EXHIBIT 99.1
| | |
 | | Press Release |
For immediate release
Company contact: Jennifer Martin, Director of Investor Relations, 303-312-8155
Bill Barrett Corporation Reports 2008 Results: Another Record Year
DENVER – February 24, 2009 – Bill Barrett Corporation (NYSE: BBG) today reported full-year 2008 operating results highlighted by:
| | • | | Production growth, up 27% to 77.6 Bcfe |
| | • | | Proved reserve growth, up 47% to 818 Bcfe |
| | • | | Reserve replacement ratio 436% |
| | • | | Proved, probable and possible resources up 45% to 2.9 Tcfe |
| | • | | Discretionary cash flow of $429.1 million, up 71% per diluted share to $9.53 |
| | • | | Net income of $107.6 million, up 298% per diluted share to $2.39 |
| | • | | Finding and development costs of $1.76 per Mcfe, having a weighted average of $1.99 per Mcfe over three-years |
| | • | | Paradox Basin shale gas discovery |
Chairman and Chief Executive Officer, Fred Barrett, commented: “2008 was a tremendous year for Bill Barrett operations, demonstrating our continuing track record of growth. Reserve growth of 47% was accompanied by low average finding costs of $1.76 per million cubic feet equivalent (Mcfe). Record production was driven by our solid development assets, which in turn delivered sizable discretionary cash flow and earnings. In addition, our exploration team has a number of exciting prospects in the works, including our internally generated shale gas discovery in the Paradox Basin. Further, as natural gas and oil prices declined during the second half of 2008, we maintained strong results and took necessary steps to be well positioned for a more challenging 2009.
“We have started 2009 with a conservative balance sheet and an operations strategy that will assist us to successfully weather the economic downturn. We began the year with $339 million available on our bank line of credit, we have a capital budget of up to $350 million, intended to keep expenditures aligned with discretionary cash flow, and we have in-place natural gas and oil hedges supporting 73% to 76% of forecast 2009 production, including natural gas hedges at an average floor price of $7.89 per Mcf, which in-turn supports our cash flow. While we believe we are well-positioned in the current environment, we will also maintain flexibility in our operations strategy to best align with business conditions, the regulatory environment and commodity prices going forward.”
Natural gas and oil production totaled 77.6 billion cubic feet equivalent (Bcfe) for 2008 compared with 61.2 Bcfe in 2007. Including the effects of the Company’s hedging activities, the average sales price realized was $7.81 per Mcfe in 2008 compared with $6.13 per Mcfe in 2007. The Company’s 2008 hedging program increased its natural gas and oil revenues by $31.9 million or $0.41 per Mcfe on average. For the fourth quarter 2008, production totaled 20.6 Bcfe, up 20% compared with 17.2 Bcfe in the fourth quarter 2007, and the average realized price was $6.96 per Mcfe, up from $6.19 per Mcfe in the fourth quarter 2007.
Proved reserves at year-end 2008 were 818 Bcfe, up 47% from 558 Bcfe at year-end 2007. Capital expenditures for 2008 totaled $601.1 million, up 35% from $443.7 million in 2007.
Discretionary cash flow (a non-GAAP measure, see page 12) was $429.1 million in 2008 or $9.53 per diluted share, up $180.6 million compared with $248.5 million or $5.56 per diluted share in 2007. The significant year-over-year increase was primarily a result of higher cash operating income generated by: a 27% increase in production; a 27% increase in the average realized price; a 16% decline in per unit lease operating costs generated primarily by increased efficiencies in the Piceance and Powder River
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development projects; all partially offset by higher per unit gathering, transportation and production taxes (see per unit metrics on page 8.) For the fourth quarter 2008, discretionary cash flow was $101.8 million, or $2.28 per diluted share, compared with $70.1 million, or $1.56 per diluted share, in the prior year period. Fourth quarter 2008 results benefited primarily from both higher year-over-year production volumes and higher per unit sales prices.
Net income was $107.6 million, or $2.39 per diluted common share, in 2008 compared with $26.8 million, or $0.60 per diluted common share, in 2007. Net income includes a $25.3 million non-cash impairment charge, or $15.8 million after tax and $0.35 per diluted share after tax, for a reduction in the carrying value of natural gas and oil properties due to a geologic and engineering re-evaluation of certain Wind River properties and lower commodity prices at year-end 2008. Net income also includes a net unrealized commodity gain of $7.9 million and a gain on property sales of $1.1 million, or $5.6 million after tax and $0.13 per diluted share after tax. Adjusting for these three charges, 2008 net income was $117.8 million or $2.62 per diluted share.
