Bill Barrett Corporation Reports Second Quarter 2015 Results - Production Volume of 1.6 MMBoe Exceeds Guidance and 2015 Produ...

DENVER, Aug. 6, 2015 /PRNewswire/ -- Bill Barrett Corporation (the "Company") (NYSE: BBG) reports second quarter of 2015 results, including these highlights:

• Sales volumes grew to 1.6 MMBoe, exceeding guidance by 9% due to solid execution of the DJ Basin drilling program
• Increased DJ Basin production by 76% year-over-year and 8% sequentially
• Increasing full-year 2015 production guidance to 6.1-6.5 MMBoe, represents 23% growth over 2014 utilizing the mid-point of the guidance range
• Generated $1.06 per share discretionary cash flow
• Maintain strong liquidity of $450 million with zero drawn on credit facility and cash and short-term investments of $101 million 

Chief Executive Officer and President Scot Woodall commented, "I am pleased with the results of the second quarter as we executed on all phases of our strategic plan and delivered very solid results.  Our entire organization is focused on achieving our operational objectives and this can be seen in second quarter production volumes that exceeded our forecast by 9%. Importantly, DJ Basin and Uinta Oil Program ("UOP") production for the first half of 2015 surpassed our initial forecasted guidance by over 10% and was 35% higher compared 2014. Our excellent performance through the first half of the year allows us to increase full year 2015 production guidance for the third time, which at the mid-point represents 23% growth over 2014, excluding asset sales, and is 11% greater than the mid-point of our initial forecasted guidance. Our drilling results continue to reflect the quality of our DJ Basin assets and positions us to achieve our goals for the remainder of the year while providing a strong foundation heading into 2016.    

"We are encouraged by the early production data we are seeing from our extended reach lateral ("XRL") program and our preferred completion technique¹ is proving to be the most effective and efficient method to develop our asset as evidenced by the improving production data we are reporting. We continue implementing technological refinements and enhancements to our drilling and completion process in an effort to optimize well results and further enhance operational efficiencies to improve economic returns. Specifically, we are making significant strides in increasing drilling efficiency as we have reduced recent XRL well drilling days by approximately 40% compared to earlier XRL program wells. Our core Northeast ("NE") Wattenberg acreage provides a competitive advantage as more than 80% of our acreage is expected to be developed with XRL wells that we project provide acceptable rates of return at the current commodity price strip.

"We maintain a strong financial position in the challenging macro-economic environment that we are presently navigating. We enter the second half of the year with an undrawn revolving credit facility and $101 million in cash and short-term investments that provide ample liquidity. In addition, approximately 80% of our expected second half of 2015 production volumes and approximately 40% of 2016 production volumes are hedged at very favorable commodity prices.  We remain capital disciplined, financially responsible and operationally flexible as we preserve the strength of our balance sheet."

SECOND QUARTER 2015 OPERATING AND FINANCIAL RESULTS
(Prior year period results are pro forma for assets sold.)

The Company realized substantial growth in production from its core DJ Basin asset, driven by strong NE Wattenberg XRL well results that offset a production decline from the UOP. Oil, natural gas and natural gas liquids ("NGL") production from the DJ Basin and UOP totaled 1.6 million barrels of oil equivalent ("MMBoe") in the second quarter of 2015 compared with 1.3 MMBoe in the second quarter of 2014. DJ Basin production grew 76% while UOP production was down 21%. The decline in UOP production was primarily due to a decrease in drilling and workover activity, as the Company is focusing the majority of its 2015 capital program on its higher-return DJ Basin assets. NGL production was greater compared to the first quarter of 2015 and second quarter of 2014 due to greater processing yields. Second quarter of 2015 production was 69% oil, 18% natural gas and 13% NGLs.   

