Bill Barrett Corporation Reports First Quarter 2016 Financial and Operating Results

DENVER, May 5, 2016 /PRNewswire/ -- Bill Barrett Corporation (the "Company") BBG reports first quarter of 2016 financial and operating results, including these highlights:

Production sales volumes of 1.4 MMBoe (65% oil), at the high-end of first quarter guidance range
Capital expenditures of $46 million, 20% below the mid-point of the first quarter guidance range
2016 capital expenditures reduced to $90-$135 million from $100-$150 million as a result of lower well costs
Reported discretionary cash flow of $0.50 per share and EBITDAX of $39 million
Affirmed borrowing base at $335 million with no change to terms or conditions
Exited the first quarter of 2016 with $106 million of cash and an undrawn credit facility
Executed agreement to divest a portion of Uinta Basin assets for approximately $30 million

Chief Executive Officer and President Scot Woodall commented, "Our team continues to execute and we posted another solid quarter of operational and financial results. The positive results were due in part to production coming in at the upper end of our guidance range, tightening oil differentials, and a 26% year-over-year decrease in per unit LOE. In addition, G&A expense declined 17% compared to the first quarter of 2015. We continue to maintain a capital disciplined approach as first quarter spending was 20% below the mid-point of our guidance range as we captured further XRL well cost savings. This gives us the confidence to lower our full-year 2016 capital expenditure guidance, while reaffirming our production guidance. The second quarter is off to a good start and we continue to be encouraged by the results of our XRL development program and the associated contribution to our increasing production profile this year. We are in the process of completing and placing on initial flowback the remainder of the wells that have been drilled. Our balance sheet remains strong as we ended the quarter with a cash position of $106 million, an undrawn credit facility, and a favorable hedge position which provides ample liquidity. The Uinta Basin non-core asset sale will further bolster our balance sheet by increasing our cash position."

OPERATING AND FINANCIAL RESULTS

Discretionary cash flow, adjusted net income (loss) and EBITDAX are non-GAAP (Generally Accepted Accounting Principles) measures. Please reference the reconciliations to GAAP financial statements at the end of this release.

Discretionary cash flow in the first quarter of 2016 was $24.4 million, or $0.50 per share, compared to $48.1 million, or $1.00 per share, in the first quarter of 2015. Discretionary cash flow in the first quarter of 2016 compared to 2015 was impacted by lower revenues due to a 14% decline in production volumes as a result of asset sales and a 17% decline in realized oil prices including hedges.

Adjusted net loss for the first quarter of 2016 was $13.7 million, or $0.28 per share, compared with adjusted net loss for the first quarter of 2015 of $5.9 million, or $0.12 per share. 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.

EBITDAX was $39.4 million for the first quarter of 2016 compared to $63.2 million for the first quarter of 2015. Lower EBITDAX is primarily a result of lower commodity prices and a decline in production volumes as a result of asset sales, as discussed above.

	Three Months Ended March 31,
	2016		2015
Discretionary Cash Flow ($ millions)	$	24.4	$	48.1
Discretionary Cash Flow per share	0.50		1.00
Adjusted Net Loss ($ millions)	(13.7)		(5.9)
Adjusted Net Loss per share	(0.28)		(0.12)
EBITDAX ($ millions)	39.4		63.2

Oil, natural gas and natural gas liquids ("NGL") production from the Denver-Julesburg ("DJ") Basin and Uinta Oil Program ("UOP") totaled 1.4 million barrels of oil equivalent ("MMBoe") in the first quarter of 2016, which was at the high-end of the Company's guidance range of 1.3-1.4 MMBoe. Lower production sales volumes to the comparable 2015 period were primarily the result of non-core asset sales in the DJ Basin and UOP that were completed during 2015.

First quarter of 2016 production was 65% oil, 20% natural gas and 15% NGLs, which was consistent with guidance.