The $80.8 million increase in net income in 2008 compared with 2007 was primarily a result of higher per unit discretionary cash flow from operations described above, as well as lower per unit depreciation, depletion and amortization expenses, partially offset by certain higher non-cash expenses including the impairment charge and non-cash general and administrative charge for stock-based compensation. For the fourth quarter 2008, net income was $6.9 million, or $0.15 per diluted common share, compared with $2.5 million, or $0.06 per diluted common share, in the prior year period. Adjusting for the fourth quarter impairment charge and net unrealized commodity gains, net income was $20.7 million or $0.46 per diluted share after tax. Improved fourth quarter 2008 results compared with the prior year period were driven primarily by higher per unit discretionary cash flow.
DEBT AND LIQUIDITY
As reported earlier, the Company ended 2008 with $254.0 million drawn on its revolving credit facility. The facility has a borrowing base of $600.0 million and bank commitments of $592.8 million, providing the Company $338.8 million of borrowing capacity as of year-end 2008. The Company also had outstanding 5% convertible senior notes in the amount of $172.5 million. The Company is comfortable with its available financing and the status of its credit metrics.
OPERATIONS
Wells Spud and Capital Expenditures
Capital expenditures for 2008 totaled $601.1 million and included: $542.1 million for drilling, exploration and development of natural gas and oil properties; $39.4 million for acquisition of proved and undeveloped properties; $14.8 million for geologic and geophysical costs and exploratory dry holes and abandonment; and $4.8 million for furniture, fixtures, equipment and other assets. The Company did not have any major property sales during the year but received $2.4 million in proceeds from several smaller transactions, which was not deducted from the total above.
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The following table lists wells spud and total capital expenditures by basin for the full-year 2008:
| | | | | |
| | | Year ended
December 31, 2008 |
Basin | | Wells
Spud
(gross) | | Capital
Expenditures
(millions) |
Uinta | | 75 | | $ | 223.7 |
Piceance | | 135 | | | 249.8 |
Powder River | | 203 | | | 36.9 |
Wind River | | 2 | | | 33.0 |
Paradox | | 6 | | | 30.6 |
Other | | 9 | | | 27.1 |
| | | | | |
Total | | 430 | | $ | 601.1 |
| | | | | |
Operating and Drilling Update
Piceance Basin, Colorado
Gibson Gulch – Current net production is approximately 92 million cubic feet equivalent per day (MMcfe/d), and the Company plans to operate a two-rig program through 2009. The Piceance program continues to be a key, low-risk, high growth development area for the Company and offers flexibility to adjust the number of active rigs dependent upon the Company’s capital strategy.
At year-end 2008, the Piceance development project had 372.1 Bcfe in proved reserves and 1.1 trillion cubic feet equivalent (Tcfe) of proved, probable and possible resources. The proved, probable and possible resources include 10-acre development across the Company’s Piceance acreage where, to date, the Company has drilled 108 successful wells on 10-acre density. During 2008, the Company added 60 MMcf/d of compression capacity, increasing project capacity to 140 MMcf/d.
Piceance Basin activity is subject to regulations of the Colorado Oil and Gas Conservation Commission, which has adopted new rules that go into effect April 1, 2009. While the Company expects to be able to execute its 2009 program, it believes that the revised rules will cause additional costs and may cause delay for our Colorado operations.
At year-end 2008, the Company had an approximate 94% working interest in production from 424 gross wells in its Gibson Gulch program.
Uinta Basin, Utah
West Tavaputs – Current net production is approximately 89 MMcfe/d, and the Company plans to operate one rig in the area to drill up to 16 wells in 2009.
As already announced, the Record of Decision on the Environmental Impact Statement for full-field development at West Tavaputs has been deferred to President Obama’s administration. Due to the pending transition of certain positions within the Bureau of Land Management and Department of Interior, the Company believes it will be months before the Record of Decision is obtained.
At year-end 2008, the West Tavaputs development project had 320.3 Bcfe in proved reserves and 1.4 Tcfe of proved, probable and possible resources, with the majority of probable and possible resources related to 40-acre density drilling locations. To date in the shallow drilling program (Wasatch/Mesaverde), the Company has drilled 36 successful wells on 40-acre density and has six 20-acre density pilot wells on production with an additional three-well pilot test under evaluation.