		Three Months Ended June 30,				Three Months Ended March 31,
		2015	2014	Change		2015	Change
Production Data:
	Oil (MBbls)	1,120	858	31%		1,125	0%
	Natural gas (MMcf)	1,800	1,650	9%		1,764	2%
	NGLs (MBbls)	208	132	58%		162	28%
	Combined volumes (MBoe)	1,628	1,265	29%		1,581	3%
	Daily combined volumes (Boe/d)	17,890	13,901	29%		17,567	2%

 

Pre-hedge commodity prices were down significantly compared with 2014. For the second quarter of 2015, approximately 92% of oil production and 96% of natural gas production benefited from commodity derivative swaps that averaged $90.39 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 June 30,				Three Months Ended March 31,
		2015 Pre- hedge	2015 Including hedge	2014 Pre- hedge		2015 Pre- hedge	2015 Including hedge
Average Sales Prices:
	Oil (per Bbl)	$ 48.68	$ 78.44	$ 85.76		$ 37.12	$ 76.28
	Natural gas (per Mcf)	2.33	4.10	4.86		2.60	3.92
	NGLs (per Bbl)	12.76	12.76	23.91		13.31	13.31
	Combined (per Boe)	37.70	60.13	67.05		30.68	60.01

 

Cash operating costs (lease operating expense, gathering, transportation and processing costs and production tax expense) were $9.92 per Boe in the second quarter of 2015, down 9% compared to the first quarter of 2015.  This was primarily a result of increased efficiencies, lease operating cost reductions across both basins, and the Company's decision to proactively reduce workover activity in the UOP and to shut-in certain UOP wells in the current commodity price environment due to higher operating costs. The DJ Basin has lower per unit lease operating costs than the UOP and averaged $5.84 per Boe in the second quarter of 2015. Production tax expense for the second quarter of 2015 averaged 6.2% of pre-hedge revenue. Normalized production taxes are expected to approximate 8% of pre-hedge revenue for the remainder of the year.

		Three Months Ended June 30,				Three Months Ended March 31,
		2015	2014	Change		2015	Change
Average Costs (per Boe):
	Leasing operating expenses	$  7.01	$ 8.13	-14%		$  8.72	-20%
	Gathering, transportation and processing expense	0.57	1.18	-52%		0.60	-5%
	Production tax expenses	2.34	5.23	-55%		1.60	46%
	Depreciation, depletion and amortization	32.36	33.40	-3%		33.05	-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 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 second quarter of 2015 was $51.4 million, or $1.06 per share, down from $67.3 million, or $1.40 per share, in the second quarter of 2014. Discretionary cash flow in the second quarter of 2015 compared to 2014 was impacted by lower revenues due to a 38% decline in production volumes as a result of asset sales.

Net loss for the second quarter of 2015 was ($44.6) million, or ($0.92) per share, compared with the second quarter of 2014 at ($26.6) million, or ($0.55) per share. Adjusted net loss was ($4.0) million, or ($0.08) per share, in the second quarter of 2015 compared with ($8.6) million, or ($0.18) per share, in the second 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 June 30,
	2015	2014
Discretionary Cash Flow ($ millions)	$  51.4	$  67.3
Discretionary Cash Flow per share	1.06	1.40
Adjusted Net Loss ($ millions)	(4.0)	(8.6)
Adjusted Net Loss per share	(0.08)	(0.18)

Debt & Liquidity

At June 30, 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. The principal balance of long-term debt was $803.0 million and cash and short-term investments were $100.8 million, resulting in net debt (principal balance of debt outstanding less the cash and investment balance) of $702.2 million. Liquidity was $449.8 million.

In addition, as of August 6, 2015, the Company has not issued any shares under its previously announced "at-the-market" equity offering program.

