Exhibit 99.1

Press Release

For immediate release

Company contact: Jennifer Martin, Vice President of Investor Relations 303-312-8155

Bill Barrett Corporation Reports First Quarter 2015 Financial and Operating Results -

82% Production Growth from DJ, $1.00 per Share Discretionary Cash Flow

and 2015 Production Guidance Increased

DENVER – May 8, 2015 – Bill Barrett Corporation (the “Company”) (NYSE: BBG) reports first quarter of 2015 results, including these highlights:

• Produced 1.6 MMBoe, exceeding estimates as a result of strong well performance in the DJ Basin

• Increased DJ Basin production 82% over the first quarter of 2014 and 28% sequentially

• Delivered excellent performance from extended reach lateral drilling program, demonstrating consistent execution with results from four new wells

• Generated $1.00 per share discretionary cash flow

• Reduced long-term debt by $25 million with redemption of convertible securities

• Reaffirmed and extended revolving credit facility at $375 million

Chief Executive Officer and President Scot Woodall commented, “We have been saying over the last few months how encouraged we are with the preliminary results from our extended reach lateral (“XRL”) program in the Denver-Julesburg (“DJ”) Basin. These early, positive signals are now confirmed by our first quarter production volumes, which exceed our forecast. We have also observed improved well performance from our latest completion techniques, supporting the evolution of our completion designs. We expect continued outperformance from our XRL wells in 2015 and, as a result, are increasing full year 2015 production guidance. The Niobrara formation in the DJ Basin provides among the top economic returns of basins in the country, and our XRL well results support the economic viability of the play. More than 80% of our Northeast Wattenberg acreage position will be developed with XRL wells, which are expected to provide higher economic returns than standard length lateral wells.”

“We remain financially strong in the current macro-economic environment with the re-affirmed $375 million revolving credit facility undrawn, $149 million in cash and short-term investments, and more than 80% of our expected 2015 production hedged at very favorable commodity prices.”

OPERATING AND FINANCIAL RESULTS

Operating Results from Core Programs - DJ Basin and Uinta Oil

(Results from the first quarter of 2015 include nominal contributions from assets sold. Prior year period results are pro forma for assets sold.)

The Company had substantial growth in production from its core assets driven by strong Northeast Wattenberg XRL well results. Oil, natural gas and natural gas liquids (“NGL”) production from the DJ Basin and Uinta Oil Program (“UOP”) totaled 1.6 million barrels of oil equivalent (“MMBoe”) in the first quarter of 2015 compared with 1.1 MMBoe in the first quarter of 2014. DJ production grew 82% while UOP production was generally flat. Sequentially, first quarter 2015 daily production was up 18% from the fourth quarter of 2014. First quarter of 2015 production was 71% oil, 19% natural gas and 10% NGLs.

	Three Months Ended March 31,							Three Months Ended December 31,
	2015		2014		Change			2014		Change
Production Data:
Oil (MBbls)		1,125		760		48	%		953		18	%
Natural gas (MMcf)		1,764		1,290		37	%		1,689		4	%
NGLs (MBbls)		162		122		33	%		140		16	%
Combined volumes (MBoe)		1,581		1,097		44	%		1,375		15	%
Daily combined volumes (Boe/d)		17,567		12,193		44	%		14,946		18	%

Pre-hedge commodity prices are down significantly compared with 2014 due to macro-economic conditions. However, the Company has substantial hedges in place for 2015. For the first quarter of 2015 approximately 97% of natural gas production and 90% of oil production benefited from commodity derivative swaps that averaged $92.33 per barrel of oil (WTI) and $4.15 per MMBtu of natural gas (regionally priced at NWPL). The Company had no NGL hedges in place. The Company previously provided estimates based on preliminary results of first quarter of 2015 commodity differentials and pre-hedge pricing that differed from amounts below for natural gas and NGLs. Upon further review, the Company has reclassified certain processing deductions of natural gas and NGLs from being fully deducted from the NGL revenue stream to be allocated between the commodities. Going forward the Company will continue to allocate these processing deductions between commodities based on the value of each commodity’s revenue stream.