The West Tavaputs program continues to offer low-risk growth in the shallow zones as well as upside opportunity through the deep potential of the east and west structures and in the Mancos shale.
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At year-end 2008, the Company had an approximate 96% working interest in production from 130 gross wells in its West Tavaputs shallow and deep programs.
Blacktail Ridge/Lake Canyon – During 2008, the Company moved the infill program in the Blacktail Ridge area into the development phase and drilled 12 wells and in Lake Canyon drilled and completed one well. Currently in the combined area, there are 16 operated and producing wells with gross production capacity of approximately 4,000 barrels of oil per day (Bopd). Oil produced from this area is a yellow wax that incurs an approximate $17 to $20 per barrel sales price deduction from West Texas Intermediate oil price quotes. As a result of current oil prices, infrastructure needs and delays in obtaining permits, activity in this area will be reduced in 2009. Currently, the Company has several wells shut-in affected by marketing and refining constraints and expects that gross production may be limited to approximately 1,000 to 1,500 Bopd during 2009.
Hook – During 2008, the Company drilled one deep well (50% working interest; total depth 7,585 feet) in the Hook prospect targeting the Manning Canyon shale. The well indicated good gas shows and high gas contents from core samples. In March 2009, the Company plans to drill a horizontal well with a 3,700 foot lateral, offsetting the vertical core well. In the shallower Juana Lopez shale gas prospect (100% working interest), the Company recently drilled a 3,900 foot vertical evaluation well that is currently in the testing process.
Powder River Basin, Wyoming
Coal Bed Methane (CBM) – Current CBM net production is approximately 26 MMcf/d, slightly constrained in the Cat Creek area due to insufficient compression capacity. The Company is currently operating one rig through February, at which time winter wildlife stipulations go into effect and drilling activity is stopped through July 2009. Development of this area requires dewatering of wells, which takes an average of six to 12 months. During 2009, the Company will see continued dewatering of wells with production expected to increase by approximately one-third as wells dewater.
At year-end 2008, the Powder River development project had proved reserves of 66.6 Bcf and proved, probable and possible resources of 178.3 Bcf and had an approximate 74% working interest in production from 666 gross CBM wells.
Wind River Basin, Wyoming
Cave Gulch/Bullfrog – During 2008, the Company recompleted the Bullfrog 14-18 well, which became a prolific producer and is currently producing approximately 19.3 MMcf/d gross. The Company has postponed recompletion of the Bullfrog 33-19 well, located along the same fault block, due to currently low natural gas prices.
In the Cave Gulch deep program, the Company spud two wells during 2008, the Cave Gulch 31-32 well (46% working interest) and the East Bullfrog 23-6 well (50% working interest), each targeting the Frontier, Muddy and Lakota formations at 17,000 to 19,000 feet. The Cave Gulch 31-32 well, which tested 1 MMcf/d from the Muddy and Lakota formations, is currently undergoing continued testing in the third Frontier formation and is planned to be recompleted in the first Frontier formation later this year. The East Bullfrog 23-6 well was recently completed in the Muddy and Lakota formations and, while early in the flowback stage, the well is producing more than 6.5 MMcf/d of natural gas to sales.
Paradox Basin, Colorado
Yellow Jacket – As reported earlier, the Company made a significant grass roots discovery at the Yellow Jacket shale gas prospect in the Paradox Basin in southwest Colorado. Gas sales were initiated from the Gothic shale in December 2008, and the Company is currently selling approximately 2 MMcf/d from two wells into temporary taps on Northwest Pipeline. A third completed well is currently shut-in for analysis as the Company continues to adjust completion procedures. The Company has five horizontal Gothic Shale wells in various stages, with three completed, one waiting on completion and one currently drilling. A one rig continuous program is planned for this area in 2009, as the Company will seek to better determine the scope of this discovery. The Company has a 55% working interest in this project.
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Green Jacket – During 2008, the Company drilled one vertical well into the Hovenweep shale, which was re-entered and taken horizontal during the first quarter of 2009. Eight fracture stimulation stages have been selected in the 3,400 foot lateral portion of the well. Completion work is planned for the second quarter of 2009. The Company has a 100% working interest in the Green Jacket prospect.
Montana Overthrust, Montana
Circus – During 2008, the Company drilled four vertical appraisal wells to test the Cody shale and will continue further completion work on these wells during 2009 with plans to drill a horizontal well mid-year 2009. The Company has a 50% working interest in this prospect.
