by a 16% overall increase in oil production with increases in the DJ Basin and Powder Deep Oil Program for the three months ended March 31, 2014. Additional information concerning production is in the following table:
 
Three Months Ended March 31, 2014
 
Three Months Ended March 31, 2013
 
% 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)
Piceance Basin
61

318

5,022

1,216

 
93

527

7,032

1,792

 
(34)%
(40
)%
(29)%
(32)%
Uinta Oil Program
402

30

522

519

 
477

27

726

625

 
(16)%
11
 %
(28)%
(17)%
DJ Basin
357

92

780

579

 
156

28

360

244

 
129%
229
 %
117%
137%
Powder Deep Oil Program
99

2

114

120

 
49


48

57

 
102%
*nm

138%
111%
Other (1)
3


(18
)

 
19


6,498

1,102

 
(84)%
*nm

(100)%
(100)%
Total
922

442

6,420

2,434

 
794

582

14,664

3,820

 
16%
(24
)%
(56)%
(36)%

*
Not meaningful.
(1)
Other includes Uinta - West Tavaputs natural gas volumes of 6,455 MMcf and oil production of 15 MBbls for 2013.

Hedging Activities. During the three months ended March 31, 2014, approximately 88% of our oil volumes, 91% of our natural gas volumes and 18% of our NGL related volumes were subject to financial hedges, which resulted in decreases in oil revenues of $3.5 million, natural gas revenues of $5.0 million and NGL revenues of $0.5 million after settlements for all

27


commodity derivatives. Of the $9.0 million loss on settlements for the three months ended March 31, 2014, a $0.2 million gain was included in oil, gas and NGL production revenues and a $9.2 million loss was included in commodity derivative loss in the Unaudited Consolidated Statements of Operations. During the three months ended March 31, 2013, approximately 81% of our oil volumes, 92% of our natural gas volumes, and 14% of our NGL related volumes were subject to financial hedges, which resulted in increases in oil revenues of $2.4 million, natural gas revenues of $5.7 million and NGL revenues of $0.4 million after settlements for all commodity derivatives. Of the $8.5 million gain on settlements for the three months ended March 31, 2013, $2.0 million was included in oil, gas and NGL production revenues and $6.5 million was included in commodity derivative loss in the Unaudited Consolidated Statements of Operations. We may not always be able to generate increases in revenues based on hedge settlements due to the volatility of prices for oil, natural gas and NGLs and current market conditions.

Other Operating Revenues. Other operating revenues decreased to $0.5 million for the three months ended March 31, 2014 from $3.9 million for the three months ended March 31, 2013. Other operating revenues for the three months ended March 31, 2014 primarily consisted of $0.5 million of income from gathering and compression fees received from third parties. Other operating revenues for the three months ended March 31, 2013 consisted of $3.5 million in net gains realized from the sale of properties and $0.4 million of income from gathering and compression fees received from third parties.

Lease Operating Expense ("LOE"). LOE increased to $6.64 per Boe for the three months ended March 31, 2014 from $4.91 per Boe for the three months ended March 31, 2013. LOE on a per Boe basis is inherently higher for our oil producing properties such as those in our Uinta and DJ Basin development areas. In addition, the sale of natural gas properties with lower LOE per Boe in the West Tavaputs Divestiture also contributed to a higher LOE per Boe unit cost for the three months ended March 31, 2014.

Gathering, Transportation and Processing Expense ("GTP"). GTP expense increased to $4.81 per Boe for the three months ended March 31, 2014 from $4.08 per Boe for the three months ended March 31, 2013. GTP expense for the three months ended March 31, 2014 increased on a per Boe basis primarily due to retaining certain transportation contracts that were related to West Tavaputs natural gas production but were not part of the West Tavaputs Divestiture. Transportation costs were incurred for these contracts during the three months ended March 31, 2014 with no associated production volumes. We continue to be subject to long-term firm transportation contracts for a portion of our natural gas production from the Piceance Basin. From time to time, we may sell certain portions of firm capacity on various pipelines, as business or operations conditions warrant, to mitigate our exposure on unused transportation capacity.

Production Tax Expense. Total production taxes increased to $7.6 million for the three months ended March 31, 2014 from $6.0 million for the three months ended March 31, 2013. 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 6.0% and 4.5% for the three months ended March 31, 2014 and 2013, 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. The increase in the overall production tax rate is consistent with our production increase in areas with higher production tax rates.

