BILL BARRETT CORP - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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8-K - 8-K - BILL BARRETT CORP	bbg-9302015x8kxearningsrel.htm



		Press Release

For immediate release

Company contact: Larry C. Busnardo, Senior Director, Investor Relations, 303-312-8514

Bill Barrett Corporation Reports Third Quarter 2015 Results - Production Volume of 1.7 MMBoe Exceeds Guidance, 72% Production Growth from DJ Basin, Continued

Cost Discipline with LOE of $5.67 per Boe; Expect Non-Core Asset Sales of

$79 Million to be Accomplished during 2015

DENVER - November 5, 2015 - Bill Barrett Corporation (the "Company") (NYSE: BBG) reports third quarter of 2015 results, including these highlights:


•	Production sales volumes of 1.7 MMBoe, exceeding guidance by 13% due to the performance of the DJ Basin extended reach lateral ("XRL") drilling program


•	Increased Denver-Julesburg ("DJ") Basin production by 72% year-over-year and 14% sequentially


•	Reported adjusted net income of $(0.09) per share excluding non-recurring charges and impairment expense; generated $1.11 per share of discretionary cash flow


•	Maintaining cost discipline as XRL well costs of $5.6 million are approximately 32% lower compared to wells drilled in the fourth quarter of 2014


•	Lease operating expense of $5.67 per Boe, a 19% sequential reduction


•	Lease operating expense guidance lowered by 8% at the mid-point to $45-$47 million


•	Executed agreements to sell non-core asset for aggregate proceeds of $79 million year-to-date


•	Borrowing base reaffirmed at $375 million in September 2015

Chief Executive Officer and President Scot Woodall commented, "We posted another quarter of solid results that was highlighted by production exceeding expectations for a third consecutive quarter and our ability to decrease drilling days for XRL wells and meaningfully lower well costs and cash expenses. We remain on track to meet full-year production guidance despite shutting in approximately 1,000 Boe/d of production in the Uinta Basin during the second quarter of 2015 and including a reduction in volumes associated with expected asset sales. This is clearly a reflection of the performance of our Northeast ("NE") Wattenberg assets. XRL drilling days have improved by 40% to approximately 10 days per well and we have been consistently drilling recent wells in 8 days or less. Furthermore, associated cost reductions have lowered completed XRL well costs to $5.6 million, or by 32%, and we are committed to continuous cost reduction measures as we endeavor to further improve our capital efficiency. Efficiency gains are also translating into tangible reductions in operating costs across our assets, as evidenced by third quarter LOE of $5.67 per Boe, which was 19% lower than the second quarter, and we will seek additional means to drive down costs.

"We maintain a strong financial position. Year-to-date, we have executed agreements to sell assets that were not expected to compete for drilling capital in the near or mid-term for aggregate proceeds of $79 million, including transactions in the DJ, Uinta and Powder River Basins. This further augments our balance sheet and enhances our liquidity as we look to 2016. Our undrawn revolving credit facility was recently reaffirmed at $375 million and, when combined with our cash position, provides ample liquidity to navigate the current environment."

THIRD QUARTER 2015 OPERATING AND FINANCIAL RESULTS

(Prior year period results are pro forma for assets sold.)

The Company realized growth in production volumes from its core DJ Basin asset, driven by the results of the NE Wattenberg XRL well program that offset a production decline from the Uinta Oil Program ("UOP"). Oil, natural gas and natural gas liquids ("NGL") production from the DJ Basin and UOP totaled 1.7 million barrels of oil equivalent ("MMBoe") in the third quarter of 2015 compared with 1.4 MMBoe in the third quarter of 2014. DJ Basin production grew 72%, while UOP production was down 38% as compared to the third quarter of 2014. The decline in UOP production was primarily due to a decrease in drilling and workover activity and the decision to shut-in certain wells during the second quarter of 2015 due to higher operating costs. Third quarter of 2015 production was 63% oil, 22% natural gas and 15% NGLs. The increase in the proportion of natural gas and NGL volumes relative to oil volumes was primarily due to a greater amount of natural gas liquids yields that benefited from the expansion of regional processing capacity and the delay in timing of oil sales from inventory.



