Bill Barrett Corporation Reports 2014 Financial and Operating Results and Announces 2015 Operating Plan

DENVER, Feb. 25, 2015 /PRNewswire/ -- Bill Barrett Corporation (the "Company") BBG reported 2014 results and announced the 2015 Operating Plan and Strategy. Highlights include:

• Total production in 2014 of 9.1 MMBoe, as previously reported
• Production increased 29% over 2013, pro forma for asset sales
• Year-end 2014 proved reserves of 122 MMBoe, proved, probable and possible ("3P") reserves of 477 MMBoe
• Generated $231.6 million in discretionary cash flow, or $4.78 per diluted common share
• Reduced net debt by $266 million in 2014
• Entered 2015 well positioned with zero drawn on credit line, $515 million liquidity and approximately 100% of projected 2015 oil production hedged at $90 per barrel
• Received $42.9 million net cash settlement for Cottonwood Gulch litigation in February 2015
• 2015 strategy to concentrate capital on highest return assets while maintaining strong balance sheet
• 2015 operating plan has projected capital expenditures between $240-$280 million and total production between 5.5-5.9 million barrels of oil equivalent, or 10%  production growth at the mid-point, pro forma for asset sales

Chief Executive Officer and President Scot Woodall commented, "During 2014 we successfully executed the objectives we set forth at the beginning of the year including completing the transition to an oil-focused portfolio, concentrating our investment capital on our highest return assets and significantly reducing net debt. Our portfolio is dominated by our position in the Northeast Wattenberg area of the DJ Basin, which offers top tier returns among basins across the country."

"I am very pleased with our progress in the Northeast Wattenberg where, to date, we have drilled and completed 24 extended reach lateral ("XRL") wells. Preliminary results continue to support our expectations of higher rates of return associated with XRL development versus standard length laterals. Our Northeast Wattenberg development plans indicate that more than 80% of our acreage position can be developed with XRL wells. Our team continues to drive well optimization through variations in completion design with favorable preliminary results from larger sand volumes and an increased number of stimulation stages. Further, we continue to realize significant cost efficiencies through diligent efforts to reduce capital and operating costs, including a reduction in drilling and completion costs of approximately $2 million per XRL well to date. Results demonstrate the quality of the geology and our operating expertise, and we are focusing our 2015 drilling program on development of the Northeast Wattenberg with XRL wells."

"As we enter 2015, we are well positioned to run our business in a challenging macro-economic environment. We have zero drawn on our bank line, $165 million in cash, insignificant drilling obligations, approximately 100% of oil production hedged at $90 per barrel, and we are projecting approximately 10% growth in production from our core assets. We are implementing a more than 50% reduction in capital expenditures in 2015 to preserve the strength of our balance sheet and defer development in order to realize better long-term returns."

See below for details on 2015 guidance. In addition, the Company posted an updated investor presentation to its website at www.billbarrettcorp.com, which provides additional detail on year-end 2014 results, year-end 2014 reserves and the 2015 operating plan.

OPERATING AND FINANCIAL RESULTS

Reserves

Total estimated proved reserves at year-end 2014 were 122.3 million barrels of oil equivalent ("MMBoe"). Estimated proved reserves were 69% oil, 21% natural gas and 10% natural gas liquids ("NGLs") and were 34% developed. The estimated production replacement ratio was 340% based on reserve additions and acquisitions in 2014 of 30.9 MMBoe and 2014 production of 9.1 MMBoe. The Company took a conservative approach to proved reserve bookings in the current commodity price environment, including reducing reserves that the Company does not contemplate developing over the next few years, in advance of the deadline imposed by the five-year rule. Also of note, reserves associated with extended reach lateral wells were heavily risked by an estimated 20-30% due to limited production history as of the cut-off date for reserve calculations in the fourth quarter of 2014.

The pre-tax present value of proved reserves, or PV10 (a non-GAAP measure, see the relevant reconciliation table below), was estimated at $1.5 billion. The present value calculation is before income taxes and is based on a Henry Hub natural gas price of $4.35 per MMBtu, a WTI oil price of $94.99 per barrel, an NGL price per barrel equal to 36% of WTI,  and a 10% per annum discount rate. Pre-tax PV10 adds back the discounted value of taxes from the Company's standardized measure of discounted future net cash flows. PV10 information is provided because it is a commonly used metric in the exploration and production industry.

In addition to estimated proved reserves, the Company estimates it had probable and possible reserves of 355 MMBoe at December 31, 2014, for total 3P reserves of approximately 477 MMBoe. 3P reserves increased 22% at year-end 2014 compared with year-end 2013, pro forma for assets sold. See "Reserve and Resource Disclosure" note below. At December 31, 2014, the Company had approximately 3,700 gross/1,690 net drilling locations based on 3P reserves.