Exploration Expense. Exploration expense increased to $0.3 million for the three months ended March 31, 2014 from $0.1 million for the three months ended March 31, 2013. Exploration expense for the three months ended March 31, 2014 consisted of $0.2 million for geological and geophysical seismic programs and $0.1 million for delay rentals across all basins. Exploration expense for the three months ended March 31, 2013 consisted of $0.1 million of geological and geophysical seismic programs and delay rentals across all basins.

Impairment, Dry Hole Costs and Abandonment Expense. Our impairment, dry hole costs and abandonment expense decreased to $1.8 million for the three months ended March 31, 2014 from $7.1 million for the three months ended March 31, 2013. For the three months ended March 31, 2014, impairment expense was $1.0 million, abandonment expense was $0.7 million and dry hole costs were $0.1 million. The $1.0 million of impairment expense for the three months March 31, 2014 related to West Tavaputs Divestiture based upon a true up of previously estimated fair value relative to carrying value. These properties were sold in December 2013. For the three months ended March 31, 2013, abandonment expense was $6.2 million and dry hole costs were $0.9 million.

Depreciation, Depletion and Amortization ("DD&A"). DD&A decreased to $55.5 million for the three months ended March 31, 2014 compared with $68.4 million for the three months ended March 31, 2013. The decrease of $12.9 million was a result of the 36% decrease in production for the three months ended March 31, 2014 compared with the three months ended

28


March 31, 2013, offset by an increase in the DD&A rate. The decrease in production accounted for a $24.8 million decrease in DD&A expense, while the overall increase in the DD&A rate accounted for $11.9 million of additional DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended March 31, 2014, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $22.81 per Boe compared with $17.92 per Boe for the three months ended March 31, 2013. The increase in the DD&A rate during the three months ended March 31, 2014 compared with the three months ended March 31, 2013 was due to an increase in oil projects, which have higher capital costs per Boe compared to our natural gas projects. Future depletion rates will be adjusted to reflect capital expenditures, proved reserve changes and well performance.

General and Administrative Expense. General and administrative expense, excluding non-cash stock-based compensation, decreased to $11.8 million for the three months ended March 31, 2014 from $15.1 million for the three months ended March 31, 2013. The decrease of $3.3 million was primarily the result of a 14% decrease in the number of employees as of March 31, 2014 compared to March 31, 2013. General and administrative expense, excluding non-cash stock-based compensation, is a non-GAAP measure. See Note 1 to the table on page 26 for a reconciliation and explanation. On a per Boe basis, general and administrative expense, excluding non-cash stock-based compensation, increased to $4.86 per Boe for the three months ended March 31, 2014 from $3.97 per Boe for the three months ended March 31, 2013, largely due to the 36% decrease in production as the result of the West Tavaputs Divestiture.

Non-cash charges for stock-based compensation for the three months ended March 31, 2014 and the three months ended March 31, 2013 were $3.6 million and $5.4 million, respectively. Non-cash stock-based compensation expense for each of the three months ended March 31, 2014 and 2013 related primarily to vesting of our stock option awards and nonvested shares of common stock issued to employees.

The components of non-cash stock-based compensation for the three months ended March 31, 2014 and 2013 are shown in the following table:
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Stock options and nonvested equity shares of common stock
$
3,300

 
$
4,937

Shares issued for 401(k) plan
269

 
327

Shares issued for directors’ fees
19

 
170

Total
$
3,588

 
$
5,434


Interest Expense. Interest expense decreased to $17.4 million for the three months ended March 31, 2014 from $24.5 million for the three months ended March 31, 2013. The decrease for the three months ended March 31, 2014 was primarily due to a lower weighted average interest rate as a result of the redemption of the 9.875% Senior Notes on July 15, 2013, and lower weighted average outstanding borrowings. Our weighted average interest rate for the three months ended March 31, 2014 was 6.9% compared to 8.4% for the three months ended March 31, 2013, and our weighted average outstanding borrowings for the three months ended March 31, 2014 were $1.0 billion compared with $1.2 billion for the three months ended March 31, 2013.