	Three Months Ended March 31,			Three Months Ended December 31,
	2016	2015	Change	2015	Change
Production Sales Data:
Oil (MBbls)	886	1,125	(21)%	1,090	(19)%
Natural gas (MMcf)	1,626	1,764	(8)%	1,986	(18)%
NGLs (MBbls)	210	162	30%	264	(20)%
Combined volumes (MBoe)	1,367	1,581	(14)%	1,685	(19)%
Daily combined volumes (Boe/d)	15,022	17,567	(14)%	18,315	(18)%

Cash operating costs (lease operating expense ("LOE"), gathering, transportation and processing costs and production tax expense) were $6.81 per Boe in the first quarter of 2016 compared to $6.54 per Boe in the fourth quarter of 2015 and $10.92 per Boe in the first quarter of 2015. Higher cash operating costs on a per unit basis compared to the fourth quarter of 2015 were primarily a result of lower production sales volumes due to asset sales and higher seasonal operating costs during the first quarter of 2016. Cash operating costs were lower compared to the first quarter of 2015 primarily as a result of improved operational efficiencies and lease operating cost reductions in both the DJ Basin and the UOP.

The decrease in production tax expense in the first quarter of 2016 is related to an annual adjustment of Colorado ad valorem tax based on actual assessments and of the related Colorado severance tax credit adjustment based on the annual severance tax calculation. Normalized production taxes are expected to approximate 9% of pre-hedge revenue for the remainder of 2016.

	Three Months Ended March 31,					Three Months Ended December 31,
	2016		2015		Change	2015		Change
Average Costs (per Boe):
Lease operating expenses	$	6.46	$	8.72	(26)%	$	4.70	37%
Gathering, transportation and processing expense	0.58		0.60		(3)%	0.55		5%
Production tax expenses	(0.23)		1.60		(114)%	1.29		(118)%
Depreciation, depletion and amortization	30.74		33.05		(7)%	27.06		14%

Uinta Basin Asset Sale

The Company announced on May 2, 2016, that it entered into an agreement with an unaffiliated third party to sell certain non-core assets located in the UOP for cash proceeds of approximately $30 million. The transaction is expected to close on or before June 30, 2016, and is subject to customary closing conditions. The assets produced approximately 1,000 Boe/d (63% oil) during the first quarter of 2016 and had estimated proved reserves of 2 MMBoe (87% proved developed) as of December 31, 2015. Based on the Company's internal estimates, the expected 2016 operating cash flow from the divested properties will be less than $2 million based on current strip pricing.

Debt and Liquidity

At March 31, 2016, the principal balance of long-term debt was $803.2 million and cash and cash equivalents were $105.6 million, resulting in net debt (principal balance of debt outstanding less the cash and cash equivalents balance) of $697.6 million.

The Company's semi-annual borrowing base review was completed in April 2016 with the bank group setting a borrowing base of $335 million, an 11% reduction from the previous borrowing base of $375 million. There were no changes to the terms or conditions of the credit facility and there are no borrowings outstanding. The revolving credit facility has $309 million in available capacity, after taking into account a $26 million letter of credit.

The next regularly scheduled borrowing base redetermination will occur on or about October 1, 2016.

Capital Expenditures

The Company exhibited continued capital discipline during the first quarter of 2016 as capital expenditures ("capex") totaled $45.8 million, which was 20% below the mid-point of the Company's guidance range of $55-$60 million. This was primarily due to recent XRL well costs being executed below forecast drilling and completion cost of $4.75 million.

Capex projects included spudding 4 XRL wells in the DJ Basin and completing 16 wells, including 15 XRL wells, which began initial flowback operations during the quarter. Capex included $42.4 million for drilling, $0.8 million for leaseholds, and $2.6 million for infrastructure and corporate assets. The Company did not spud any new wells in the UOP.