	Three Months Ended September 30,				Three Months Ended June 30,
	2015	2014	Change		2015	Change
Production Sales Data:
Oil (MBbls)	1,066	934	14	%	1,120	(5	)%
Natural gas (MMcf)	2,214	1,842	20	%	1,800	23	%
NGLs (MBbls)	264	148	78	%	208	27	%
Combined volumes (MBoe)	1,699	1,389	22	%	1,628	4	%
Daily combined volumes (Boe/d)	18,467	15,098	22	%	17,890	3	%

Pre-hedge commodity prices were down significantly compared with 2014. For the third quarter of 2015, 93% of oil production and 83% of natural gas production benefited from commodity derivative swaps that averaged $89.81 per barrel of oil (WTI) and $4.13 per MMBtu of natural gas (regionally priced at NWPL). The Company had no NGL hedges in place.



	Three Months Ended September 30,						Three Months Ended June 30,
	2015 Pre- hedge		2015 Including hedge		2014 Pre- hedge		2015 Pre- hedge		2015 Including hedge
Average Sales Price:
Oil (per Bbl)	$	38.71	$	79.15	$	82.25	$	48.68	$	78.44
Natural gas (per Mcf)	2.08		3.36		4.32		2.33		4.10
NGLs (per Bbl)	11.17		11.17		24.27		12.76		12.76
Combined (per Boe)	28.73		55.77		63.64		37.70		60.13

Cash operating costs (lease operating expense ("LOE"), gathering, transportation and processing costs and production tax expense) were $8.23 per Boe in the third quarter of 2015, down 17% compared to the second quarter of 2015. LOE was $5.67 per Boe, down 19% compared to the second quarter of 2015. This was primarily a result of increased operational efficiencies, lease operating cost reductions and the Company's decision during the second quarter of 2015 to reduce workover activity in the UOP and to shut-in certain UOP wells in the current commodity price environment. LOE for the DJ Basin improved to an average of $3.96 per Boe in the third quarter of 2015. Production tax expense for the third quarter of 2015 averaged 7.5% of pre-hedge revenue. Normalized production taxes are expected to approximate 8% of pre-hedge revenue for the fourth quarter of 2015.



	Three Months Ended September 30,						Three Months Ended June 30,
	2015		2014		Change		2015		Change
Average Costs (per Boe):
Lease operating expenses	$	5.67	$	7.53	(25	)%	$	7.01	(19	)%
Gathering, transportation and processing expense	0.40		0.63		(37	)%	0.57		(30	)%
Production tax expenses	2.16		5.48		(61	)%	2.34		(8	)%
Depreciation, depletion and amortization	32.22		34.31		(6	)%	32.36		—	%

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 schedule attached to this press release. 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.

Discretionary cash flow in the third quarter of 2015 was $53.5 million, or $1.11 per share, compared to $70.1 million, or $1.46 per share, in the third quarter of 2014. Discretionary cash flow in the third quarter of 2015 compared to 2014 was impacted by lower revenues due to a 36% decline in production volumes as a result of asset sales.

Net loss for the third quarter of 2015 was $(410.3) million, or $(8.49) per share, compared with the third quarter of 2014 at $(34.6) million, or $(0.72) per share. Adjusted net loss was $(4.4) million, or $(0.09) per share, in the third quarter of 2015 compared with $(3.1) million, or $(0.06) per share, in the third quarter of 2014. 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.