Commodity Derivative Gain (Loss). Commodity derivative loss changed to a loss of $25.2 million for the three months ended March 31, 2014 compared with a loss of $29.9 million for the three months ended March 31, 2013. Gains and losses on commodity derivatives will fluctuate from period to period based on changes in commodity futures pricing.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Realized gain (loss) on derivatives not designated as cash flow hedges (1)
$
(9,200
)
 
$
6,453

Unrealized loss on derivatives not designated as cash flow hedges (1)
(15,955
)
 
(36,304
)
Total commodity derivative loss
$
(25,155
)
 
$
(29,851
)

29



(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 loss in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.
Income Tax Benefit. Income tax benefit totaled $10.2 million for the three months ended March 31, 2014 compared to an income tax benefit of $19.4 million for the three months ended March 31, 2013, resulting in effective tax rates of 44.6% and 36.9%, respectively. For both the 2014 and 2013 periods, our effective tax rate differs from the federal statutory rate primarily as a result of recording stock-based compensation expense and other operating expenses that are not deductible for income tax purposes as well as the effect of state income taxes. The increase in the effective tax rate is mainly a result of the relationship of these items to book income.
Capital Resources and Liquidity
Our primary sources of liquidity since our formation in January 2002 have been net cash provided by operating activities, sales and other issuances of equity and debt securities, notes and senior notes, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to us and our success in finding or acquiring additional reserves. We believe that we have significant liquidity available to us from cash flows from operations and under our Amended Credit Facility for our planned uses of capital.
At March 31, 2014, we had cash and cash equivalents of $62.2 million and a $180.0 million balance outstanding under our Amended Credit Facility. Our borrowing base is dependent on our proved reserves and hedge position and was, as of March 31, 2014, $625.0 million. Our borrowing capacity was further reduced by $26.0 million to $419.0 million as of March 31, 2014 due to an outstanding irrevocable letter of credit related to a firm transportation agreement.
Cash Flow from Operating Activities
Net cash provided by operating activities for the three months ended March 31, 2014 and 2013 was $75.2 million and $66.9 million, respectively. The increase in net cash provided by operating activities was due to an increase in the changes in operating assets and liabilities, a decrease in cash operating expenses, offset by a decrease in production revenues.

Commodity Hedging Activities
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.
To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production revenues. At March 31, 2014, we had in place crude oil swaps covering portions of our 2014, 2015 and 2016 production, natural gas swaps covering portions of our 2014 and 2015 production and NGL swaps covering portions of our 2014 production.
In addition to financial contracts, we may at times enter into various physical commodity contracts for the sale of oil and natural gas that cover varying periods of time and have varying pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sales exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, gas and NGL production revenues at the time of settlement.
All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative’s fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.

30


At March 31, 2014, the estimated fair value of all of our commodity derivative instruments was a net liability of $19.4 million, comprised of noncurrent assets and current and noncurrent liabilities. We will reclassify the appropriate cash flow hedge amounts from AOCI, related to hedges designated as cash flow hedges prior to January 1, 2012, to gains and losses included in oil, gas and NGL production revenues as the hedged production quantities are produced.
The table below summarizes the realized and unrealized gains and losses that we recognized related to our oil, natural gas and NGL derivative instruments for the periods indicated:
 
Three Months Ended March 31,
 
2014
 
2013
 
(in thousands)
Commodity derivative settlements on derivatives designated as cash flow hedges (1)
$
156

 
$
2,067

Realized gains (losses) on derivatives not designated as cash flow hedges (2)(3)
$
(9,200
)
 
$
6,453

Unrealized losses on derivatives not designated as cash flow hedges (2)(3)
(15,955
)
 
(36,304
)
Total commodity derivative loss
$
(25,155
)
 
$
(29,851
)
 
(1)
Included in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations.
(2)
Included in commodity derivative loss in the Unaudited Consolidated Statements of Operations.
(3)
Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative loss in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more accurate comparison to our peers.
The following table summarizes all of our hedges in place as of March 31, 2014:
 
Contract
Total
Hedged
Volumes
 
Quantity
Type
 
Weighted
Average
Fixed
Price
 
Index
Price (1)
 
Fair Market
Value
(in thousands)
Swap Contracts:
 
 
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
 
 
 