	Three Months Ended March 31,						Three Months Ended December 31,
	2015 Pre- hedge		2015 Including hedge		2014 Pre- hedge		2014 Pre- hedge		Change
Average Sales Prices:
Oil (per Bbl)	$	37.12	$	76.28	$	81.80	$	58.39		-36	%
Natural gas (per Mcf)		2.60		3.92		6.05		4.35		-31	%
NGLs (per Bbl)		13.31		13.31		25.82		17.83		-50	%
Combined (per Boe)		30.68		60.01		66.63		47.65		-36	%

Cash operating costs (lease operating expense, gathering, transportation and processing costs and production tax expense) were $10.92 per Boe in the first quarter of 2015, down 33% due to lower costs in each category. The DJ Basin has lower per unit operating costs than the Uinta. Production tax expense per unit for the first quarter of 2015 was down significantly and averaged 5.2% of pre-hedge revenue. Lower production taxes are primarily a result of lower commodity prices; in addition, taxes for the first quarter of 2015 included certain true-ups based on prior tax filings. Normalized production taxes are expected to approximate 8% of pre-hedge revenue for the remainder of the year.

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	Three Months Ended March 31,							Three Months Ended December 31,
	2015		2014		Change			2014		Change
Average Costs (per Boe):
Leasing operating expenses	$	8.72	$	10.07		-13	%	$	8.93		-2	%
Gathering, transportation and processing expense		0.60		0.90		-33	%		0.89		-33	%
Production tax expenses		1.60		5.35		-70	%		3.25		-51	%
Depreciation, depletion and amortization		33.05		31.36		5	%		33.69		-2	%

Corporate Discretionary Cash Flow and Adjusted Net Loss

(Prior period totals are total company results and are not pro forma for assets sold.)

Discretionary cash flow and adjusted net loss are non-GAAP measures. These measures are reconciled to net income (loss) in the schedules below. Net loss for the first quarter of 2015 was ($11.7) million, or ($0.24) per share, compared with the first quarter of 2014 at $(12.7) million, or ($0.27) per share.

Discretionary cash flow and adjusted net income as previously reported for the 2014 period includes cash flow and income generated from assets sold over the past two years.

	Three Months Ended March 31,
	2015			2014
Discretionary Cash Flow ($ millions)	$	48.1		$	55.3
Discretionary Cash Flow per share		1.00			1.15
Adjusted Net Loss ($ millions)		(5.9	)		(2.2	)
Adjusted Net Loss per share		(0.12	)		(0.05	)

Discretionary cash flow in the first quarter of 2015 was $48.1 million, or $1.00 per diluted common share, down from $55.3 million, or $1.15 per diluted common share, in the first quarter of 2014. Higher per unit revenue and lower per unit costs in the first quarter of 2015 were more than offset by a 35% decline in production as a result of asset sales.

Adjusted net loss was ($5.9) million, or ($0.12) per diluted common share, in the first quarter of 2015 compared with ($2.2) million, or ($0.05) per diluted common share, in the first quarter of 2014. The larger loss in 2015 was primarily driven by a 45% increase in per unit depreciation, depletion and amortization expense compared with 2014, primarily attributable to a higher proportion of oil in the production and reserves mix following the natural gas asset sales. Adjusted net income (loss) removes the effect of unrealized derivative gains and losses and non-recurring charges such as impairment expenses, property sales and certain one-time items.

Debt & Liquidity

At March 31, 2015, the Company’s revolving credit facility had a $375.0 million borrowing base with zero drawn and $349.0 million in available capacity, after taking into account a $26.0 million letter of credit. In April 2015, the borrowing base was reaffirmed at $375 million and the maturity

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date was extended to April 2020. The principal balance of long-term debt was $803.1 million and cash and short-term investments were $148.7 million, resulting in net debt (principal balance of debt outstanding less the cash and investment balance) of $654.4 million. Liquidity was $497.7 million.