ADDITIONAL FINANCIAL INFORMATION
Guidance
The Company has revised its 2009 guidance as provided on January 22, 2009. As a result of further declines in natural gas prices for 2009 and continued analysis of our capital program, the Company has decided to slow completions at key development properties. The effect of delaying these expenditures will be to reduce earlier forecast 2009 capital expenditures by approximately $50 million and to reduce production guidance by one to four Bcfe. Updated guidance for the full year 2009 consists of:
| | • | | Capital expenditures of up to $350 million |
| | • | | Oil and natural gas production of 84 to 87 Bcfe, representing an 8% to 12% increase over 2008. |
| | • | | Lease operating costs per Mcfe of $0.60 to $0.66, which is up from the 2008 average of $0.57 due to anticipated higher water handling costs in certain areas and other increased expenses. |
| | • | | Gathering and transportation costs per Mcfe of $0.55 to $0.60, which is up from the 2008 average of $0.51 due to increased processing and transportation costs. |
| | • | | General and administrative expenses before noncash stock-based compensation between $41 and $43 million, in-line with 2008 on a per unit basis. |
FOURTH QUARTER AND YEAR-END 2008 WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held later this morning to discuss fourth quarter and year-end results. Please join Bill Barrett Corporation executive management at noon eastern time/10:00 a.m. Mountain time for the live webcast, accessed atwww.billbarrettcorp.com, or join by telephone by calling 866-543-6405 (617-213-8897 international callers) with passcode 32362105. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through February 27, 2009 at call-in number 888-286-8010 (617-801-6888 international) with passcode 95113119. The Company has also tentatively scheduled its 2009 quarterly reporting dates and conference calls for May 5, August 4 and November 3. Quarterly conference calls are tentatively scheduled for noon eastern time/10:00 a.m. Mountain time on each of these dates
DISCLOSURE STATEMENTS
Reserve and resource disclosure:
The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this press release, such as probable and possible resources, that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. U.S. investors are urged to consider closely the disclosure in our Form 10-K, for the year-ended December 31, 2008, and Form 10-Q, for the quarter ended September 30, 2008, available from Bill Barrett Corporation at 1099 18th Street, Suite 2300, Denver, CO 80202. You can also obtain these forms from the SEC by calling 1-800-SEC-0330 or atwww.sec.gov.
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Forward-looking statements:
This press release contains forward-looking statements, including statements regarding projected results and future events. In particular, the Company is providing “2009 Guidance,” which contain projections for certain 2009 operational and financial results. 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, 2008 filed with the Securities and Exchange Commission (“SEC”), and subsequent filings including our 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, exploration drilling and test results, transportation, processing, availability and costs of financing to fund the Company’s operations, the ability to receive drilling and other permits and regulatory approvals, governmental regulations, availability of third party gathering, market conditions, oil and gas price volatility, risks related to hedging activities including counterparty viability, 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, surface access and costs, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, competition, risks associated with operating in one major geographic area, the success of the Company’s risk management activities, 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. 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, 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 Websitewww.billbarrettcorp.com.
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BILL BARRETT CORPORATION
Selected Operating Highlights
(Unaudited)
| | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | Year Ended
December 31, |
| | | 2008 | | 2007 | | 2008 | | 2007 |
Production Data: | | | | | | | | | | | | |