Oil
2,769,400

 
Bbls
 
$
94.03

 
WTI
 
$
(9,845
)
Natural gas
18,485,000

 
MMBtu
 
$
3.97

 
NWPL
 
(7,873
)
Natural gas liquids (2)
241,071

 
Bbls
 
$
54.93

 
Mt. Belvieu
 
335

2015
 
 
 
 
 
 
 
 
 
Oil
2,524,000

 
Bbls
 
$
89.15

 
WTI
 
(2,580
)
Natural gas
7,300,000

 
MMBtu
 
$
4.13

 
NWPL
 
369

2016
 
 
 
 
 
 
 
 
 
Oil
91,000

 
Bbls
 
$
87.69

 
WTI
 
196

Total
 
 
 
 
 
 
 
 
$
(19,398
)


31


The following table includes all hedges entered into subsequent to March 31, 2014 through April 18, 2014:
Contract
Total
Hedged
Volumes
 
Quantity
Type
 
Weighted
Average
Fixed
Price
 
Index
Price (1)
Swap Contracts:
 
 
 
 
 
 
 
2014
 
 
 
 
 
 
 
Natural gas liquids (2)
38,096

 
Bbls
 
$
89.73

 
Mt. Belvieu
2015
 
 
 
 
 
 
 
Oil
1,004,500

 
Bbls
 
$
90.36

 
WTI
2016
 
 
 
 
 
 
 
Oil
366,000

 
Bbls
 
$
86.95

 
WTI
 
(1)
NWPL refers to Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC on the first business day of each month. Mt. Belvieu refers to the average daily price as quoted by Oil Price Information Service (“OPIS”) for Mont Belvieu spot gas liquid prices. WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange (“NYMEX”).
(2)
Weighted average fixed price includes propane, normal butane, isobutane and natural gasoline hedges.
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. (“ISDA”) Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed us under 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:
 
Three Months Ended March 31,
Basin/Area
2014
 
2013
 
(in millions)
Piceance
$
0.1

 
$
2.4

Uinta Oil Program
29.7

 
64.6

DJ
95.0

 
19.5

Powder Deep Oil Program
9.1

 
29.7

Other
0.6

 
2.1

Total
$
134.5

 
$
118.3


32


 
Three Months Ended March 31,
 
2014
 
2013
 
(in millions)
Acquisitions of proved and unproved properties and other real estate
$
3.7

 
$
4.2

Drilling, development, exploration and exploitation of oil and natural gas properties (1)
130.1

 
113.6

Geologic and geophysical costs
0.3

 
0.1

Furniture, fixtures and equipment
0.4

 
0.4

Total
$
134.5

 
$
118.3

 
(1)
Includes related gathering and facilities costs.
Our current estimated capital expenditure budget in 2014 is $500.0 million to $550.0 million, with all drilling activities targeting oil. The budget includes facilities costs and excludes material acquisitions. We may adjust capital expenditures throughout the year as business conditions and operating results warrant. We believe that we have sufficient available liquidity through 2015 with available cash under the Amended Credit Facility and cash flow from operations to fund our budgeted capital expenditures. Future cash flows are subject to a number of variables, including our level of oil, natural gas and NGL 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.
The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline to levels below our acceptable levels or costs increase to levels above our 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 generally 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 routinely monitor and adjust our capital expenditures, including acquisitions and divestitures, in response to changes in prices and other economic and market conditions, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside of our control.
Financing Activities
Amended Credit Facility
Our Amended Credit Facility has a maturity date of October 31, 2016, and current commitments and borrowing base of $625.0 million. As of March 31, 2014, we had $180.0 million outstanding under the Amended Credit Facility. As credit support for future payment under a contractual obligation, a $26.0 million letter of credit was issued under the Amended Credit Facility, which reduced the borrowing capacity of the Amended Credit Facility as of March 31, 2014 to $419.0 million.
Interest rates are LIBOR plus applicable margins of 1.5% to 2.5% or ABR plus 0.5% to 1.5% and the commitment fee is between 0.375% to 0.5% based on borrowing base utilization. The average annual interest rates incurred on the Amended Credit Facility was 1.6% and 1.7% for the three months ended March 31, 2014 and 2013, respectively.
The borrowing base is required to be re-determined twice per year. On May 1, 2014 the borrowing base was reaffirmed at $625.0 million based on year-end 2013 reserves and our hedge position. Future semi-annual borrowing bases under our credit facility will be computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves, as well as any other outstanding debt of the Company.
The Amended Credit Facility is secured by oil and natural gas properties representing at least 80% of the value of our proved reserves and the pledge of all of the stock of our subsidiaries. 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.