	Three Months Ended March 31, 2016
	Average Net Daily Production (Boe/d)	Wells Spud Net ⁽¹⁾	Capital Expenditures ($ millions)
Basin:
Denver-Julesburg	11,670	4	$	44.1
Uinta	3,341	—	0.7
Other	11	—	1.0
Total	15,022	4	$	45.8


(1)	Includes operated and non-operated wells

OPERATIONAL HIGHLIGHTS

DJ Basin

Produced an average of 11,670 Boe/d, an increase of 15% from the first quarter of 2015, excluding production associated with non-core asset sales completed during 2015.
The oil price differential averaged $5.61 per barrel less than WTI, a decrease from the fourth quarter of 2015 of $6.42 per barrel and a decrease from the first quarter of 2015 of $9.99 per barrel.
Spud 4 XRL wells and placed 16 wells, including 15 XRL wells, on initial flowback.
Expect to place 8 XRL wells on initial flowback during the second quarter of 2016.
The Company continues to be encouraged with the initial results of the development program and has a total of 34 wells, including 32 XRL wells that are currently in various stages of flowback operations. Activity to date has included utilizing several modified drilling and completion concepts to determine the optimal drilling and completion techniques.
As previously announced, due to the uncertainty of an oil price recovery during 2016, the Company elected to curtail drilling activity to preserve capital and released the sole drilling rig that was operating during the first quarter. Industry conditions will continue to be monitored to determine the appropriate time to resume drilling.
Drilling and completion costs for XRL wells are currently forecast to average approximately $4.75 million per well, although wells on the most recent multi-well pad were completed 10-15% below this level.
Drilling days for the recent XRL wells have consistently averaged approximately 8 days per well from spud to rig release, including a best-in-class well drilled in 6.5 days.

Uinta Oil Program

Given the outlook for commodity prices and a focus on its core DJ Basin assets, the Company has significantly reduced activity in the UOP and did not drill or complete any wells during the first quarter of 2016. Operations continue to be focused on improving operational efficiencies, and associated cost reductions have been realized as a result of lower lease operating costs.

2016 OPERATING GUIDANCE

The Company is providing the following update to its 2016 operating guidance. In addition, the Company intends to update 2016 operating guidance upon closing of the UOP asset sale. See "Forward-Looking Statements" below.

Capital expenditures of $90-$135 million, reduced from $100-$150 million as a result of lower XRL well costs.
- Second quarter capital expenditures are expected to total approximately $30-$35 million
Production of 5.8-6.2 MMBoe, unchanged.
- Second quarter production sales volumes are expected to approximate 1.4 MMBoe

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 May 5, 2016:

	Oil (WTI)		Natural Gas (NWPL)
Period	Volume Bbls/d	Price $/Bbl	Volume MMBtu/d	Price $/MMBtu
2Q16	7,300	81.65	5,000	4.10
3Q16	7,250	74.27	5,000	4.10
4Q16	7,250	74.27	5,000	4.10
1Q17	3,250	65.40	—	—
2Q17	3,250	65.40	—	—
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

First Quarter Conference Call and Webcast

The Company plans to host a conference call on Friday, May 6, 2016, to discuss the results and management's outlook for the future. 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 90845487. The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through May 13, 2016 at (855) 859-2056 ((404) 537-3406 international) with passcode 90845487.

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 "2016 Operating Guidance," which contains projections for certain 2016 operational and financial metrics. Additional forward-looking statements in this release relate to, among other things, the closing of, and proceeds from the planned asset sale 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. Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2015 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 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 March 31,
	2016		2015
Production Data:
Oil (MBbls)	886		1,125
Natural gas (MMcf)	1,626		1,764
NGLs (MBbls)	210		162
Combined volumes (MBoe)	1,367		1,581
Daily combined volumes (Boe/d)	15,022		17,567

Average Sales Prices (before the effects of realized hedges):
Oil (per Bbl)	$	27.60	$	37.12
Natural gas (per Mcf)	1.66		2.60
NGLs (per Bbl)	9.43		13.31
Combined (per Boe)	21.30		30.68

Average Realized Sales Prices (after the effects of realized hedges):
Oil (per Bbl)	$	63.69	$	76.28
Natural gas (per Mcf)	2.26		3.92
NGLs (per Bbl)	9.43		13.31
Combined (per Boe)	45.42		60.01

Average Costs (per Boe):
Lease operating expenses	$	6.46	$	8.72
Gathering, transportation and processing expense	0.58		0.60
Production tax expenses	(0.23)		1.60
Depreciation, depletion and amortization	30.74		33.05
General and administrative expense, excluding long-term incentive compensation expense ⁽¹⁾	6.21		6.50

(1)

This separate presentation is a non-GAAP 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.

