Bill Barrett Corporation Reports Third Quarter 2011 Results and Announces Further Encouraging Uinta Oil Results
DENVER, Nov. 3, 2011 /PRNewswire/ -- Bill Barrett Corporation (NYSE: BBG) today reported third quarter 2011 operating results highlighted by:
- Natural gas and oil production growth, up 10% to 28.0 Bcfe compared with the third quarter of 2010
- Third and fourth Uteland Butte horizontal oil wells showing strong initial flow rates
- Discretionary cash flow of $125.9 million or $2.65 per diluted common share
- Net income of $20.6 million or $0.43 per diluted common share and adjusted net income of $16.8 million or $0.35 per diluted common share
- Issuing $400 million of 7.625% senior notes, providing substantial liquidity
- Closing key Denver-Julesburg (“DJ”) oil acquisition, adding 7 MMBoe proved reserves with 28,500 net acres
Chairman, Chief Executive Officer and President Fred Barrett commented: “Solid execution on strategies to increase the oil mix in our portfolio continued in the third quarter. Our build in oil is demonstrated on a few fronts with September oil production representing a 42% increase since the start of the year. Our acquisitions team closed on our DJ Basin acquisition, adding a fourth key development area and another liquids-focused program. Our operations team has completed two more horizontal Uteland Butte wells, both with encouraging results from our Uinta Oil Program. Currently, oil and natural gas liquids represent approximately 20% of our production based on energy content and approximately 44% of pre-hedge revenue, driving our continued emphasis on balancing the portfolio with liquids growth.
“We are very pleased to report continued positive results from the Uinta Oil Program where the peak 24-hour initial production (“IP”) rates for the first four horizontal Uteland Butte wells have averaged in excess of 1,000 barrels of oil equivalent per day (“Boe/d”). To date, the first two horizontal wells are producing as, or better than, expected. The third Uteland Butte horizontal well flowed and pumped an average 707 Boe/d over the first 30 days of production and had a peak 24-hour IP rate of 1,330 Boe/d, and the fourth Uteland Butte horizontal well, which has been on production for only 21 days, has averaged 596 Boe/d and had a peak IP rate of 863 Boe/d during that period. It is too early to estimate EURs from results to date, yet success in the Uteland Butte would open the potential for inventory expansion in our sizable Uinta Oil Program acreage position.
“As 2011 is nearing a close, we have added a third rig in the Uinta Oil Program where we will soon commence drilling in the East Bluebell oil expansion area. We have also recently added a rig in the DJ Basin, where we will continue development in the Wattenberg Field and will soon drill our first horizontal Niobrara test at our Chalk Bluffs exploration area. We are diligently working to complete facility upgrades at West Tavaputs in order to keep pace with production there. We have updated 2011 guidance to lower cost estimates for both operating and transportation expenses while keeping production and capital expenditure expectations unchanged (see “Guidance” below.) 2011 remains on track to deliver solid growth while positioning the Company for an even stronger year in 2012.”
Third quarter 2011 natural gas and oil production totaled 28.0 billion cubic feet equivalent (“Bcfe”), up 10% from 25.5 Bcfe in the third quarter of 2010 and up 6% sequentially from the second quarter of 2011. For the first nine months of 2011, production totaled 77.7 Bcfe, up 8% from the 2010 period. The Company is on track for its full year guidance range of 106 to 110 Bcfe. Third quarter production growth was predominantly from the West Tavaputs natural gas program as well as the Uinta Oil Program and acquisition properties. Including the effects of the Company’s hedging activities and natural gas liquids recovery, the average realized sales price in the third quarter of 2011 was $7.06 per thousand cubic feet equivalent (“Mcfe”) compared with $7.03 per Mcfe in the third quarter of 2010. The Company’s commodity hedging program increased third quarter 2011 natural gas and oil revenues by net $16.8 million, or $0.60 per Mcfe of production. The incremental revenue benefit from processing a portion of its natural gas for natural gas liquids increased to $1.41 per Mcfe in the third quarter of 2011, reflecting strong natural gas liquids pricing in the period and inclusion of incremental NGL benefits from West Tavaputs and the DJ Basin.
Discretionary cash flow (a non-GAAP measure, see “Discretionary Cash Flow Reconciliation” below) in the third quarter of 2011 was $125.9 million, or $2.65 per diluted common share, compared with $136.5 million, or $2.98 per diluted common share, in the third quarter of 2010. Discretionary cash flow was down from the comparable 2010 period primarily due to a one-time adjustment from current to deferred tax expense in the 2010 period totaling $13.1 million. Discretionary cash flow for the first nine months of 2011 was $353.4 million, down 1% from $357.1 million in the first nine months of 2010.