5% Convertible Senior Notes Due 2028

On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012, $147.2 million of the outstanding principal amount, or approximately 85% of the outstanding Convertible Notes, were put to us and were redeemed by us at par. We settled the notes in cash. After the redemption, $25.3 million aggregate principal amount of the Convertible Notes was outstanding. The Convertible Notes mature on March 15, 2028, unless earlier converted, redeemed

33


or purchased by us. The Convertible Notes are senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, are senior in right of payment to all of our future subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness with respect to the collateral securing such indebtedness. The Convertible Notes are structurally subordinated to all present and future secured and unsecured debt and other obligations of our subsidiaries. The Convertible Notes are fully and unconditionally guaranteed by the subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the 7.625% Senior Notes and the 7.0% Senior Notes.

The Convertible Notes bear interest at a rate of 5% per annum, payable semi-annually in arrears on March 15 and September 15 of each year. Holders of the remaining Convertible Notes may require us to purchase all or a portion of their Convertible Notes for cash on each of March 20, 2015, March 20, 2018 and March 20, 2023 at a purchase price equal to 100% of the principal amount of the Convertible Notes to be repurchased, plus accrued and unpaid interest, if any, up to but excluding the applicable purchase date. We have the right with at least 30 days’ notice to call the Convertible Notes.

7.625% Senior Notes Due 2019

On September 27, 2011, we issued $400.0 million in principal amount of 7.625% Senior Notes due 2019 at par. The 7.625% Senior Notes mature on October 1, 2019. Interest is payable in arrears semi-annually on April 1 and October 1 beginning April 1, 2012. The 7.625% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of our other existing and future senior unsecured indebtedness, including the Convertible Notes and 7.0% Senior Notes. The 7.625% Senior Notes are redeemable on October 1, 2015 at our option at a redemption price of 103.813% of the principal amount of the notes. The 7.625% Senior Notes are fully and unconditionally guaranteed by our subsidiaries that guarantee our indebtedness under the Amended Credit Facility, the Convertible Notes and the 7.0% Senior Notes. The 7.625% Senior Notes include certain covenants that limit our ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that prohibit us from paying dividends. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance.

7.0% Senior Notes Due 2022

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

Lease Financing Obligation Due 2020

In July, 2012, we entered into a lease financing arrangement with Bank of America Leasing & Capital, LLC as the lead bank (the “Lease Financing Obligation”) whereby we received $100.8 million through the sale and subsequent leaseback of existing 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 where we may purchase the equipment for $36.6 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%. As part of the West Tavaputs Divestiture, the purchaser assumed approximately 51% of the lease financing obligation, including the early buyout option related to West Tavaputs.

Our outstanding debt is summarized below:

34


 
 
As of March 31, 2014
 
As of December 31, 2013
 
Maturity Date
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
Principal
 
Unamortized
Discount
 
Carrying
Amount
 
 
(in thousands)
Amended Credit Facility (1)
October 31, 2016
$
180,000

 
$

 
$
180,000

 
$
115,000

 
$

 
$
115,000

Convertible Notes (2)
March 15, 2028 (3)
25,344

 

 
25,344

 
25,344

 

 
25,344

7.625% Senior Notes (4)
October 1, 2019
400,000

 

 
400,000

 
400,000

 

 
400,000

7.0% Senior Notes (5)
October 15, 2022
400,000

 

 
400,000

 
400,000

 

 
400,000

Lease Financing Obligation (6)
August 10, 2020
42,192

 

 
42,192

 
43,329

 

 
43,329

Total Debt
 
$
1,047,536

 
$

 
$
1,047,536

 
$
983,673

 
$

 
$
983,673

Less: Current Portion of Long-Term Debt
 
4,647

 

 
4,647

 
4,591

 