Capital Expenditures

Capital expenditures ("Capex") for the second quarter of 2015 were $65.1 million, which was 19% below guidance of $80 million primarily due to the timing of drilling and completion activities in the DJ Basin. Capex included 13 gross/9 net wells in the DJ Basin, of which, 7 gross/7 net were XRL wells operated by the Company. In the second quarter, 10 gross/9 net XRL wells began initial flowback operations and were placed on sales.  These wells are expected to reach peak initial production in the fourth quarter of 2015. Capital expenditures included $59.6 million for drilling, $1.8 million for leaseholds, and $3.7 million for infrastructure and corporate assets.

Basin Summary

		Three Months Ended June 30, 2015				Six Months Ended June 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	12,527	9	$   58.9		12,105	22	$  158.6
	Uinta	5,330	2	6.2		5,503	4	19.1
	Other(2)	33	0	0		121	0	1.8
		17,890	11	$ 65.1		17,729	26	$  179.5

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

 

OPERATIONAL HIGHLIGHTS

DJ Basin

Second quarter DJ Basin highlights include:

• Produced an average of 12,527 Boe/d, up 76% from the second quarter of 2014 and up 8% sequentially.
• Drilled 7 gross/7 net operated XRL wells.
• Increased operational efficiency by reducing the number of drilling days for the most recent seven XRL wells by 40%. The most recent pad averaged 10 days per well, including a best-in-class well drilled in 8 days.
• Maintained cost discipline as contracted NE Wattenberg XRL drilling and completion costs of $6.25 million are approximately 25% lower compared to wells drilled in the fourth quarter of 2014.
• Placed 10 gross/9 net XRL wells on initial sales with 30-day peak initial production ("IP") rates (see Disclosure section below) expected to be reached in the fourth quarter of 2015. Subsequent to the end of the quarter, an additional 4 gross/4 net XRL wells were placed on initial sales in July 2015.
• Continued implementing and improving preferred completion technology and mechanics for XRL wells that includes a combination of plug-and-perf stimulation, approximately 1,000 pounds of proppant per foot, 55-stage completions and controlled flowback, yielding improved early well performance and a shallower initial production decline compared to prior completion practices.
• The four initial XRL wells utilizing the preferred completion technology had an average 30-day peak IP rate of 649 Boe/d, a 60-day average IP rate of 615 Boe/d and a 90-day average IP rate of 580 Boe/d.

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 has been significantly reduced to only include several 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 cost efficiencies, and 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 UOP wells in the current commodity price environment.

2015 OPERATING GUIDANCE

The Company's 2015 plan is expected to result in approximately 23% pro forma production growth from core assets at the mid-point of guidance, with approximately 25% growth in oil volumes. The Company anticipates drilling 35-40 gross (28-32 net) wells in the NE Wattenberg area during 2015, most of which are XRL wells, and to participate in approximately 5 net non-operated DJ Basin wells.

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

• Capital expenditures of $320-$350 million, unchanged.
  • Includes the addition of a second drilling rig in NE Wattenberg that began operating in June 2015.
  • The level of capital expenditures between the third and the fourth quarter of 2015 will depend on the timing of completion activities that are scheduled to begin in the third quarter of 2015.
• Production of 6.1-6.5 MMBoe, increased from 6.0-6.4 MMBoe. 
  • The mid-point of guidance represents 23% annual production growth over 2014, pro forma for asset sales, and is 11% greater than initial forecasted guidance.
  • The increase is primarily due to continued strong well performance from the DJ Basin drilling program.
  • Production is expected to be approximately 70% oil, 20% natural gas and 10% NGLs.
  • Third quarter 2015 production is expected to be approximately 1.5 MMBoe. 

COMMODITY HEDGES UPDATE

Generally, it is the Company's strategy to hedge 50%-70% of production on a forward 12-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 Company has hedges in place for approximately 80% of its remaining forecasted 2015 production. 

The following table summarizes hedge positions as of August 6, 2015:

	Oil (WTI)			Natural Gas (NWPL)
Period	Volume Bbls/d	Price $/Bbl		Volume MMBtu/d	Price $/MMBtu
3Q15	10,800	89.81		20,000	4.13
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

Second Quarter Conference Call and Webcast

The Company plans to host a conference call on Friday, August 7, 2015, to discuss 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 80924651. The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through August 14, 2015 at 855-859-2056 (404-537-3406 international) with passcode 80924651.