Natural gas (MMcf) | | | 19,449 | | | 16,497 | | | 73,623 | | | 57,678 |
Oil (MBbls) | | | 188 | | | 123 | | | 661 | | | 586 |
Combined volumes (MMcfe) | | | 20,577 | | | 17,235 | | | 77,589 | | | 61,194 |
Daily combined volumes (Mmcfe/d) | | | 224 | | | 187 | | | 212 | | | 168 |
Average Prices (before the effects of realized hedges): | | | | | | | | | | | | |
Natural gas (per Mcf) | | $ | 4.09 | | $ | 4.17 | | $ | 7.05 | | $ | 4.37 |
Oil (per Bbl) | | | 42.54 | | | 75.06 | | | 83.27 | | | 61.18 |
Combined (per Mcfe) | | | 4.25 | | | 4.52 | | | 7.40 | | | 4.71 |
Average Prices (includes effects of hedges): | | | | | | | | | | | | |
Natural gas (per Mcf) (1) | | $ | 6.86 | | $ | 5.97 | | $ | 7.61 | | $ | 5.89 |
Oil (per Bbl) | | | 51.88 | | | 66.57 | | | 69.55 | | | 59.87 |
Combined (per Mcfe) | | | 6.96 | | | 6.19 | | | 7.81 | | | 6.13 |
Average Costs (per Mcfe): | | | | | | | | | | | | |
Lease operating expense | | $ | 0.58 | | $ | 0.51 | | $ | 0.57 | | $ | 0.68 |
Gathering and transportation expense | | | 0.47 | | | 0.46 | | | 0.51 | | | 0.38 |
Production tax expense | | | 0.34 | | | 0.45 | | | 0.57 | | | 0.37 |
Depreciation, depletion and amortization | | | 2.75 | | | 2.73 | | | 2.66 | | | 2.87 |
General and administrative expense, excluding stock-based compensation | | | 0.50 | | | 0.56 | | | 0.52 | | | 0.52 |
| (1) | The average realized prices for the fourth quarter and full-year 2008 include $1.0 million and $0.06 million, respectively, in net realized gains related to Mid-continent hedges that were not designated as cash flow hedges. These gains are reported as a component of Commodity derivative gain in the Statement of Operations. |
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BILL BARRETT CORPORATION
Consolidated Statements of Operations
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
(in thousands, except per share amounts) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Operating and Other Revenues: | | | | | | | | | | | | | | | | |
Oil and gas production (1) | | $ | 142,122 | | | $ | 106,762 | | | $ | 605,881 | | | $ | 374,956 | |
Commodity derivative gain (1) | | | 4,273 | | | | — | | | | 7,920 | | | | — | |
Other | | | 380 | | | | 2,220 | | | | 4,110 | | | | 15,314 | |
| | | | | | | | | | | | | | | | |
Total operating and other revenues | | | 146,775 | | | | 108,982 | | | | 617,911 | | | | 390,270 | |
| | | | | | | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | | | | | | |
Lease operating | | | 11,927 | | | | 8,711 | | | | 44,318 | | | | 41,643 | |
Gathering and transportation | | | 9,596 | | | | 7,898 | | | | 39,342 | | | | 23,163 | |
Production tax | | | 7,005 | | | | 7,828 | | | | 44,410 | | | | 22,744 | |
Exploration | | | 5,204 | | | | 1,993 | | | | 8,139 | | | | 8,755 | |
Impairment, dry hole costs and abandonment (2) | | | 26,447 | | | | 14,841 | | | | 32,065 | | | | 25,322 | |
Depreciation, depletion and amortization | | | 56,518 | | | | 47,126 | | | | 206,316 | | | | 172,054 | |
General and administrative (3) | | | 10,330 | | | | 9,599 | | | | 40,454 | | | | 32,074 | |
Non-cash stock-based compensation (3) | | | 4,656 | | | | 3,212 | | | | 16,752 | | | | 10,154 | |
| | | | | | | | | | | | | | | | |
Total operating expenses | | | 131,683 | | | | 101,208 | | | | 431,796 | | | | 335,909 | |
| | | | | | | | | | | | | | | | |
Operating Income | | | 15,092 | | | | 7,774 | | | | 186,115 | | | | 54,361 | |
| | | | | | | | | | | | | | | | |
Other Income and Expense: | | | | | | | | | | | | | | | | |
Interest and other income | | | 364 | | | | 667 | | | | 2,036 | | | | 2,391 | |
Interest expense | | | (4,427 | ) | | | (4,061 | ) | | | (15,834 | ) | | | (12,754 | ) |
| | | | | | | | | | | | | | | | |
Total other income and expense | | | (4,063 | ) | | | (3,394 | ) | | | (13,798 | ) | | | (10,363 | ) |
| | | | | | | | | | | | | | | | |
Income before Income Taxes | | | 11,029 | | | | 4,380 | | | | 172,317 | | | | 43,998 | |
Provision for Income Taxes | | | 4,137 | | | | 1,901 | | | | 64,670 | | | | 17,244 | |
| | | | | | | | | | | | | | | | |
Net Income | | $ | 6,892 | | | $ | 2,479 | | | $ | 107,647 | | | $ | 26,754 | |
| | | | | | | | | | | | | | | | |
Net Income Per Common Share | | | | | | | | | | | | | | | | |
Basic | | $ | 0.15 | | | $ | 0.06 | | | $ | 2.42 | | | $ | 0.61 | |
Diluted | | $ | 0.15 | | | $ | 0.06 | | | $ | 2.39 | | | $ | 0.60 | |