 
4,591

     Total Long-Term Debt
 
$
1,042,889

 
$

 
$
1,042,889

 
$
979,082

 
$

 
$
979,082

 
(1)
The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure.
(2)
The aggregate estimated fair value of the Convertible Notes was approximately $25.5 million and $25.1 million as of March 31, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.
(3)
We have the right at any time with at least 30 days’ notice to call the Convertible Notes, and the holders have the right to require us to purchase the notes on each of March 20, 2015, March 20, 2018 and March 20, 2023.
(4)
The aggregate estimated fair value of the 7.625% Senior Notes was approximately $433.0 million and $430.2 million as of March 31, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.
(5)
The aggregate estimated fair value of the 7.0% Senior Notes was approximately $422.0 million and $417.0 million as of March 31, 2014 and December 31, 2013, respectively, based on reported market trades of these instruments.
(6)
The aggregate estimated fair value of the Lease Financing Obligation was approximately $40.3 million and $41.7 million as of March 31, 2014 and December 31, 2013, 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.
Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s Investor Services and Standard & Poor’s Rating Services currently rate our 7.625% Senior Notes and 7.0% Senior Notes and have assigned a credit rating. We do not have any provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, Convertible Notes, 7.625% Senior Notes or the 7.0% Senior Notes. However, our ability to raise funds and the costs of any financing activities will be affected by our credit rating at the time any such financing activities are conducted.

Contractual Obligations. A summary of our contractual obligations as of and subsequent to March 31, 2014 is provided in the following table:
 
Payments Due By Year
Year 1
 
Year 2
 
Year 3
 
Year 4
 
Year 5
 
Thereafter
 
Total
 
(in thousands)
Notes payable (1)
$
553

 
$
553

 
$
180,553

 
$
553

 
$
44

 
$

 
$
182,256

7.625% Senior Notes (2)
30,500

 
30,500

 
30,500

 
30,500

 
30,500

 
415,250

 
567,750

7.0% Senior Notes (3) 
28,000

 
28,000

 
28,000

 
28,000

 
28,000

 
499,167

 
639,167

Convertible Notes (4)
26,889

 

 

 

 

 

 
26,889

Lease Financing Obligation (5)
5,979

 
5,979

 
5,979

 
5,979

 
23,266

 

 
47,182

Purchase commitments (6)(7)

 
1,695

 

 

 

 

 
1,695

Drilling rig commitments (7)(8)
3,846

 

 

 

 

 

 
3,846

Office and office equipment leases and other (9)(10) 
4,360

 
9,799

 
2,624

 
2,536

 
2,532

 

 
21,851

Firm transportation and processing agreements (7)(11)
36,523

 
36,454

 
34,955

 
33,159

 
33,204

 
55,627

 
229,922

Asset retirement obligations (12)
5,296

 
328

 
522

 
300

 
333

 
37,528

 
44,307

Derivative liability (13)(14)
20,388

 
283

 

 

 

 

 
20,671

Total
$
162,334

 
$
113,591

 
$
283,133

 
$
101,027

 
$
117,879

 
$
1,007,572

 
$
1,785,536

 