DISCLOSURE STATEMENTS

Well Performance

The calculation of 30-day IP rates averages the daily production for the 30 days following the date upon which the Company determines the well has achieved peak production.  This date may occur several days or weeks after oil production commences. 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 reported by the Company.

Forward-Looking Statements

All statements in this press release, other than historical financial information, 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 third quarter of 2015.

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; 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			Six Months Ended
				June 30,			June 30,
				2015	2014 (1)		2015	2014 (1)
Production Data:
	Oil (MBbls)			1,120	1,026		2,245	1,948
	Natural gas (MMcf)			1,800	6,696		3,558	13,116
	NGLs (MBbls)			208	480		371	922
	Combined volumes (MBoe)			1,628	2,622		3,209	5,056
	Daily combined volumes (Boe/d)			17,890	28,813		17,729	27,934
Average Sales Prices (before the effects of realized hedges):
	Oil (per Bbl)			$ 48.68	$ 86.64		$ 42.89	$ 84.73
	Natural gas (per Mcf)			2.33	4.74		2.46	5.14
	NGLs (per Bbl)			12.76	31.64		13.00	32.87
	Combined (per Boe)			37.70	51.80		34.24	51.98
Average Realized Sales Prices (after the effects of realized hedges):
	Oil (per Bbl)			$ 78.44	$ 79.69		$ 77.35	$ 79.26
	Natural gas (per Mcf)			4.10	4.46		4.01	4.62
	NGLs (per Bbl)			12.76	31.75		13.00	32.35
	Combined (per Boe)			60.13	48.39		60.07	48.43
Average Costs (per Boe):
	Lease operating expense			$   7.01	$   6.07		$   7.85	$   6.35
	Gathering, transportation and processing expense			0.57	4.48		0.58	4.64
	Production tax expense			2.34	3.68		1.98	3.42
	Depreciation, depletion and amortization			32.36	24.75		32.70	23.81
	General and administrative expense, excluding long-term incentive compensation expense		(2)	7.31	4.58		6.91	4.71

(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		As of
						June 30, 2015		December 31, 2014
(in thousands)
Assets:
	Cash and cash equivalents					$                          35,882		$                        165,904
	Short-term investments					64,963		-
	Other current assets				(1)	142,602		260,201
	Property and equipment, net					1,802,869		1,753,121
	Other noncurrent assets				(1)	41,385		65,258
		Total assets				$                    2,087,701		$                    2,244,484
Liabilities and Stockholders' Equity:
	Current liabilities, other					$                        174,836		$                        239,343
	Current liabilities, convertible senior notes					579		25,344
	Capitalized lease obligation					3,004		3,222
	Senior notes					800,000		800,000
	Other long-term liabilities					133,287		147,087
	Stockholders' equity					975,995		1,029,488
		Total liabilities and stockholders' equity				$                    2,087,701		$                    2,244,484