BILL BARRETT CORPORATION Consolidated Condensed Balance Sheets (Unaudited)

	As of March 31,		As of December 31,
	2016		2015
	(in thousands)
Assets:
Cash and cash equivalents	$	105,563	$	128,836
Assets classified as held for sale	33,717		—
Other current assets ⁽¹⁾	114,083		145,481
Property and equipment, net	1,141,629		1,170,684
Other noncurrent assets ⁽¹⁾	49,218		61,519
Total assets	$	1,444,210	$	1,506,520

Liabilities and Stockholders' Equity:
Liabilities associated with assets held for sale	$	4,785	$	—
Other current liabilities	124,798		145,231
Long-term debt, net of debt issuance costs	794,972		794,652
Other long-term liabilities	13,678		17,221
Stockholders' equity	505,977		549,416
Total liabilities and stockholders' equity	$	1,444,210	$	1,506,520


(1)	At March 31, 2016, the estimated fair value of all of the Company's commodity derivative instruments was a net asset of $95.2 million, comprised of $80.4 million of current assets and $14.8 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 March 31,
	2016		2015
	(in thousands, except per share amounts)
Operating and Other Revenues:
Oil, gas and NGLs	$	29,121	$	48,486
Other	313		548
Total operating and other revenues	29,434		49,034
Operating Expenses:
Lease operating	8,827		13,791
Gathering, transportation and processing	788		942
Production tax	(315)		2,534
Exploration	27		33
Impairment, dry hole costs and abandonment	558		1,255
(Gain) Loss on divestitures	—		(38)
Depreciation, depletion and amortization	42,016		52,254
Unused commitments	4,568		4,388
General and administrative ⁽¹⁾	8,494		10,279
Long-term incentive compensation ⁽¹⁾	3,926		3,050
Total operating expenses	68,889		88,488
Operating Income (Loss)	(39,455)		(39,454)
Other Income and Expense:
Interest and other income	37		275
Interest expense	(15,746)		(16,430)
Commodity derivative gain (loss) ⁽²⁾	8,668		34,438
Gain (loss) on extinguishment of debt	—		2,567
Total other income and expense	(7,041)		20,850
Income (Loss) before Income Taxes	(46,496)		(18,604)
(Provision for) Benefit from Income Taxes	—		6,873
Net Income (Loss)	$	(46,496)	$	(11,731)

Net Income (Loss) per Common Share
Basic	$	(0.96)	$	(0.24)
Diluted	$	(0.96)	$	(0.24)
Weighted Average Common Shares Outstanding
Basic	48,499		48,199
Diluted	48,499		48,199


(1)	This separate presentation is a non-GAAP 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.

(2)	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,
	2016		2015
	(in thousands)
Included in commodity derivative gain (loss):
Realized gain (loss) on derivatives ^(a)	$	32,962	$	46,375
Prior year unrealized (gain) loss transferred to realized (gain) loss ^(a)	(29,486)		(40,734)
Unrealized gain (loss) on derivatives ^(a)	5,192		28,797
Total commodity derivative gain (loss)	$	8,668	$	34,438

(a)

Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of The Company's hedge position. The Company also believes that this disclosure allows for a more accurate comparison to its peers.