35


(1)
Included in notes payable is the outstanding principal amount under our Amended Credit Facility due October 31, 2016. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Also included in notes payable is a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is April 30, 2018.
(2)
On September 27, 2011, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes. We are obligated to make annual interest payments through maturity in 2019 equal to $30.5 million.
(3)
On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make annual interest payments through maturity in 2022 equal to $28.0 million.
(4)
On March 12, 2008, we issued $172.5 million aggregate principal amount of Convertible Notes. On March 20, 2012 approximately 85% of the outstanding Convertible Notes, representing $147.2 million of the then outstanding principal amount, were put to us. We settled the notes in cash and recognized a gain on extinguishment of $1.6 million after completing a fair value analysis of the consideration transferred to holders of the Convertible Notes. After the redemption in March 2012, $25.3 million principal amount of the Convertible Notes is currently outstanding. We are obligated to make semi-annual interest payments on the Convertible Notes until either we call the remaining Convertible Notes or the holders put the Convertible Notes to us, which is expected to occur by 2015.
(5)
The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component.
(6)
We have one take-or-pay carbon dioxide purchasing agreement that expires in December 2015. The agreement imposes a minimum volume commitment to purchase CO2 at a contracted price. The contract provides CO2 used in fracture stimulation operations. If we do not take delivery of the minimum volume required, we are obligated to pay for the deficiency. As of March 31, 2014, $1.7 million of the future commitment is due by December 31, 2015.
(7)
The values in the table represent the gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest and net revenue interest, which will vary from property to property.
(8)
We currently have two drilling rigs under contract. Both contracts expire in 2014. The contracts may be terminated prior to the expiration date but we would be required to pay a penalty computed at $3.8 million as of March 31, 2014. All other rigs currently performing work for us are on a well-by-well basis and, therefore, can be released without penalty given a 60 day notice. The latter types of drilling obligations have not been included in the table above.
(9)
The lease for our principal office in Denver extends through March 2019.
(10)
We have entered into a purchase, sale and exploration agreement which includes a drilling carry in the amount of $8.5 million related to acreage in the Powder River Basin. As of March 31, 2014, we have satisfied $1.6 million of this agreement. If we do not satisfy the carry amount by October 1, 2015, the remaining balance must be remitted.
(11)
We have entered into contracts that provide firm processing rights and firm transportation capacity on pipeline systems. The remaining terms on these contracts range from two to seven years and require us to pay transportation demand and processing charges regardless of the amount of gas we deliver to the processing facility or pipeline. From time to time, we may sell certain portions of firm capacity on various pipelines, as business or operations conditions warrant, to mitigate our exposure on unused transportation capacity.
(12)
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, 2013 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(13)
Derivative liability represents the net fair value for oil, gas and NGL commodity derivatives presented as liabilities in our Unaudited Consolidated Balance Sheets as of March 31, 2014. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. 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, 2013 and in “Commodity Hedging Activities” above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
(14)
Derivative liability balances in the Unaudited Consolidated Balance Sheets are presented as a net liability for each counterparty. The amount in the table above excludes the year three asset balance of $48.0 thousand netted with the liability on the Unaudited Consolidated Balance Sheets.
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, 2013 for a discussion of trends and uncertainties that may affect our financial condition or liquidity.
Critical Accounting Policies and Estimates

36




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, 2013 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 three months ended March 31, 2014, our annual revenues would have decreased by approximately $0.1 million for each $1.00 per barrel decrease in crude oil prices, $0.1 million for each $0.10 decrease per MMBtu in natural gas prices and $0.3 million for each $1.00 per barrel decrease in NGL prices.
We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty. These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations.
As of April 18, 2014, we have financial derivative instruments related to oil, natural gas and NGL 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.”
 
April – December
2014
 
For the year
2015
 
For the year
2016
Oil (Bbls)
2,769,000

 
3,528,500

 
457,000

Natural Gas (MMbtu)
18,485,000

 
7,300,000

 

Natural Gas Liquids (Bbls)
279,167

 

 

Interest Rate Risks
At March 31, 2014, we had $180.0 million outstanding under our Amended Credit Facility, which bears interest at floating rates. The average annual interest rate incurred on this debt for the three months ended March 31, 2014 was 1.6%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2014 would have resulted in an estimated $0.3 million increase in interest expense assuming a similar average debt level to the three months ended March 31, 2014. The average annual interest rate incurred on this debt for the three months ended March 31, 2013 was 1.7%.
Item 4.
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. As of March 31, 2014, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of March 31, 2014.
Changes in Internal Controls. There has been no change in our internal control over financial reporting during the first fiscal quarter of 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

37




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 believes that the resolution of any proceeding will not 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, 2013. 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, 2013 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.

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 March 31, 2014:
 
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
January 1 – 31, 2014
70

 
$
26.34

 

 

February 1 – 28, 2014
78,564

 
24.58

 

 

March 1 – 31, 2014
507

 
24.31

 

 

Total
79,141

 
$
24.58

 

 

 
(1)
Represents shares delivered by employees to satisfy the exercise price of stock options and tax withholding obligations in connection with the exercise of stock options and shares withheld from employees to satisfy tax withholding obligations in connection with 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.


38


Item 6.   Exhibits.
 
Exhibit
Number
 
Description of Exhibits
2
 
Purchase and Sale Agreement dated October 22, 2013 between Bill Barrett Corporation and Enervest Energy Institutional Fund XIII-A, Enervest Energy Institutional Fund XIII-WIB, L.P., and Enervest Energy Institutional Fund XIII-WIC, L.P. [Incorporated by reference to Exhibit 2 of our Current Report on Form 8-K filed with the Commission on October 25, 2013.]