2014 Production & Financial Results

Oil, natural gas and NGL production totaled 9.1 MMBoe in 2014 compared with 14.5 MMBoe in 2013, with the decrease in production attributable to asset sales completed at the end of 2013 and in the third quarter of 2014. Production from core assets increased 29% year over year, pro forma for asset sales.  Fourth quarter 2014 production was 1.4 MMBoe. Exit rate production is estimated at approximately 15,600 Boe/d, including approximately 11,000 Bbls/d oil, 18 MMcf/d natural gas and 1,600 Bbls/d NGLs. Fourth quarter and exit rate production include the impact of third party facility downtime, which affected net production for these periods by approximately 1,000 Boe/d.

Discretionary cash flow, (a non-GAAP measure, see the relevant reconciliation table below) for 2014 was $4.78 per diluted common share, down from $5.92 per diluted common share in 2013 mostly as a result of lower production due to asset sales. Lower production was partially offset by a 29% increase in the average realized price per barrel primarily as a result of the increased proportion of oil sales in the Company's commodity mix, a 21% decline in interest expense and a 14% decline in general and administrative expenses (before non-cash, stock-based compensation.) Discretionary cash flow for the fourth quarter of 2014 was $0.80 per diluted common share compared with $1.62 per diluted common share in the prior year period.

Net income for 2014 was $15.1 million, or $0.31 per diluted common share, compared with a loss of $192.7 million, or ($4.06) per diluted common share in 2013. Net income for 2014 and 2013 includes impairment charges of $40.2 million (pre-tax) and $226.6 million (pre-tax), respectively, as well as a derivative gain of $199.3 million (pre-tax) in 2014 and a derivative loss of $28.4 million (pre-tax) in 2013. Impairment charges in 2014 related primarily to the Powder River Basin asset sale, unfavorable drilling results in the Paradox Basin and certain unproved properties.  Net income for the fourth quarter of 2014 was $89.1 million, or $1.84 per diluted common share, which included a non-cash derivative gain of $177.4 million. Adjusted net income (loss) (a non-GAAP measure, see the relevant reconciliation table below) was ($25.2) million in 2014 compared with ($20.5) million in 2013. The larger loss in 2014 was primarily driven by a 34% increase in per unit depreciation, depletion and amortization expense compared with 2013 due to a higher proportion of oil in the production mix. For the fourth quarter of 2014, adjusted net income (loss) was ($11.3) million or ($0.23) per diluted common 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.

2014 Year-end Debt & Liquidity

At December 31, 2014, 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. At year-end, net debt (principal balance of debt outstanding less the cash balance) was $663.0 million and liquidity was $515.0 million. In February 2015, the Company received approximately $42.9 million net proceeds to refund leases relinquished in settlement of the Cottonwood Gulch litigation.

2014 Capital Expenditures

Capital expenditures for 2014 were $569 million and included drilling 168 gross/96 net wells, of which 115 gross/89 net were operated by the Company. Capital expenditures included $531 million for drilling at development programs, $15 million for leaseholds to expand development programs, and $23 million for infrastructure and corporate. The Company also acquired assets in the Northeast Wattenberg for an estimated value of $69 million in an exchange for assets in the Powder River Basin.

OPERATIONS BRIEF

DJ Basin

2014 DJ Basin highlights include:

• Drilled 99 gross/58 net wells and placed 93 gross/63 net into sales.
• DJ Basin fourth quarter of 2014 production averaged 8,930 Boe/d, up 74% from the fourth quarter of 2013.
• Year-end proved reserves totaled 73.1 MMBoe, and year-end proved, probable and possible reserves totaled 301 MMBoe.
• Increased PDP reserves by 89%.
• Year-end net acreage totaled 96,655, of which 47,826 net acres are located in the Northeast Wattenberg.
• Exit rate production was 9,150 Boe/d.

Drilling results update:

• As previously reported, the Company has recorded 30-day initial production ("IP") (see Disclosure section below) rates for 9 XRL wells. These wells produced an average 617 Boe/d (3-stream) per well over the first 30 days.
• The Company has recorded 60-day day average production rates for 3 XRL wells that averaged 484 (3-stream) Boe/d per well over the first 60 days following peak production.

The Northeast Wattenberg program will be the foundation of the 2015 operating plan as it offers the best returns in the Company's portfolio. The Company operated three rigs in the area through mid-February and plans to operate a one rig program through the remainder of 2015. Well costs for a 9,000 foot lateral are projected to decline during the year by approximately $2 million per well from approximately $8.25 million at the end of 2014. The Company plans to drill and complete 20-25 wells in the Northeast Wattenberg during 2015, which will be predominantly XRL wells, as well as participate in non-operated wells in the area.