(1)	At June 30, 2015, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $118.9 million, comprised of $90.9 million of current assets and $28.0 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				Six Months Ended
					June 30,				June 30,
					2015		2014		2015		2014
(in thousands, except per share amounts)
Operating and Other Revenues:
	Oil, gas and NGLs			(1)	$  61,382		$ 136,220		$ 109,868		$ 263,389
	Other				1,236		8,788		1,784		9,307
	Total operating and other revenues				62,618		145,008		111,652		272,696
Operating Expenses:
	Lease operating				11,405		15,919		25,196		32,083
	Gathering, transportation and processing				933		11,750		1,875		23,454
	Production tax				3,816		9,651		6,350		17,275
	Exploration				92		116		125		419
	Impairment, dry hole costs and abandonment				1,090		1,743		2,345		3,504
	(Gain) Loss on divestitures				(644)		-		(682)		-
	Depreciation, depletion and amortization				52,674		64,894		104,928		120,402
	Unused commitments				4,387		-		8,775		-
	General and administrative			(2)	11,903		11,998		22,182		23,817
	Long-term incentive compensation			(2)	2,769		2,523		5,819		6,111
	Total operating expenses				88,425		118,594		176,913		227,065
Operating Income (Loss)					(25,807)		26,414		(65,261)		45,631
Other Income and Expense:
	Interest and other income				144		352		419		727
	Interest expense				(17,390)		(17,821)		(33,820)		(35,252)
	Commodity derivative gain (loss)			(1)	(27,657)		(46,775)		6,781		(71,930)
	Gain (loss) on extinguishment of debt				(818)		-		1,749		-
	Total other income and expense				(45,721)		(64,244)		(24,871)		(106,455)
Income (Loss) before Income Taxes					(71,528)		(37,830)		(90,132)		(60,824)
Benefit from Income Taxes					26,947		11,244		33,820		21,489
Net Income (Loss)					$ (44,581)		$  (26,586)		$  (56,312)		$  (39,335)
Net Income (Loss) Per Common Share
	Basic				$     (0.92)		$      (0.55)		$      (1.17)		$      (0.82)
	Diluted				$     (0.92)		$      (0.55)		$      (1.17)		$      (0.82)
Weighted Average Common Shares Outstanding
	Basic				48,299		47,997		48,249		47,944
	Diluted				48,299		47,997		48,249		47,944
(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 June 30,				Six Months Ended June 30,
					2015		2014		2015		2014
	Included in oil, gas and NGL production revenue:
	Certain realized gains on hedges				$              -		$          382		$               -		$          538
	Included in commodity derivative gain (loss):
	Realized gain (loss) on derivatives not designated as cash flow hedges				$    36,523		$      (9,326)		$     82,898		$    (18,526)
	Unrealized loss on derivatives not designated as cash flow hedges				(64,180)		(37,449)		(76,117)		(53,404)
	Total commodity derivative gain (loss)				$   (27,657)		$    (46,775)		$       6,781		$    (71,930)
(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 Statements of Cash Flows
(Unaudited)
					Three Months Ended				Six Months Ended
					June 30,				June 30,
					2015		2014		2015		2014
(in thousands)
Operating Activities:
	Net income (loss)				$ (44,581)		$   (26,586)		$   (56,312)		$   (39,335)
	Adjustments to reconcile to net cash
	provided by operations:
		Depreciation, depletion and amortization			52,674		64,894		104,928		120,402
		Impairment, dry hole costs and abandonment expense			1,090		1,743		2,345		3,504
		Unrealized derivative (gain) loss, non-cash flow hedges			64,180		37,449		76,117		53,404
		Deferred income tax benefit			(26,947)		(11,286)		(33,820)		(21,531)
		Incentive compensation and other non-cash charges			2,470		2,463		5,213		6,155
		Amortization of debt discounts and deferred financing costs			2,283		1,065		3,350		2,132
		(Gain) loss on sale of properties			(644)		(2,570)		(682)		(2,570)
		(Gain) loss on extinguishment of debt			818		-		(1,749)		-
		Change in assets and liabilities:
			Accounts receivable		8,045		169		17,109		5,699
			Prepayments and other assets		225		660		(1,139)		1,068
			Accounts payable, accrued and other liabilities		(12,017)		(8,929)		(13,678)		(2,795)
			Amounts payable to oil & gas property owners		(3,527)		(7,465)		3,311		1,936
			Production taxes payable		(6,753)		617		(13,852)		(651)
		Net cash provided by operating activities			$  37,316		$     52,224		$     91,141		$  127,418
Investing Activities:
	Additions to oil and gas properties, including acquisitions				(83,114)		(135,407)		(194,123)		(264,345)
	Additions of furniture, equipment and other				(269)		(582)		(878)		(856)
	Proceeds from sale of properties and other investing activities				103		8,563		66,518		8,175
	Proceeds from the sale of short-term investments				50,000		-		50,000		-
	Cash paid for short term investments				-		-		(114,883)		-
		Net cash used in investing activities			$ (33,280)		$ (127,426)		$ (193,366)		$ (257,026)
Financing Activities:
	Proceeds from debt				-		70,000		-		135,000
	Principal payments on debt				(105)		(1,148)		(24,976)		(2,285)
	Deferred financing costs and other				(1,821)		(103)		(2,821)		(2,049)
	Proceeds from stock option exercises				-		-		-		126
		Net cash provided by (used in) financing activities			$   (1,926)		$     68,749		$   (27,797)		$  130,792
Increase (Decrease) in Cash and Cash Equivalents					2,110		(6,453)		(130,022)		1,184
Beginning Cash and Cash Equivalents					33,772		62,232		165,904		54,595
Ending Cash and Cash Equivalents					$  35,882		$     55,779		$     35,882		$     55,779