Net income in the third quarter of 2011 was $20.6 million, or $0.43 per diluted common share, compared with $24.6 million, or $0.54 per diluted common share, in the third quarter of 2010. The decline in net income was primarily due to higher impairment, dry hole and abandonment expense in the 2011 period. Dry hole expense in the third quarter of 2011 was $11.0 million ($6.9 million net of tax) and included the McRae Gap exploration well in the Wind River Basin and interests in two exploratory wells in the north end of the DJ Basin. Net income for the first nine months of 2011 was $68.5 million, down 22% from the first nine months of 2010, primarily due to higher derivative losses and higher impairment, dry hole and abandonment expenses. Adjusted net income for the third quarter of 2011 (a non-GAAP measure, see “Adjusted Net Income Reconciliation” below) was $16.8 million, or $0.35 per diluted common share, compared with $24.0 million, or $0.52 per diluted common share, in the third quarter of 2010. The decline in adjusted net income was primarily due to the higher dry hole cost in the 2011 period, which is not added back in the adjusted net income calculation. Adjusted net income removes the effect of non-recurring charges such as unrealized derivative gains and losses, impairment expenses, property sales and one-time items.
DEBT AND LIQUIDITY
At September 30, 2011, the Company’s revolving credit facility was undrawn. Subsequent to quarter-end, the Company increased its borrowing base to $1.1 billion and bank commitments to $900.0 million, while extending the maturity of the credit facility to October 2016. After deducting an outstanding letter of credit for $26.0 million, borrowing capacity is currently $874.0 million. During the quarter, the Company completed the offering of $400 million of 7.625% senior notes due 2019, issued at par. Proceeds from the offering were used to pay down the Company’s revolving credit facility. The Company also had $172.5 million in 5% convertible senior notes and $250.0 million in 9.875% senior notes outstanding at September 30, 2011.
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital expenditures by basin for the three months and nine months ended September 30, 2011:
Three Months ended September 30, 2011
Nine Months ended September 30, 2011
Powder River (CBM)
Capital expenditures totaled $324.8 million for the third quarter of 2011, including the acquisition of properties in the DJ Basin for $149.1 million.
Operating and Drilling Update
The Company anticipates participating in the drilling of approximately 300 gross wells in 2011, including approximately 6 coal bed methane (“CBM”) wells. The Company currently has eight active operated drilling rigs with two at West Tavaputs, two at Gibson Gulch, three at the Uinta Oil Program and one at the DJ Basin acquisition area. The Company’s development program is focused on growth in production and reserves as well as driving operating efficiencies at West Tavaputs.
Uinta Basin, Utah
West Tavaputs – Current net production is approximately 100 million cubic feet equivalent per day (“MMcfe/d”). The Company continues to successfully execute its development program in the area and is on track for its approximate 100-well program for 2011. Due to increased drilling efficiencies and better than expected well performance at certain wells, production increased faster than anticipated, and the Company is currently installing a loop line and additional compression capacity. New capacity will be in place in the first quarter of 2012 that will support future production. West Tavaputs is one of the Company’s largest development assets based on its current reserve base of 345 Bcfe proved and 1.3 Tcfe proved, probable and possible reserves (see “Reserve Disclosure” below), providing a multi-year, high growth program for the Company.
At September 30, 2011, the Company had an approximate 97% working interest in production from 235 gross wells in its West Tavaputs shallow and deep programs. The West Tavaputs development program primarily targets the shallow Mesaverde and Wasatch zones. Upside potential is also recognized in the shallow Green River oil zones and deeper formations including the Mancos.
Uinta Oil Program (Blacktail Ridge, Lake Canyon and East Bluebell) – Current net production is approximately 4,400 Boe/d. The Company added a third rig to the area in early October 2011. This area offers upside potential through horizontal drilling, increased density and field extension.
During the third quarter of 2011, the Company continued horizontal drilling into the Uteland Butte formation (working interest 55.8% for first four wells). The third well was completed in the Uteland Butte at approximately 5,850’ with a 3,400’ lateral and 15 fracture stimulation stages and flowed and pumped an average 707 Boe/d over the first 30 days of production with a peak 24-hour IP rate of 1,330 Boe/d. The fourth well was completed to approximately 5,900’ with a 3,200’ lateral and 15 fracture stimulation stages and had a peak IP rate of 863 Boe/d during the 21 days it has been on production. The Company intends to drill a total of seven horizontal wells targeting the Uteland Butte formation by year-end. The Company expects to sizably increase its well inventory at the Uinta Oil Program with continued success in both its vertical and horizontal drilling plans.
The Company also completed a vertical test well into the Mahogany formation to 5,500’ with 245’ of core. Core tests in the Mahogany formation were positive and the well is recovering oil. The Company is currently permitting for two additional vertical test wells it expects to drill in mid-2012.
At September 30, 2011, the Company had an approximate 68% working interest in production from 105 gross wells in the combined area. The working interests in this area range from 19% to 100%.