Capital Expenditures

Capital expenditures for the first quarter of 2015 were $114.3 million, in line with guidance of $115 million. Included in this capital was drilling 22 gross/13 net wells in the Northeast Wattenberg, of which 9 gross/9 net were XRL wells and operated by the Company. The Company also drilled 4 gross/2 net vertical wells in the East Bluebell area of the UOP. In the first quarter, 10 wells were put on sales including 2 gross/2 net XRL wells and 8 gross/7 net standard length lateral wells. Capital expenditures included $108.1 million for drilling at development programs, $1.6 million for leaseholds, and $4.6 million for infrastructure and corporate assets.

Regional Summary

	Three Months Ended March 31, 2015
	Average Net Daily Production (Boe/d)		Wells Spud Net(1)		Capital Expenditures ($ millions)
Basin:
Denver-Julesburg		11,678		13	$	99.6
Uinta		5,683		2		12.9
Other		206				1.8
		17,567		16	$	114.3

(1) Includes operated and non-operated wells

OPERATIONS BRIEF

DJ Basin

First quarter DJ Basin highlights include:

• Drilled 9 gross/9 net operated wells.

• Placed into sales 2 gross/2 net XRL and 8 gross/7 net standard laterals.

• Produced an average 11,678 Boe/d, up 82% from the first quarter of 2014 and up 28% sequentially.

• Reached 30-day peak initial production (“IP”) (see Disclosure section below) rates on four new XRL wells. Including these wells, the Company now has 30-day IP rates for 20 XRL wells that average 581 Boe/d (3-stream) per well. The four new wells are located on two pads in the northern portion of the Northeast Wattenberg position and were all drilled into the Niobrara B horizon with 55 stage completions. Two of the wells were completed with approximately 1,000 pounds of proppant per foot and two wells with approximately 1,300 pounds of proppant per foot.

• Identified preferred completion technology and mechanics for XRL wells. The Company has tested a number of completion techniques and believes that the combination of plug-and-perf mechanics and 55-stage completions combined with controlled flowback methods are providing a step-change in well performance:

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• 7 wells with plug-and-perf mechanics had average 30-day IP rates of 639 Boe/d, of which 3 wells had average 60-day IP rates of 557 Boe/d, compared with 13 sliding sleeve completions that had average 30-day IP rates of 550 Boe/d, and 12 wells had average 60-day IP rates of 457 Boe/d.

• The preferred mechanics yield a 16% improvement in 30-day rates and initial declines appear to be shallower than previous completion techniques. These wells are expected to track more closely to the upper end of our recovery expectations.

The Northeast Wattenberg XRL program is the focus of the 2015 operating plan as it offers the best returns in the Company’s portfolio. In addition, the Company completed eight standard length (4,000 foot) lateral wells in the first quarter of 2015 (drilled in 2014) where the new completion and flowback practices were applied. The Company plans to drill 22-25 gross/20-22 net wells in the Northeast Wattenberg during 2015, which will be predominantly XRL wells, and to participate in approximately 5 net non-operated wells in the area.

Uinta Oil Program

2014 UOP highlights include:

• Drilled 4 gross/2 net wells and placed 7 gross/5 net wells into sales.

• New wells test 40 acre spacing.

First quarter of 2015 development drilling was in the East Bluebell area of the UOP. All wells drilled in the quarter were on 40 acre density. Operations are focused on cost efficiencies, and the Company is realizing significant reductions. Regional price realizations currently reflect a posted deduct of approximately $8.75 off WTI, which was significantly improved during the first quarter from approximately $18.75 early in the quarter.

Other Assets

During the first quarter of 2015 the Company received net settlement proceeds related to the Cottonwood Gulch litigation of $42.9 million and completed the sale of all remaining Powder River Basin assets and other non-core assets for proceeds of $21.6 million.