	Three Months Ended September 30,
	2015			2014
Discretionary Cash Flow ($ millions)	$	53.5		$	70.1
Discretionary Cash Flow per share	1.11			1.46
Adjusted Net Loss ($ millions)	(4.4		)	(3.1		)
Adjusted Net Loss per share	(0.09		)	(0.06		)

Non-Cash Impairment

The Company recognized a non-cash impairment charge of $571.9 million in the third quarter of 2015 related to the UOP proved and unproved oil and gas assets. The impairment was the result of reduced future net revenues compared against the current carrying value from the second quarter of 2015 to the third quarter of 2015.

Primarily as a result of this quarter's impairment charge, the Company recorded a valuation allowance against its net deferred tax asset of $66.4 million.

Debt and Liquidity

The Company's semi-annual borrowing base review was completed in September 2015 with the bank group reaffirming the Company's $375 million borrowing base related to its revolving credit

facility maturing in April 2020. At September 30, 2015, the revolving credit facility had zero drawn and $349.0 million in available capacity, after taking into account a $26.0 million letter of credit. The principal balance of long-term debt was $802.9 million and cash and short-term investments were $112.8 million, resulting in net debt (principal balance of debt outstanding less the cash and investment balance) of $690.1 million. Liquidity was $461.8 million.

In addition, as of November 5, 2015, the Company has not issued any shares under its previously announced "at-the-market" equity offering program and does not anticipate currently utilizing it due to market conditions.

Divestitures

During the third quarter, the Company announced the signing of an agreement to sell certain properties located in the Uinta Basin for after-tax cash proceeds of approximately $27 million. The transaction is expected to close on or before November 30, 2015, subject to customary closing conditions. The properties produced approximately 484 Boe/d during September 2015, had estimated proved reserves of 11 million barrels of oil equivalent (“MMBoe”) (9% proved developed) as of December 31, 2014 and included 17,632 net acres.

Subsequent to the end of the quarter, the Company executed agreements to sell certain assets in the DJ Basin that are located outside of the core NE Wattenberg area for after-tax cash proceeds of approximately $31 million. The transaction is expected to close on or before November 30, 2015, and is subject to customary closing conditions.

Including this transaction, the Company has completed or announced three separate DJ Basin transactions for aggregate after-tax proceeds of $43 million during 2015. None of the assets sold are located within the Company's NE Wattenberg focus area, and they were not expected to compete for drilling capital in the near or mid-term. The assets primarily included legacy vertical wells that had estimated production of approximately 1,265 Boe/d (29% natural gas), estimated proved reserves of 4 MMBoe (76% proved developed) as of December 31, 2014 and included 23,735 net acres. Based on the Company’s internal estimates, the sale price amounts to approximately 8x estimated 2016 operating cash flow (excluding general and administrative expense) based on current strip pricing.

In aggregate, the Company expects to receive proceeds of approximately $58 million, prior to customary purchase price adjustments, for the Uinta Basin and recent DJ Basin divestitures in the fourth quarter of 2015. The sale of these properties will not result in a reduction of the Company’s borrowing base related to its revolving credit facility.

Capital Expenditures

Capital expenditures ("Capex") for the third quarter of 2015 were $63.2 million and totaled $242.6 million for the nine months ended September 30, 2015. Capex included 18 gross/ 16.9 net spud wells in the DJ Basin, all of which were XRL wells operated by the Company, and 3 gross/ 1 net operated wells in the UOP. In the third quarter, 8 gross/ 7.8 net XRL wells began flowback operations and were placed on initial sales. Capital expenditures included $59.3 million for drilling, $0.8 million for leaseholds, and $3.1 million for infrastructure and corporate assets.