Piceance Basin, Colorado
Gibson Gulch – Current net production is approximately 138 MMcfe/d. The Company continues to operate two rigs in the area and expects to complete a 100-plus well program in 2011. The Company continues to benefit from its election to process the majority of its Gibson Gulch natural gas production, which exposes the Company to natural gas liquids pricing. Gibson Gulch operations offer strong margins due to low operating costs and the currently higher revenues related to liquids. The program continues to be a key, lower risk development area for the Company.
At September 30, 2011, the Company had an approximate 98% working interest in production from 792 gross wells in its Gibson Gulch program.
Denver-Julesburg Basin, Colorado and Wyoming
Wattenberg/Chalk Bluffs/Sagebrush – The Company has approximately 67,500 net acres in the DJ Basin, a fourth key development area for the Company. The Company closed on its DJ Basin acquisition in August, took over operations as of September and initiated drilling in mid-October. Drilling commenced in the Wattenberg area, where current production is from the Codell, Niobrara and J Sand formations. Following four-to-five vertical wells in the Wattenberg Field, the Company plans to initiate exploration drilling in the area, targeting the Niobrara shale formation through horizontal wells.
During the third quarter of 2011, the Company completed its first DJ Basin exploration well and had a small participation interest in a second well, both located in the northern DJ Basin, north of the Company’s recent acquisition, which did not produce commercial quantities of oil and were expensed as dry holes.
Wind River Basin, Wyoming
McRae Gap - The Company has identified approximately 100,000 net undeveloped acres within its acreage position in the area that it considers prospective for Niobrara shale oil. In the third quarter of 2011, the Company completed its first horizontal exploration well into the lower bench of the Niobrara shale at approximately 8,000’ in depth with an approximate 3,200’ lateral and 13 fracture stimulation stages. While the first exploration well in the area produced only minor amounts of oil, the Company is reviewing data to refine its drilling focus in the prospect. In the third quarter, this $5.7 million McRae Gap well was expensed as a dry hole.
ADDITIONAL FINANCIAL INFORMATION
The Company’s 2011 guidance (please reference “Forward-Looking Statements” below) is updated as follows:
- Capital expenditures for exploration and development of $685 to $705 million, unchanged. This amount is before acquisition purchase costs totaling approximately $268 million through the first nine months.
- Oil and natural gas production of 106 to 110 Bcfe, unchanged.
- Lease operating costs per Mcfe of $0.53 to $0.55, reduced and narrowed from $0.54 to $0.58 as a result of effective cost discipline across operations.
- Gathering, transportation and processing costs per Mcfe of $0.87 to $0.89, lowered from $0.89 to $0.93.
- General and administrative expenses before non-cash stock-based compensation between $47.5 and $48.5 million, increased from $46.0 and $47.5 million, mostly due to higher employee costs and headcount.
Commodity Hedges Update
It is the Company’s strategy to hedge a portion of its production to reduce the risks associated with unpredictable future commodity prices and to provide predictability for a portion of cash flows in order to support the Company’s capital expenditure program.
For the fourth quarter of 2011 and for 2012, the Company has hedges in place as outlined in the table below. Swap and collar hedge positions are tied to regional sales points and include:
- For the fourth quarter of 2011, approximately 18.7 Bcfe at a weighted average blended floor price of $7.30 per Mcfe.
- For 2012, approximately 51.7 Bcfe at a weighted average blended floor price of $7.27 per Mcfe.
As of October 31, 2011:
SWAPS & COLLARS
Natural Gas / NGLs
In addition, the Company has natural gas basis only hedges in place for the fourth quarter of 2011 for 20,000 MMBtu/d at a basis differential price between CIG Rocky Mountains and Henry Hub of ($1.72) per MMBtu and for 2012 of 20,000 MMBtu/d at a basis differential price of ($1.22) per MMBtu. These hedges are not in the money.
THIRD QUARTER 2011 WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held later this morning to discuss third quarter 2011 results. Please join Bill Barrett Corporation executive management at 12:00 p.m. Eastern time (“ET”)/10:00 a.m. Mountain time (“MT”) for the live webcast, accessed at www.billbarrettcorp.com, or join by telephone by calling 866-761-0748 (617-614-2706 international callers) with passcode 68573156. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through November 10, 2011 at call-in number 888-286-8010 (617-801-6888 international) with passcode 69611288. The Company also has tentatively scheduled its fourth quarter 2011 earnings conference call for February 23, 2012 at noon ET/10:00 a.m. MT.
Updated investor presentations will be posted to the homepage of the Company’s website at www.billbarrettcorp.com for each event below. Please check the website at 5:00 p.m. MT on the business day prior to the investor event for the most recent presentation, unless otherwise noted:
Chief Financial Officer Bob Howard will participate at the Barclays Capital Second Annual Energy, Engineering and Construction Forum in Dallas on November 10, 2011. An updated investor presentation will be posted at 5:00 p.m. MT on Tuesday, November 8, 2011.