| | | | | | | | | | | | | | | | |
Weighted Average Common Shares Outstanding | | | | | | | | | | | | | | | | |
Basic | | | 44,531 | | | | 44,170 | | | | 44,432 | | | | 44,050 | |
Diluted | | | 44,637 | | | | 44,945 | | | | 45,037 | | | | 44,677 | |
| | | | | | | | | | | | | | | | |
| (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
December 31, | | Year Ended
December 31, |
| | | 2008 | | | 2007 | | 2008 | | 2007 |
Included in Oil and gas production revenue: | | | | | | | | | | | | | |
Realized gains on cash flow hedges | | $ | 54,599 | | | $ | 28,773 | | $ | 31,900 | | $ | 86,917 |
| | | | | | | | | | | | | |
Included in Commodity derivative gain: | | | | | | | | | | | | | |
Realized gains on derivatives not designated cash flow hedges | | $ | 1,025 | | | $ | — | | $ | 62 | | $ | — |
Unrealized ineffectiveness recognized on derivatives designated cash flow hedges | | | 3,682 | | | | — | | | 6,803 | | | — |
Unrealized gains (losses) on derivatives not designated cash flow hedges | | | (434 | ) | | | — | | | 1,055 | | | — |
| | | | | | | | | | | | | |
Total commodity derivative gain | | $ | 4,273 | | | $ | — | | $ | 7,920 | | $ | — |
| | | | | | | | | | | | | |
| (2) | Fourth quarter and full-year 2008 include impairment charges of $25.3 million related to certain properties located in the Wind River Basin. |
| (3) | 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. |
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BILL BARRETT CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)
| | | | | | |
(in thousands) | | As of
December 31,
2008 | | As of
December 31,
2007 |
Assets: | | | | | | |
Cash and cash equivalents | | $ | 43,063 | | $ | 60,285 |
Other current assets (1) | | | 270,311 | | | 71,142 |
Property and equipment, net | | | 1,561,819 | | | 1,195,832 |
Other noncurrent assets (1) | | | 119,870 | | | 2,428 |
| | | | | | |
Total assets | | $ | 1,995,063 | | $ | 1,329,687 |
| | | | | | |
Liabilities and Stockholders’ Equity: | | | | | | |
Current liabilities | | $ | 225,794 | | $ | 139,568 |
Notes payable under bank credit facility | | | 254,000 | | | 274,000 |
Convertible senior notes | | | 172,500 | | | — |
Other long-term liabilities | | | 254,971 | | | 142,608 |
Stockholders’ equity | | | 1,087,798 | | | 773,511 |
| | | | | | |
Total liabilities and stockholders’ equity | | $ | 1,995,063 | | $ | 1,329,687 |
| | | | | | |
| (1) | At December 31, 2008, the estimated fair value of all of our commodity derivative instruments was a net asset of $313.8 million, comprised of: $200.0 million current assets; $113.8 million non-current assets. This amount will fluctuate quarterly based on estimated future commodity prices. |
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BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
(in thousands) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Operating Activities: | | | | | | | | | | | | | | | | |
Net income | | $ | 6,892 | | | $ | 2,479 | | | $ | 107,647 | | | $ | 26,754 | |
Adjustments to reconcile to net cash provided by operations: | | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 56,518 | | | | 47,126 | | | | 206,316 | | | | 172,054 | |
Impairment, dry hole costs and abandonment costs | | | 26,447 | | | | 14,841 | | | | 32,065 | | | | 25,322 | |
Unrealized derivative gain | | | (3,248 | ) | | | — | | | | (7,858 | ) | | | — | |
Deferred income taxes | | | 4,454 | | | | 1,927 | | | | 64,060 | | | | 17,270 | |
Stock-based compensation and other non-cash charges | | | 4,957 | | | | 3,495 | | | | 18,117 | | | | 11,284 | |
Amortization of deferred financing costs | | | 550 | | | | 130 | | | | 1,736 | | | | 482 | |
(Gain) loss on sale of properties | | | 2 | | | | (1,883 | ) | | | (1,132 | ) | | | (13,420 | ) |
| | | | | | | | | | | | | | | | |
Change in assets and liabilities: | | | | | | | | | | | | | | | | |
Accounts receivable | | | (15,568 | ) | | | (24,987 | ) | | | (16,047 | ) | | | 5,900 | |
Prepayments and other assets | | | 4,309 | | | | 68 | | | | (324 | ) | | | (875 | ) |
Accounts payable, accrued and other liabilities | | | (11,280 | ) | | | 10,883 | | | | (7,908 | ) | | | (4,065 | ) |
Amounts payable to oil & gas property owners | | | (3,718 | ) | | | 3,480 | | | | (5,142 | ) | | | 8,276 | |
Production taxes payable | | | (7,556 | ) | | | (4,310 | ) | | | 11,417 | | | | 2,471 | |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 62,759 | | | $ | 53,249 | | | $ | 402,947 | | | $ | 251,453 | |