Basin Summary



	Three Months Ended September 30, 2015				Nine Months Ended September 30, 2015
	Average Net Daily Production (Boe/d)	Wells Spud Net ⁽¹⁾	Capital Expenditures ($ millions)		Average Net Daily Production (Boe/d)	Wells Spud Net ⁽¹⁾	Capital Expenditures ($ millions)
Basin:
Denver-Julesburg	14,250	18	$	55.8	12,828	38	$	214.3
Uinta	4,185	2	7.2		5,059	8	26.3
Other ⁽²⁾	32	—	0.2		91	—	2.0
Total	18,467	20	$	63.2	17,978	46	$	242.6


(1)	Includes operated and non-operated wells


(2)	Primarily non-operated production in Wyoming and New Mexico

OPERATIONAL HIGHLIGHTS

DJ Basin

Third quarter DJ Basin highlights include:


•	Produced an average of 14,250 Boe/d, an increase of 72% from the third quarter of 2014 and an increase of 14% sequentially.


•	DJ Basin oil volumes averaged 8,283 Bbls/d, an increase of 72% from the third quarter of 2014 and an increase of 3% sequentially.


•	Spud 18 gross/ 16.9 net operated XRL wells during the third quarter of 2015.


•	Placed 8 gross/ 7.8 net XRL wells on initial sales during the third quarter of 2015.


•	Placed 9 gross/ 8.1 net XRL wells on initial sales in November 2015.


•	Operational efficiency increased by reducing the number of drilling days for XRL wells by 40% to an average of approximately 10 days per well. Recent wells have consistently been drilled in approximately 8 days per well, including a best-in-class well drilled in 6.9 days. These improved efficiencies allow the remainder of 2015 drilling program to be accomplished with one-rig drilling program.


•	Maintaining a sharp focus on cost discipline as recently contracted XRL drilling and completion costs of $5.6 million are approximately 32% lower compared to wells drilled in the fourth quarter of 2014.

The NE Wattenberg XRL program remains the focus of the 2015 operating plan as it offers the best returns in the Company's portfolio. Approximately 90% of the 2015 capital expenditures are planned for the NE Wattenberg area.

Uinta Oil Program

Drilling and completion activity in the UOP for the remainder of the year includes 4 commitment wells as the Company has elected to focus the majority of its 2015 capital program on its higher-return DJ Basin assets. Operations are focused on operational efficiencies, and associated cost reductions have been realized as a result of lower lease operating costs following the Company's decision to proactively reduce workover activity in the UOP and to shut-in certain wells in the current commodity price environment.

2015 OPERATING GUIDANCE

The Company is providing the following update to guidance for its 2015 activities. See "Forward-Looking Statements" below.


•	Capital expenditures of $315-$325 million, unchanged.


◦	Includes the reduction in the operated rig count from two rigs to one rig in NE Wattenberg as previously announced.


•	Production of 6.3-6.5 MMBoe, unchanged.


◦	It is estimated that the aggregate production reduction from the pending DJ and Uinta Basin asset sales, which are scheduled to close on or before November 30, 2015, will be approximately 42 MBoe in December 2015.


•	Lease operating expense of $45-$47 million, decreased from $48-$52 million to correspond with lease operating cost reductions in both the DJ Basin and UOP.

COMMODITY HEDGES UPDATE

Generally, it is the Company's strategy to hedge 50%-70% of production on a forward 12-month to 18-month basis to reduce the risks associated with unpredictable future commodity prices to provide certainty for a portion of its cash flow and to support its capital expenditure program.

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



	Oil (WTI)			Natural Gas (NWPL)
Period	Volume Bbls/d	Price $/Bbl		Volume MMBtu/d	Price $/MMBtu
4Q15	10,800	$	89.81	20,000	$	4.13
1Q16	7,300	81.65		5,000	4.10
2Q16	7,300	81.65		5,000	4.10
3Q16	6,250	79.11		5,000	4.10
4Q16	6,250	79.11		5,000	4.10
1Q17	2,250	73.88		—	—
2Q17	2,250	73.88		—	—
3Q17	1,500	78.16		—	—
4Q17	1,500	78.16		—	—

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

UPCOMING EVENTS

Third Quarter Conference Call and Webcast

The Company plans to host a conference call on Friday, November 6, 2015, to discuss the results and management's outlook for the future (not part of this earnings release). The call is scheduled at 10:00 a.m. Eastern time (8:00 a.m. Mountain time). 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 63826020. The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through November 13, 2015 at 855-859-2056 (404-537-3406 international) with passcode 63826020.