Uinta Oil Program ("UOP")

2014 Uinta basin highlights include:

• Drilled 65 gross/37 net wells and placed 58 gross/34 net into sales.
• UOP fourth quarter of 2014 production averaged 6,000 Boe/d with exit rate production of 6,200 Boe/d.
• Year-end proved reserves totaled 48.1 MMBoe, and year-end proved, probable and possible reserves totaled 151 MMBoe.
• Year-end net acreage totaled 171,883, of which 24,365 net acres is located in the East Bluebell area.

In 2015, due to low commodity prices, the Company plans to release the UOP rig during the first quarter with plans to resume drilling in the second half of 2015. The Company expects to drill 9 gross/3.3 net wells in the East Bluebell area of which four wells will test 40-acre density.

2015 OPERATING GUIDANCE

The Company's 2015 strategy is to preserve the balance sheet and reduce capital activity in an environment where investment returns are affected by the low commodity price outlook. The Company is very well positioned for the current year having ample liquidity, approximately all of its 2015 production hedged at $90 per barrel oil and more than $4.00 per MMBtu natural gas, nominal drilling commitments and flexible service contracts. The Company's 2015 plan is expected to result in approximately 10% production growth from core assets while cutting the capital budget by more than half. The plan does not require additional debt and focuses investment on highest return development.

The Company plans to reduce its development activity with total capital expenditures between $240-$280 million.  The Company expects to drill and complete approximately 30-35 wells and participate in non-operated wells in the Northeast Wattenberg and Uinta Basin. The Company intends to fund its capital expenditure program with cash flows from operations and from its available cash balance.

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

• Capital expenditures of $240-$280 million
  • This includes a one-rig program through the year in the DJ Basin drilling 20-25 wells and a partial year rig in the Uinta Basin drilling approximately nine wells in the East Bluebell area, plus participation in non-operated wells in both basins.
  • Well costs are expected to vary during the year due to the timing of service cost reductions. Currently, XRL wells in the Northeast Wattenberg are approximately $6.25 million per well. Wells in East Bluebell are expected to average $1.6 million per well.
  • First quarter of 2015 capital expenditures are expected to be approximately $115 million due to maintaining four rigs through approximately one-half of the quarter.
• Production of 5.5-5.9 MMBoe
  • Production is expected to be approximately 70% oil, 20% natural gas and 10% NGLs.
  • First quarter of 2015 production is expected to be approximately 1.4 MMBoe.
• Lease operating expenses of $46-$50 million.
• Gathering, transportation and processing costs of $3-$5 million.
• Unused commitment for firm natural gas transportation charges of $18-$19 million.
• General and administrative expenses before non-cash, performance-based compensation of $36-$40 million.

COMMODITY HEDGES UPDATE

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

The following table summarizes hedge positions as of February 23, 2015:

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

UPCOMING EVENTS

2014 Fourth Quarter and Year-end Conference Call and Webcast

The Company plans to host a conference call this morning to discuss results.  The call is scheduled at 9:00 a.m. Eastern time (7:00 a.m. Mountain time) today. Please join the webcast conference call live or for replay via the Internet at www.billbarrettcorp.com. To join by telephone, call 800-901-5213 (617-786-2962 international callers) with passcode 31760883. Slides will be presented in conjunction with the webcast and conference call and are accessible on the Company's website homepage at www.billbarrettcorp.com.The webcast will remain on the Company's website for approximately 30 days and a replay of the call will be available through March 4, 2015 at 888-286-8010 (617-801-6888 international) with passcode 11777921.

DISCLOSURE STATEMENTS

Please refer to the Company's Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC, and for the year ended 2014 upon filing, 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.

Reserve Disclosure

The Company has provided internally generated estimates for probable and possible reserves in this release. The estimates conform to SPEE methodology. They are not prepared or reviewed by third party engineers. Our 2014 probable and possible reserve estimates are determined using year-end pricing, as used in the calculation of proved reserves. Probable and possible reserves are subject to significantly greater risk of recovery than proved reserves. The Company's estimate of probable and possible reserves is provided in this release because management believes it is useful, additional information that is widely used by the investment community in the valuation, comparison and analysis of companies.

Well Performance

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

Forward-Looking Statements

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

These and other forward-looking statements in this presentation are based on management's judgment as of the date of this presentation and are subject to numerous risks and uncertainties. Actual results may vary significantly from those indicated in the forward-looking statements due to, among other things: oil, NGL and natural gas price volatility, including regional price differentials; changes in operational and capital plans; 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; 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; and other factors discussed in the Company's reports filed with the SEC. 

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

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SOURCE Bill Barrett Corporation