| | | | | | | | | | | | | | | | |
Investing Activities: | | | | | | | | | | | | | | | | |
Additions to oil and gas properties, including acquisitions | | | (183,670 | ) | | | (126,137 | ) | | | (568,445 | ) | | | (414,925 | ) |
Additions of furniture, equipment and other | | | (2,795 | ) | | | (938 | ) | | | (4,752 | ) | | | (4,640 | ) |
Proceeds from sale of properties | | | 51 | | | | 13,650 | | | | 2,405 | | | | 96,450 | |
| | | | | | | | | | | | | | | | |
Net cash used in investing activities | | $ | (186,414 | ) | | $ | (113,425 | ) | | $ | (570,792 | ) | | $ | (323,115 | ) |
| | | | | | | | | | | | | | | | |
Financing Activities: | | | | | | | | | | | | | | | | |
Proceeds from debt | | | 80,000 | | | | 67,000 | | | | 319,800 | | | | 164,000 | |
Principal payments on debt | | | — | | | | — | | | | (167,300 | ) | | | (78,000 | ) |
Proceeds from sale of common stock | | | 11 | | | | 1,866 | | | | 4,082 | | | | 5,098 | |
Deferred financing costs and other | | | (697 | ) | | | (391 | ) | | | (5,959 | ) | | | (473 | ) |
| | | | | | | | | | | | | | | | |
Net cash provided by financing activities | | $ | 79,314 | | | $ | 68,475 | | | $ | 150,623 | | | $ | 90,625 | |
| | | | | | | | | | | | | | | | |
Increase (Decrease) in Cash and Cash Equivalents | | | (44,341 | ) | | | 8,299 | | | | (17,222 | ) | | | 18,963 | |
Beginning Cash and Cash Equivalents | | | 87,404 | | | | 51,986 | | | | 60,285 | | | | 41,322 | |
| | | | | | | | | | | | | | | | |
Ending Cash and Cash Equivalents | | $ | 43,063 | | | $ | 60,285 | | | $ | 43,063 | | | $ | 60,285 | |
| | | | | | | | | | | | | | | | |
10
BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow (1) from Net Income
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
(in thousands, except per unit amounts) | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Net income | | $ | 6,892 | | | $ | 2,479 | | | $ | 107,647 | | | $ | 26,754 | |
Adjustments to reconcile to discretionary cash flow: (1) | | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 56,518 | | | | 47,126 | | | | 206,316 | | | | 172,054 | |
Impairment, dry hole and abandonment costs | | | 26,447 | | | | 14,841 | | | | 32,065 | | | | 25,322 | |
Exploration expense | | | 5,204 | | | | 1,993 | | | | 8,139 | | | | 8,755 | |
Unrealized derivative gain | | | (3,248 | ) | | | — | | | | (7,858 | ) | | | — | |
Deferred income taxes | | | 4,454 | | | | 1,927 | | | | 64,060 | | | | 17,270 | |
Stock compensation and other non-cash charges | | | 4,957 | | | | 3,495 | | | | 18,117 | | | | 11,284 | |
Amortization of deferred financing | | | 550 | | | | 130 | | | | 1,736 | | | | 482 | |
Gain on disposal of properties | | | 2 | | | | (1,883 | ) | | | (1,132 | ) | | | (13,420 | ) |
| | | | | | | | | | | | | | | | |
Discretionary cash flow (1) | | $ | 101,776 | | | $ | 70,108 | | | $ | 429,090 | | | $ | 248,501 | |
| | | | | | | | | | | | | | | | |
Per share, diluted | | $ | 2.28 | | | $ | 1.56 | | | $ | 9.53 | | | $ | 5.56 | |
Per Mcfe | | $ | 4.95 | | | $ | 4.07 | | | $ | 5.53 | | | $ | 4.06 | |
| (1) | Discretionary cash flow is computed as net income plus depreciation, depletion, and amortization, impairment expenses, deferred income taxes, dry hole costs and abandonment expenses, exploration expenses, non-cash stock-based compensation, losses (gains) on disposals of properties, and certain other non-cash charges. The non-GAAP measure of discretionary cash flow is presented because management believes that it provides useful additional information to investors for analysis of the Company’s ability to internally generate funds for exploration, development and acquisitions. In addition, discretionary cash flow is 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 many investors use the published research of industry research analysts in making investment decisions. |
Discretionary cash flow 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 accounting principles generally accepted in the United States of America (“GAAP”). Because discretionary cash flow excludes some, but not all, items that affect net income and net cash provided by operating activities and may vary among companies, the discretionary cash flow amounts presented may not be comparable to similarly titled measures of other companies.