DISCLOSURE STATEMENTS

Forward-Looking Statements

All statements in this press release, other than statements of historical fact, may be deemed to be 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. Words such as expects, forecast, guidance, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein; however, these are not the exclusive means of identifying 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 fourth quarter of 2015. Additional forward-looking statements in this release relate to, among other things, the closing of, and proceeds from the planned asset sales and future capital expenditures, projects and opportunities.

These and other forward-looking statements in this press release are based on management's judgment as of the date of this release 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 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; unexpected obstacles to closing anticipated transactions or unfavorable purchase price adjustments; 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.

BILL BARRETT CORPORATION

Selected Operating Highlights

(Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014 (1)		2015		2014 (1)
Production Data:
Oil (MBbls)	1,066		1,107		3,311		3,056
Natural gas (MMcf)	2,214		6,834		5,772		19,950
NGLs (MBbls)	264		408		635		1,330
Combined volumes (MBoe)	1,699		2,654		4,908		7,711
Daily combined volumes (Boe/d)	18,467		28,848		17,978		28,245

Average Sales Prices (before the effects of realized hedges):
Oil (per Bbl)	$	38.71	$	82.83	$	41.54	$	84.04
Natural gas (per Mcf)	2.08		4.24		2.31		4.83
NGLs (per Bbl)	11.17		32.65		12.24		32.80
Combined (per Boe)	28.73		50.48		32.33		51.47

Average Realized Sales Prices (after the effects of realized hedges):
Oil (per Bbl)	$	79.15	$	79.98	$	77.93	$	79.52
Natural gas (per Mcf)	3.36		4.27		3.76		4.50
NGLs (per Bbl)	11.17		33.19		12.24		32.61
Combined (per Boe)	55.77		49.46		58.58		48.78

Average Costs (per Boe):
Lease operating expenses	$	5.67	$	6.14	$	7.10	$	6.27
Gathering, transportation and processing expense	0.40		4.06		0.52		4.44
Production tax expenses	2.16		3.95		2.04		3.60
Depreciation, depletion and amortization	32.22		26.01		32.53		24.57
General and administrative expense, excluding long-term incentive compensation expense ⁽²⁾	5.31		2.86		6.36		4.07


(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.

BILL BARRETT CORPORATION

Consolidated Condensed Balance Sheets

(Unaudited)



	As of September 30,		As of December 31,
	2015		2014
	(in thousands)
Assets:
Cash and cash equivalents	$	92,836	$	165,904
Short-term investments	19,992		—
Other current assets ⁽¹⁾	157,312		260,201
Property and equipment, net	1,238,947		1,753,121
Other noncurrent assets ⁽¹⁾	87,173		65,258
Total assets	$	1,596,260	$	2,244,484

Liabilities and Stockholders' Equity:
Current liabilities, other	$	199,635	$	239,343
Current liabilities, convertible senior notes	579		25,344
Capitalized lease obligation	2,894		3,222
Senior notes	800,000		800,000
Other long-term liabilities	25,386		147,087
Stockholders' equity	567,766		1,029,488
Total liabilities and stockholders' equity	$	1,596,260	$	2,244,484


(1)	At September 30, 2015, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $142.1 million, comprised of $109.9 million of current assets and $32.2 million of non-current assets. This amount will fluctuate based on estimated future commodity prices and the current hedge position.