2015 OPERATING GUIDANCE

The Company’s 2015 plan is expected to result in approximately 16%+ production growth from core assets. The plan does not require additional debt and focuses investment on highest return development. The Company anticipates participating in approximately 80-85 gross/34-36 net development wells, of which approximately 39 gross/27 net are to be operated by the Company.

The Company is providing the following updated guidance for its 2015 activities. See “Forward-Looking Statements” below.

• Capital expenditures of up to $280 million:

• Expenditures are expected to be at the higher end of the earlier reported $240-280 million range as the Company increased net well participation by approximately 10 wells. This includes higher working interests in the Northeast Wattenberg, participation in non-operated wells in the Chalk Bluffs area and drilling 3 net wells in the Blacktail Ridge area of the UOP.

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• Second quarter 2015 capital expenditures are expected to be approximately $80-90 million.

• Production of 5.9-6.3 MMBoe, increased 7% at the mid-point from 5.5-5.9 MMBoe.

• The increase is due to well performance and the increase in net wells.

• Production is expected to be approximately 70% oil, 20% natural gas and 10% NGLs.

• Second quarter of 2015 production is expected to be approximately 1.5 MMBoe.

• Lease operating expenses of $48-$52 million, increased to correspond with higher expected production.

• Second quarter expenses are expected to be similar-to-lower per unit compared with the first quarter while second half of 2015 expenses are expected to decline as certain cost saving measures are realized.

• Gathering, transportation and processing costs of $4-$6 million, increased to correspond with higher expected production.

• Unused commitment primarily for firm natural gas transportation charges of $20-$21 million, increased from $18-19 million.

• General and administrative expenses, before long-term performance-based compensation, unchanged at $36-$40 million.

COMMODITY HEDGES UPDATE

The Company has hedges in place for more than 80% of its forecast 2015 production. Generally, it is the Company’s strategy to hedge 50%-70% of production on a forward 12-month basis in order to reduce the risks associated with unpredictable future commodity prices and to provide certainty for a portion of its cash flow to support its capital expenditure program.

The following table summarizes hedge positions as of May 5, 2015:

	Oil (WTI)				Natural Gas (NWPL)
Period	Volume Bbls/d		Price $/Bbl		Volume MMBtu/d		Price $/MMBtu
2Q15		11,300		90.39		20,000		4.13
3Q15		10,800		89.81		20,000		4.13
4Q15		10,800		89.81		20,000		4.13
1Q16		6,800		83.06		5,000		4.10
2Q16		6,800		83.06		5,000		4.10
3Q16		5,500		81.15		5,000		4.10
4Q16		5,500		81.15		5,000		4.10
1Q17		1,500		78.16		—		—
2Q17		1,500		78.16		—		—
3Q17		1,000		84.74		—		—
4Q17		1,000		84.74		—		—

Realized sales prices will reflect basis differentials from the index prices to the sales location.

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UPCOMING EVENTS

First Quarter Conference Call and Webcast

The Company plans to host a conference call this morning to discuss results and management’s outlook for the future, the context of which is not part of this earning’s release. The call is scheduled at 11:00 a.m. Eastern time (9:00 a.m. Mountain time) today. Please join the webcast conference call live or for replay via the Internet at www.billbarrettcorp.com, accessible from the home page. To join by telephone, call 855-760-8152 (631-485-4979 international callers) with passcode 24970194. The webcast will remain on the Company’s website for approximately 30 days and a replay of the call will be available through May 15, 2015 at 855-859-2056 (404-537-3406 international) with passcode 24970194.