11
BILL BARRETT CORPORATION
Costs Incurred and Reserve Information
(Unaudited)
| | | | | | | | | | | | |
($ in millions) | | 2008 | | | 2007 | | | 2006 | |
TOTAL CAPITAL EXPENDITURES | | $ | 601.1 | | | $ | 443.7 | | | $ | 501.2 | |
Furniture, fixtures and equipment and real estate | | | (4.8 | ) | | | (4.9 | ) | | | (3.2 | ) |
Asset retirement obligation | | | 8.2 | | | | 1.0 | | | | 6.3 | |
| | | | | | | | | | | | |
TOTAL COSTS INCURRED | | $ | 604.5 | | | $ | 439.8 | | | $ | 504.3 | |
| | | | | | | | | | | | |
TOTAL COSTS INCURRED DISCLOSURE | | | | | | | | | | | | |
Exploration costs | | $ | 342.9 | | | $ | 250.7 | | | $ | 224.2 | |
Development costs | | | 214.0 | | | | 162.5 | | | | 114.6 | |
Acquisition costs: | | | | | | | | | | | | |
Unproved properties | | | 33.1 | | | | 23.6 | | | | 126.1 | |
Proved properties | | | 6.3 | | | | 2.0 | | | | 33.1 | |
Asset retirement obligation | | | 8.2 | | | | 1.0 | | | | 6.3 | |
| | | | | | | | | | | | |
TOTAL COSTS INCURRED | | | 604.5 | | | | 439.8 | | | | 504.3 | |
less: Asset retirement obligation | | | (8.2 | ) | | | (1.0 | ) | | | (6.3 | ) |
less: Proceeds received from JV partners (1) | | | — | | | | (12.1 | ) | | | (52.5 | ) |
less: Deferred tax component of CH4 acquisition | | | — | | | | 1.6 | | | | (36.8 | ) |
less: Capitalized interest | | | (2.0 | ) | | | (1.6 | ) | | | (1.0 | ) |
| | | | | | | | | | | | |
Adjusted costs incurred (2) | | $ | 594.3 | | | $ | 426.7 | | | $ | 407.7 | |
| | | | | | | | | | | | |
RESERVE ADDITIONS (Bcfe) | | | | | | | | | | | | |
Extensions, discoveries and other additions | | | 196.2 | | | | 175.7 | | | | 147.7 | |
Revisions of previous estimates based on performance (3) | | | 146.4 | | | | 34.8 | | | | 12.4 | |
Revisions of previous estimates based on price | | | (7.3 | ) | | | 19.4 | | | | (33.8 | ) |
Purchases of reserves in place | | | 3.1 | | | | 2.7 | | | | 19.5 | |
| | | | | | | | | | | | |
RESERVE ADDITIONS | | | 338.4 | | | | 232.6 | | | | 145.8 | |
| | | | | | | | | | | | |
SALES INFORMATION | | | | | | | | | | | | |
Property sales (1) | | $ | 2.4 | | | $ | 84.4 | | | $ | 35.1 | |
Sales of reserves (Bcfe) | | | 0.1 | | | | 42.2 | | | | 6.2 | |
| (1) | The sum of proceeds from joint venture partners and property sales equals “Proceeds from sales of properties” from the Consolidated Statement of Cash Flows, with the exception of 2006, which includes $9.2 million for non-cash proceeds from the Montana Overthrust sell-down. |
| (2) | Finding and developments cost is a non-GAAP metric commonly used in the exploration and production industry. The calculation presented by the Company on page 1 is the quotient of “Adjusted costs incurred” divided by “Reserve additions.” The calculation may not be comparable to similarly titled measures provided by other companies. |
| (3) | At year-end 2008, the reserve revision was primarily the result of adding increased density proved undeveloped locations in the Piceance and West Tavaputs fields and improved production performance by wells located in each of our major producing basins: Wind River, Uinta, Powder and Piceance. |
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