 
 
 
2.1
 
Amendment to Purchase and Sale Agreement, dated December 10, 2013, among Bill Barrett Corporation, Enervest Energy Institutional Fund XIII-A, L.P., Enervest Energy Institutional Fund XIII-WIB, L.P. and Enervest Energy Institutional Fund XIII-WIC, L.P. [Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed with the Commission on December 11, 2013.]
 
 
 
3.1
 
Restated Certificate of Incorporation of Bill Barrett Corporation. [Incorporated by reference to Appendix A to our Definitive Proxy Statement filed with the Commission on April 4, 2012.]
 
 
 
3.2
 
Bylaws of Bill Barrett Corporation. [Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed with the Commission on May 15, 2012.]
 
 
 
4.1(a)
 
Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
 
 
 
4.1(b)
 
Indenture, dated March 12, 2008, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
 
 
 
4.1(c)
 
Indenture, dated July 8, 2009, between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on July 8, 2009.]
 
 
 
4.2(a)
 
Registration Rights Agreement, dated March 28, 2002, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.2 of Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
 
 
 
4.2(b)
 
First Supplemental Indenture, dated March 12, 2008, by and between Bill Barrett Corporation and Deutsche Bank Trust Company Americas, as Trustee (including form of 5% Convertible Senior Notes due 2028). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2008.]
 
 
 
4.3(a)
 
Stockholders’ Agreement, dated March 28, 2002 and as amended to date, among Bill Barrett Corporation and the investors named therein. [Incorporated by reference to Exhibit 4.3 to Amendment No. 2 to our Registration Statement on Form S-1 (Registration No. 333-114554) filed with the Commission on August 31, 2004.]
 
 
 
4.3(b)
 
Third Supplemental Indenture, dated September 27, 2011, by Bill Barrett Corporation, Bill Barrett CBM Corporation, Bill Barrett CBM LLC, Circle B Land Company LLC, GB Acquisition Corporation, Elk Production, LLC, Aurora Gathering, LLC and Deutsche Bank Trust Company Americas, as Trustee (including form of 7.625% Senior Notes due 2019). [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on September 27, 2011.]
 
 
 
4.3(c)
 
Fourth Supplemental Indenture for the Company’s 7% Senior Notes due 2022, dated March 12, 2012, among the Company, the Subsidiary Guarantors and the Trustee. [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 12, 2012.]
 
 
 

39


Exhibit
Number
 
Description of Exhibits
4.4
  
Form of Rights Agreement concerning Shareholder Rights Plan, which includes, as Exhibit A thereto, the Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation, and, as Exhibit B thereto, the Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
 
 
 
4.5
  
Form of Certificate of Designations of Series A Junior Participating Preferred Stock of Bill Barrett Corporation. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
 
 
 
4.6
  
Form of Right Certificate. [Incorporated by reference to Exhibit 4.4 (Exhibit A) to Amendment No. 1 to our Registration Statement on Form 8-A filed with the Commission on December 20, 2004.]
 
 
 
4.7
 
Amendment No. 1 to Rights Agreement, dated as of March 18, 2013, between Bill Barrett Corporation and Computershare Shareowner Services LLC. [Incorporated by reference to Exhibit 4.5 to Amendment No. 2 to our Registration Statement on Form 8-A filed with the Commission on March 18, 2013.]
 
 
 
31.1*
  
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
 
 
 
31.2*
  
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
 
 
 
32.1*
  
Section 1350 Certification of Chief Executive Officer.
 
 
 
32.2*
  
Section 1350 Certification of Chief Financial Officer.
 
 
 
101.INS
  
XBRL Instance Document
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document
 
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document
 
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document
 
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document
 
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document

*
Furnished herewith.

40


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:
May 1, 2014
By:
 
/s/ R. Scot Woodall
 
 
 
 
R. Scot Woodall
 
 
 
 
Chief Executive Officer and President
 
 
 
 
(Principal Executive Officer)
 
 
 
 
Date:
May 1, 2014
By:
 
/s/ Robert W. Howard
 
 
 
 
Robert W. Howard
 
 
 
 
Chief Financial Officer
 
 
 
 
(Principal Financial Officer)

41