 

BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income (Loss)
(Unaudited)
Discretionary Cash Flow Reconciliation
						Three Months Ended				Six Months Ended
						June 30,				June 30,
						2015		2014		2015		2014
(in thousands, except per share amounts)
Net Income (Loss)						$ (44,581)		$ (26,586)		$ (56,312)		$ (39,335)
Adjustments to reconcile to discretionary cash flow:
	Depreciation, depletion and amortization					52,674		64,894		104,928		120,402
	Impairment, dry hole and abandonment expense					1,090		1,743		2,345		3,504
	Exploration expense					92		116		125		419
	Unrealized derivative loss, non-cash flow hedges					64,180		37,449		76,117		53,404
	Deferred income taxes					(26,947)		(11,286)		(33,820)		(21,531)
	Stock compensation and other non-cash charges					2,470		2,463		5,213		6,155
	Amortization of debt discounts and deferred financing costs					2,283		1,065		3,350		2,132
	(Gain) loss on sale of properties					(644)		(2,570)		(682)		(2,570)
	(Gain) loss on extinguishment of debt					818		-		(1,749)		-
Discretionary Cash Flow						$ 51,435		$ 67,288		$ 99,515		$ 122,580
	Per share, diluted					$       1.06		$       1.40		$       2.06		$        2.56
	Per Boe					$     31.59		$     25.66		$     31.01		$      24.24
Adjusted Net Income (Loss) Reconciliation
						Three Months Ended				Six Months Ended
						June 30,				June 30,
						2015		2014		2015		2014
(in thousands except per share amounts)
Net Loss						$ (44,581)		$ (26,586)		$ (56,312)		$ (39,335)
Adjustments to net loss:
	Unrealized derivative loss, non-cash flow hedges					64,180		37,449		76,117		53,404
	Impairment expense					445		340		503		1,378
	(Gain) loss on sale of properties					(644)		(2,570)		(682)		(2,570)
	(Gain) loss on extinguishment of debt					818		-		(1,749)		-
	One-time items:
		West Tavaputs NGL processing true-up				(1,005)		(5,677)		(1,005)		(5,677)
			Expenses (credit) relating to compressor station fire			-		(570)		-		(570)
			Expenses related to amending credit facility			1,617		-		1,617		-
	Subtotal adjustments					65,411		28,972		74,801		45,965
	Statutory tax rate					38%		38%		38%		38%
	Tax effected adjustments					40,555		17,963		46,377		28,498
Adjusted Net Loss						$ (4,026)		$ (8,623)		$ (9,935)		$ (10,837)
	Per share, diluted					$     (0.08)		$     (0.18)		$     (0.21)		$      (0.23)
	Per Boe					$     (2.47)		$     (3.29)		$     (3.10)		$      (2.14)

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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