DISCLOSURE STATEMENTS

Well Performance

The calculation of 30-day IP rates measures the daily production from a well starting with the date upon which the Company determines the well has achieved peak production and averages the daily production for 30 days. This date will occur at some point after oil production commences. In addition, in calculating the IP rate of a well over a specified period of time, the calculation will exclude days on which production is impaired for mechanical, third party mid-stream or other non-geologic reasons. IP rates and other initial indications of well performance do not necessarily reflect expected ultimate recoveries or other long-term measures of a well’s performance. Peer data may not be comparable to results obtained by the Company.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are subject to events, risks and uncertainties that may be outside the Company’s control. Actual results could differ materially from those discussed in the forward-looking statements. In particular, the Company is providing “2015 Operating Guidance,” which contains projections for certain 2015 operational and financial metrics as well as certain projections for the second quarter of 2015.

These and other forward-looking statements in this presentation are based on management’s judgment as of the date of this presentation and are subject to numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements due to, among other things: oil, NGL and natural gas price volatility, including regional price differentials; changes in operational and capital plans; changes in capital costs, operating costs, availability and timing of build-out of third party facilities for gathering, processing, refining and transportation; delays or other impediments to drilling and completing wells arising from political or judicial developments at the local, state or federal level, including voter initiatives related to hydraulic fracturing; development drilling and testing results; the potential for production decline rates to be greater than expected; regulatory delays, including seasonal or other wildlife restrictions on federal lands; exploration risks such as drilling unsuccessful wells; higher than expected costs and expenses, including the availability and cost of services and materials; unexpected future capital expenditures; economic and competitive conditions; debt and equity market conditions, including the availability and costs of financing to fund the Company’s operations; the ability to obtain industry partners to jointly explore certain prospects, and the

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willingness and ability of those partners to meet capital obligations when requested; declines in the values of our oil and gas properties resulting in impairments; changes in estimates of proved reserves; compliance with environmental and other regulations, including new emission control requirements; derivative and hedging activities; risks associated with operating in one major geographic area; the success of the Company’s risk management activities; title to properties; litigation; and environmental liabilities. Please refer to the Company’s Annual Report on Form 10-K for the year ended December 31, 2014 filed with the SEC and other filings, including our Current Reports on Form 8-K and Quarterly Reports on Form 10-Q, all of which are incorporated by reference herein, for further discussion of risk factors that may affect the forward-looking statements. The Company encourages you to consider the risks and uncertainties associated with projections and other forward-looking statements and to not place undue reliance on any such statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.

ABOUT BILL BARRETT CORPORATION

Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado, develops oil and natural gas in the Rocky Mountain region of the United States. Additional information about the Company may be found on its website www.billbarrettcorp.com.

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BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)

	Three Months Ended
	March 31,
	2015		2014 (1)
Production Data:
Oil (MBbls)		1,125		922
Natural gas (MMcf)		1,764		6,420
NGLs (MBbls)		162		442
Combined volumes (MBoe)		1,581		2,434
Daily combined volumes (Boe/d)		17,567		27,044
Average Sales Prices (before the effects of realized hedges):
Oil (per Bbl)	$	37.12	$	82.60
Natural gas (per Mcf)		2.60		5.57
NGLs (per Bbl)		13.31		34.19
Combined (per Boe)		30.68		52.19
Average Realized Sales Prices (after the effects of realized hedges):
Oil (per Bbl)	$	76.28	$	78.78
Natural gas (per Mcf)		3.92		4.79
NGLs (per Bbl)		13.31		33.00
Combined (per Boe)		60.01		48.47
Average Costs (per Boe):
Lease operating expense	$	8.72	$	6.64
Gathering, transportation and processing expense		0.60		4.81
Production tax expense		1.60		3.13
Depreciation, depletion and amortization		33.05		22.81
General and administrative expense, excluding long-term incentive compensation expense (2)		6.50		4.86

(1) 2014 data represents total company as previously reported for the period, including assets subsequently sold.

(2) This separate presentation is a non-GAAP (Generally Accepted Accounting Principles) measure. Management believes the separate presentation of the long-term incentive compensation component of general and administrative expense is useful because it provides a better understanding of current period general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company’s peers, which may have higher or lower stock-based/long-term incentive compensation expense. See “Operating Expenses” in the Consolidated Statements of Operations.