BILL BARRETT CORPORATION

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except per share amounts)
Operating and Other Revenues:
Oil, gas and NGLs ⁽¹⁾	$	48,799		$	134,342		$	158,667		$	397,731
Other	880			921			2,664			7,658
Total operating and other revenues	49,679			135,263			161,331			405,389
Operating Expenses:
Lease operating	9,638			16,284			34,834			48,367
Gathering, transportation and processing	684			10,784			2,559			34,238
Production tax	3,670			10,495			10,020			27,770
Exploration	20			23			145			442
Impairment, dry hole costs and abandonment	572,651			29,109			574,996			32,613
(Gain) Loss on divestitures	(77		)	99,466			(759		)	96,896
Depreciation, depletion and amortization	54,738			69,024			159,666			189,426
Unused commitments	4,388			—			13,163			—
General and administrative ⁽²⁾	9,018			7,591			31,200			31,408
Long-term incentive compensation ⁽²⁾	2,007			3,520			7,826			9,631
Total operating expenses	656,737			246,296			833,650			470,791
Operating Income (Loss)	(607,058		)	(111,033		)	(672,319		)	(65,402		)
Other Income and Expense:
Interest and other income	100			264			519			991
Interest expense	(15,754		)	(18,033		)	(49,574		)	(53,285		)
Commodity derivative gain (loss) ⁽¹⁾	69,133			72,299			75,914			369
Gain (loss) on extinguishment of debt	—			—			1,749			—
Total other income and expense	53,479			54,530			28,608			(51,925		)
Income (Loss) before Income Taxes	(553,579		)	(56,503		)	(643,711		)	(117,327		)
(Provision for) Benefit from Income Taxes	143,265			21,854			177,085			43,343
Net Income (Loss)	$	(410,314	)	$	(34,649	)	$	(466,626	)	$	(73,984	)

Net Income (Loss) per Common Share
Basic	$	(8.49	)	$	(0.72	)	$	(9.67	)	$	(1.54	)
Diluted	$	(8.49	)	$	(0.72	)	$	(9.67	)	$	(1.54	)
Weighted Average Common Shares Outstanding
Basic	48,340			48,060			48,280			47,983
Diluted	48,340			48,060			48,280			47,983


(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 September 30,					Nine Months Ended September 30,
	2015		2014			2015			2014
	(in thousands)
Included in oil, gas and NGL production revenue:
Certain realized gains on hedges	$	—	$	351		$	—		$	889
Included in commodity derivative gain (loss):
Realized gain (loss) on derivatives not designated as cash flow hedges	$	45,936	$	(3,054	)	$	128,834		$	(21,580	)
Unrealized gain (loss) on derivatives not designated as cash flow hedges	23,197		75,353			(52,920		)	21,949
Total commodity derivative gain (loss)	$	69,133	$	72,299		$	75,914		$	369

(2)