BILL BARRETT CORPORATION Consolidated Statements of Cash Flows (Unaudited)
	Three Months Ended March 31,
	2016		2015
	(in thousands)
Operating Activities:
Net income (loss)	$	(46,496)	$	(11,731)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	42,016		52,254
Impairment, dry hole costs and abandonment expense	558		1,255
Unrealized derivative (gain) loss	24,294		11,937
Deferred income tax benefit	—		(6,873)
Incentive compensation and other non-cash charges	3,329		2,743
Amortization of deferred financing costs	639		1,067
(Gain) loss on sale of properties	—		(38)
(Gain) loss on extinguishment of debt	—		(2,567)
Change in operating assets and liabilities:
Accounts receivable	12,413		9,064
Prepayments and other assets	(591)		(1,364)
Accounts payable, accrued and other liabilities	12,253		(1,661)
Amounts payable to oil and gas property owners	(4,036)		6,838
Production taxes payable	(3,864)		(7,099)
Net cash provided by (used in) operating activities	$	40,515	$	53,825
Investing Activities:
Additions to oil and gas properties, including acquisitions	(61,261)		(111,009)
Additions of furniture, equipment and other	(782)		(609)
Proceeds from sale of properties and other investing activities	(1,238)		66,415
Cash paid for short-term investments	—		(114,883)
Net cash provided by (used in) investing activities	$	(63,281)	$	(160,086)
Financing Activities:
Principal payments on debt	(109)		(24,871)
Deferred financing costs and other	(398)		(1,000)
Net cash provided by (used in) financing activities	$	(507)	$	(25,871)
Increase (Decrease) in Cash and Cash Equivalents	(23,273)		(132,132)
Beginning Cash and Cash Equivalents	128,836		165,904
Ending Cash and Cash Equivalents	$	105,563	$	33,772

BILL BARRETT CORPORATION Reconciliation of Discretionary Cash Flow and Adjusted Net Income (Loss) (Unaudited) Discretionary Cash Flow Reconciliation

	Three Months Ended March 31,
	2016		2015
	(in thousands, except per share amounts)
Net Income (Loss)	$	(46,496)	$	(11,731)
Adjustments to reconcile to discretionary cash flow:
Depreciation, depletion and amortization	42,016		52,254
Impairment, dry hole and abandonment expense	558		1,255
Exploration expense	27		33
Unrealized derivative (gain) loss	24,294		11,937
Deferred income tax benefit	—		(6,873)
Incentive compensation and other non-cash charges	3,329		2,743
Amortization of deferred financing costs	639		1,067
(Gain) loss on sale of properties	—		(38)
(Gain) loss on extinguishment of debt	—		(2,567)
Discretionary Cash Flow	$	24,367	$	48,080
Per share, diluted	$	0.50	$	1.00

Adjusted Net Income (Loss) Reconciliation

	Three Months Ended March 31,
	2016		2015
	(in thousands, except per share amounts)
Net Income (Loss)	$	(46,496)	$	(11,731)
(Provision for) Benefit from income taxes	—		6,873
Income (Loss) before income taxes	(46,496)		(18,604)

Adjustments to net income (loss):
Unrealized derivative (gain) loss	24,294		11,937
Impairment expense	183		58
(Gain) loss on sale of properties	—		(38)
(Gain) loss on extinguishment of debt	—		(2,567)
Adjusted Income (Loss) before income taxes	(22,019)		(9,214)
Adjusted (provision for) benefit from income taxes ⁽¹⁾	8,312		3,305
Adjusted Net Income (Loss)	$	(13,707)	$	(5,909)
Per share, diluted	$	(0.28)	$	(0.12)


(1)	Adjusted (provision for) benefit from income taxes is calculated using the Company's current effective tax rate prior to applying the valuation allowance against deferred tax assets.

EBITDAX Reconciliation

	Three Months Ended March 31,
	2016		2015
	(in thousands, except per share amounts)
Net Income (Loss)	$	(46,496)	$	(11,731)
Adjustments to reconcile to EBITDAX:
Depreciation, depletion and amortization	42,016		52,254
Impairment, dry hole and abandonment expense	558		1,255
Exploration expense	27		33
Unrealized derivative (gain) loss	24,294		11,937
Incentive compensation and other non-cash charges	3,329		2,743
(Gain) loss on sale of properties	—		(38)
(Gain) loss on extinguishment of debt	—		(2,567)
Interest and other income	(37)		(275)
Interest expense	15,746		16,430
(Provision for) Benefit from Income Taxes	—		(6,873)
EBITDAX	$	39,437	$	63,168

Discretionary cash flow, adjusted net income (loss) and EBITDAX 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, adjusted net income (loss) and EBITDAX 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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