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BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)

	As of March 31, 2015		As of December 31, 2014
(in thousands)
Assets:
Cash and cash equivalents	$	33,772	$	165,904
Short-term investments		114,918		—
Other current assets (1)		197,193		260,201
Property and equipment, net		1,790,332		1,753,121
Other noncurrent assets (1)		59,886		65,258
Total assets	$	2,196,101	$	2,244,484
Liabilities and Stockholders’ Equity:
Current liabilities, other	$	232,218	$	239,343
Current liabilities, convertible senior notes		579		25,344
Notes payable to bank		—		—
Capitalized lease obligation		3,113		3,222
Senior notes		800,000		800,000
Convertible senior notes		—		—
Other long-term liabilities		142,158		147,087
Stockholders’ equity		1,018,033		1,029,488
Total liabilities and stockholders’ equity	$	2,196,101	$	2,244,484

(1) At March 31, the estimated fair value of all of the Company’s commodity derivative instruments was a net asset of $183.0 million, comprised of $137.8 million of current assets and $45.2 million of non-current assets. This amount will fluctuate quarterly based on estimated future commodity prices and the current hedge position.

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BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended
	March 31,
	2015			2014
(in thousands, except per share amounts)
Operating and Other Revenues:
Oil, gas and NGLs (1)	$	48,486		$	127,169
Other		548			519
Total operating and other revenues		49,034			127,688
Operating Expenses:
Lease operating		13,791			16,164
Gathering, transportation and processing		942			11,704
Production tax		2,534			7,624
Exploration		33			303
Impairment, dry hole costs and abandonment		1,255			1,761
Gain on divestitures		(38	)		—
Depreciation, depletion and amortization		52,254			55,508
Unused commitments		4,388			—
General and administrative (2)		10,279			11,819
Long-term incentive compensation (2)		3,050			3,588
Total operating expenses		88,488			108,471
Operating Income (Loss)		(39,454	)		19,217
Other Income and Expense:
Interest and other income		275			375
Interest expense		(16,430	)		(17,431	)
Commodity derivative gain (loss) (1)		34,438			(25,155	)
Gain on extinguishment of debt		2,567			—
Total other income and expense		20,850			(42,211	)
Net Loss before Income Taxes		(18,604	)		(22,994	)
Provision for (Benefit from) Income Taxes		(6,873	)		(10,245	)
Net Loss	$	(11,731	)	$	(12,749	)
Net Loss Per Common Share
Basic	$	(0.24	)	$	(0.27	)
Diluted	$	(0.24	)	$	(0.27	)
Weighted Average Common Shares Outstanding
Basic		48,199			47,890
Diluted		48,199			47,890

(1) The table below summarizes the realized and unrealized gains and losses the Company recognized related to its oil and natural gas derivative instruments for the periods indicated:

	Three Months Ended March 31,
	2015			2014
Included in oil, gas and NGL production revenue:
Certain realized gains on hedges	$	—		$	156
Included in commodity derivative gain (loss):
Realized gain (loss) on derivatives not designated as cash flow hedges	$	46,375		$	(9,200	)
Unrealized loss on derivatives not designated as cash flow hedges		(11,937	)		(15,955	)
Total commodity derivative gain (loss)	$	34,438		$	(25,155	)

(2) This separate presentation is a non-GAAP (Generally Accepted Accounting Principles) measure. Management believes the separate presentation of the long-term incentive compensation component of general and administrative expense is useful because it provides a better understanding of current period general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company’s peers, which may have higher or lower stock-based/long-term incentive compensation expense.