BILL BARRETT CORPORATION

Consolidated Statements of Cash Flows

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands)
Operating Activities:
Net income (loss)	$	(410,314	)	$	(34,649	)	$	(466,626	)	$	(73,984	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	54,738			69,024			159,666			189,426
Impairment, dry hole costs and abandonment expense	572,651			29,109			574,996			32,613
Unrealized derivative (gain) loss, non-cash flow hedges	(23,197		)	(75,353		)	52,920			(21,949		)
Deferred income tax benefit	(142,977		)	(22,073		)	(176,797		)	(43,604		)
Incentive compensation and other non-cash charges	2,068			3,496			7,281			9,651
Amortization of debt discounts and deferred financing costs	633			1,068			3,983			3,200
(Gain) loss on sale of properties	(77		)	99,466			(759		)	96,896
(Gain) loss on extinguishment of debt	—			—			(1,749		)	—
Change in operating assets and liabilities:
Accounts receivable	3,285			3,326			20,394			9,025
Prepayments and other assets	878			(154		)	(261		)	914
Accounts payable, accrued and other liabilities	18,025			23,518			4,347			20,723
Amounts payable to oil and gas property owners	(4,161		)	—			(850		)	1,936
Production taxes payable	3,208			7,106			(10,644		)	6,455
Net cash provided by (used in) operating activities	$	74,760		$	103,884		$	165,901		$	231,302
Investing Activities:
Additions to oil and gas properties, including acquisitions	(61,936		)	(161,633		)	(256,059		)	(425,978		)
Additions of furniture, equipment and other	(158		)	(1,254		)	(1,036		)	(2,110		)
Proceeds from sale of properties and other investing activities	99			549,572			66,617			557,747
Proceeds from the sale of short-term investments	45,000			—			95,000			—
Cash paid for short-term investments	—			—			(114,883		)	—
Net cash provided by (used in) investing activities	$	(16,995	)	$	386,685		$	(210,361	)	$	129,659
Financing Activities:
Proceeds from debt	—			30,000			—			165,000
Principal payments on debt	(107		)	(281,157		)	(25,083		)	(283,442		)
Deferred financing costs and other	(704		)	(413		)	(3,525		)	(2,462		)
Proceeds from stock option exercises	—			—			—			126
Net cash provided by (used in) financing activities	$	(811	)	$	(251,570	)	$	(28,608	)	$	(120,778	)
Increase (Decrease) in Cash and Cash Equivalents	56,954			238,999			(73,068		)	240,183
Beginning Cash and Cash Equivalents	35,882			55,779			165,904			54,595
Ending Cash and Cash Equivalents	$	92,836		$	294,778		$	92,836		$	294,778

BILL BARRETT CORPORATION

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

(Unaudited)

Discretionary Cash Flow Reconciliation



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except per share amounts)
Net Income (Loss)	$	(410,314	)	$	(34,649	)	$	(466,626	)	$	(73,984	)
Adjustments to reconcile to discretionary cash flow:
Depreciation, depletion and amortization	54,738			69,024			159,666			189,426
Impairment, dry hole and abandonment expense	572,651			29,109			574,996			32,613
Exploration expense	20			23			145			442
Unrealized derivative (gain) loss, non-cash flow hedges	(23,197		)	(75,353		)	52,920			(21,949		)
Deferred income taxes	(142,977		)	(22,073		)	(176,797		)	(43,604		)
Stock compensation and other non-cash charges	2,068			3,496			7,281			9,651
Amortization of debt discounts and deferred financing costs	633			1,068			3,983			3,200
(Gain) loss on sale of properties	(77		)	99,466			(759		)	96,896
(Gain) loss on extinguishment of debt	—			—			(1,749		)	—
Discretionary Cash Flow	$	53,545		$	70,111		$	153,060		$	192,691
Per share, diluted	$	1.11		$	1.46		$	3.17		$	4.02
Per Boe	$	31.52		$	26.42		$	31.19		$	24.99

Adjusted Net Income (Loss) Reconciliation



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except per share amounts)
Net Income (Loss)	$	(410,314	)	$	(34,649	)	$	(466,626	)	$	(73,984	)
Adjustments to net income (loss):
Unrealized derivative (gain) loss, non-cash flow hedges	(23,197		)	(75,353		)	52,920			(21,949		)
Impairment expense	571,863			26,743			572,366			28,121
(Gain) loss on sale of properties	(77		)	99,466			(759		)	96,896
(Gain) loss on extinguishment of debt	—			—			(1,749		)	—
One-time items:
West Tavaputs NGL processing true-up	—			—			(1,005		)	(5,677		)
Expenses (credit) relating to compressor station fire	—			—			—			(570		)
Expenses relating to amending credit facility	—			—			1,617			—
Subtotal adjustments	548,589			50,856			623,390			96,821
Effective tax rate	26		%	38		%	28		%	38		%
Tax effected adjustments	405,956			31,531			448,841			60,029
Adjusted Net Income (Loss)	$	(4,358	)	$	(3,118	)	$	(17,785	)	$	(13,955	)
Per share, diluted	$	(0.09	)	$	(0.06	)	$	(0.37	)	$	(0.29	)

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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