Chief Operating Officer Scot Woodall will present at the Bank of America Merrill Lynch Global Energy Conference in Miami on November 15, 2011 at 1:20 p.m. ET. The event will be webcast.
Chief Financial Officer Bob Howard will present at the Bank of America Merrill Lynch Leveraged Finance Conference in Orlando on December 2, 2011 at 10:50 a.m. ET. The event will be webcast. The presentation for this event will be posted at 5:00 p.m. MT on Wednesday, November 30, 2011.
This press release contains forward-looking statements, including statements regarding projected results and future events, including guidance and the upside potential and other prospects of acquisitions and other planned activities. These forward-looking statements are based on management’s judgment as of this date and include certain risks and uncertainties. Please refer to the Company’s Annual Report on Form 10-K for the year-ended December 31, 2010 filed with the SEC, and other filings including our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011 and Current Reports on Form 8-K, for a list of certain risk factors.
Actual results may differ materially from Company projections and can be affected by a variety of factors outside the control of the Company including, among other things, market conditions, oil and gas price volatility, exploration and development drilling and testing results, performance of acquired properties, the ability to receive drilling and other permits and rights-of-way, regulatory approvals, governmental laws and regulations and changes in enforcement of those laws and regulations, new laws and regulations, risks related to and costs of hedging activities including counterparty viability, surface access and costs, availability of third party gathering, transportation and processing, the availability and cost of services and materials, 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, availability and costs of financing to fund the Company’s operations, uncertainties inherent in oil and gas production operations and estimating reserves, the speculative actual recovery of estimated potential volumes, unexpected future capital expenditures, competition, risks associated with operating in one major geographic area, the success of the Company’s risk management activities, title to properties, litigation, environmental liabilities, and other factors discussed in the Company’s reports filed with the SEC. Bill Barrett Corporation encourages readers to consider the risks and uncertainties associated with projections and other forward-looking statements. In addition, the Company assumes no obligation to publicly revise or update any forward-looking statements based on future events or circumstances.
The SEC, under its recently revised guidelines, permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. The Company does not plan to include probable and possible reserve estimates in its filings with the SEC.
The Company has provided internally generated estimates for probable and possible reserves in this release. The estimates conform to SEC guidelines. They are not prepared or reviewed by third party engineers. Our probable and possible reserve estimates are determined using strip pricing, which we use internally for planning and budgeting purposes. 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. U.S. investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the year ended December 31, 2010, available on the Company's website at www.billbarrettcorp.com or from the corporate offices at 1099 18th Street, Suite 2300, Denver, CO 80202. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or at www.sec.gov.
ABOUT BILL BARRETT CORPORATION
Bill Barrett Corporation (NYSE: BBG), headquartered in Denver, Colorado, explores for and develops natural gas and oil 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
Three Months Ended
Nine Months Ended
Natural gas (MMcf)
Combined volumes (MMcfe)
Daily combined volumes (Mmcfe/d)
Average Prices (before the effects of realized hedges):
Natural gas (per Mcf)
Oil (per Bbl)
Combined (per Mcfe)
Average Realized Prices (after the effects of realized hedges):
Natural gas (per Mcf)
Oil (per Bbl)
Combined (per Mcfe)
Average Costs (per Mcfe):
Lease operating expense
Gathering, transportation and processing expense
Production tax expense
Depreciation, depletion and amortization
General and administrative expense,
excluding non-cash stock-based compensation
Production tax expense for the first nine months of 2010 includes a one-time benefit to reduce and re-estimate prior periods as a result of amended returns filed with the State of Utah regarding the calculation of severance taxes. Exclusive of the one-time benefits, the production tax expense per Mcfe for the first nine months of 2010 would have been $0.38.
Management believes the separate presentation of the non-cash component of general and administrative expense is useful because the cash portion provides a better understanding of cash required for general and administrative expenses. Management also believes that this disclosure may allow for a more accurate comparison to the Company's peers that may have higher or lower costs associated with equity grants.
BILL BARRETT CORPORATION
Consolidated Statements of Operations
Three Months Ended
Nine Months Ended
(in thousands, except per share amounts)
Operating and Other Revenues:
Oil and gas production
Commodity derivative gain (loss)
Total operating and other revenues
Gathering, transportation and processing
Impairment, dry hole costs and abandonment
Depreciation, depletion and amortization
General and administrative
Non-cash stock-based compensation
Total operating expenses
Other Income and Expense:
Interest income and other income (expense)
Total other income and expense
Income before Income Taxes
Provision for Income Taxes
Net Income Per Common Share
Weighted Average Common Shares Outstanding