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BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended
	March 31,
	2015			2014
(in thousands)
Operating Activities:
Net loss	$	(11,731	)	$	(12,749	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		52,254			55,508
Impairment, dry hole costs and abandonment expense		1,255			1,761
Unrealized derivative (gain) loss, non-cash flow hedges		11,937			15,955
Deferred income tax benefit		(6,873	)		(10,245	)
Incentive compensation and other non-cash charges		2,743			3,692
Amortization of debt discounts and deferred financing costs		1,067			1,067
Gain on sale of properties		(38	)		—
Gain on extinguishment of debt		(2,567	)		—
Change in assets and liabilities:
Accounts receivable		9,064			5,530
Prepayments and other assets		(1,364	)		408
Accounts payable, accrued and other liabilities		(1,661	)		6,134
Amounts payable to oil & gas property owners		6,838			9,401
Production taxes payable		(7,099	)		(1,268	)
Net cash provided by operating activities	$	53,825		$	75,194
Investing Activities:
Additions to oil and gas properties, including acquisitions		(111,009	)		(128,938	)
Additions of furniture, equipment and other		(609	)		(274	)
Proceeds from sale of properties and other investing activities		66,415			(388	)
Cash paid for short term investments		(114,883	)		—
Net cash used in investing activities	$	(160,086	)	$	(129,600	)
Financing Activities:
Proceeds from debt		—			65,000
Principal payments on debt		(24,871	)		(1,137	)
Deferred financing costs and other		(1,000	)		(1,946	)
Proceeds from stock option exercises		—			126
Net cash provided by (used in) financing activities	$	(25,871	)	$	62,043
Increase (Decrease) in Cash and Cash Equivalents		(132,132	)		7,637
Beginning Cash and Cash Equivalents		165,904			54,595
Ending Cash and Cash Equivalents	$	33,772		$	62,232

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BILL BARRETT CORPORATION

Reconciliation of Discretionary Cash Flow & Adjusted Net Income (Loss)

(Unaudited)

Discretionary Cash Flow Reconciliation

	Three Months Ended
	March 31,
	2015			2014
(in thousands, except per share amounts)
Net Loss	$	(11,731	)	$	(12,749	)
Adjustments to reconcile to discretionary cash flow:
Depreciation, depletion and amortization		52,254			55,508
Impairment, dry hole and abandonment expense		1,255			1,761
Exploration expense		33			303
Unrealized derivative loss, non-cash flow hedges		11,937			15,955
Deferred income taxes		(6,873	)		(10,245	)
Stock compensation and other non-cash charges		2,743			3,692
Amortization of debt discounts and deferred financing costs		1,067			1,067
Gain on sale of properties		(38	)		—
Gain on extinguishment of debt		(2,567	)		—
Discretionary Cash Flow	$	48,080		$	55,292
Per share, diluted	$	1.00		$	1.15
Per Boe	$	30.41		$	22.72
Adjusted Net Income (Loss) Reconciliation
	Three Months Ended March 31,
	2015			2014
(in thousands except per share amounts)
Net Loss	$	(11,731	)	$	(12,749	)
Adjustments to net loss:
Unrealized derivative loss, non-cash flow hedges		11,937			15,955
Impairment expense		58			1,038
Gain on sale of properties		(38	)		—
Gain on extinguishment of debt		(2,567	)		—
Subtotal adjustments		9,390			16,993
Statutory tax rate		38	%		38	%
Tax effected adjustments		5,822			10,536
Adjusted Net Loss	$	(5,909	)	$	(2,213	)
Per share, diluted	$	(0.12	)	$	(0.05	)
Per Boe	$	(3.74	)	$	(0.91	)

Discretionary cash flow and adjusted net income (loss) are non-GAAP measures. These measures are presented because management believes that they provide useful additional information to investors for analysis of the Company’s ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income (loss) for one-time or unusual items to allow for a more consistent comparison from period to period. In addition, the Company believes that these measures are widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and that many investors use the published research of industry research analysts in making investment decisions.

These measures should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, profitability, cash flow or liquidity measures prepared in accordance with GAAP. Because discretionary cash flow and adjusted net income (loss) exclude some, but not necessarily all, items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similarly titled measures of other companies.

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