Exhibit 99.1
| | |
 | | Press Release |
For immediate release
Company contact: Jennifer Martin, Director of Investor Relations, 303-312-8155
Bill Barrett Corporation Reports Gothic Shale Gas Discovery
and Third Quarter 2008 Results
DENVER – November 5, 2008 – Bill Barrett Corporation (NYSE: BBG) today reported third quarter 2008 operating results highlighted by:
| | • | | A significant shale gas discovery at the Yellow Jacket prospect in the Paradox Basin in southwest Colorado |
| | • | | Production growth, up 33% from the prior year period to 19.6 billion cubic feet equivalent (Bcfe) |
| | • | | Discretionary cash flow growth, up 93% from the prior year period to $105.6 million or $2.34 per diluted common share and $5.39 per million cubic feet equivalent (Mcfe) of production |
| | • | | Net income growth, up significantly from the prior year period to $36.1 million or $0.80 per diluted common share |
| | • | | A $126 million increase in the revolving credit facility to $593 million, completed subsequent to quarter-end |
Chairman and Chief Executive Officer, Fred Barrett, commented:
“Our Company is very excited about the initial results from the first two horizontal Gothic shale gas wells at the Yellow Jacket prospect in southwest Colorado. The Koskie well produced for 17 days, averaging 4.5 million cubic feet per day (MMcf/d) of natural gas over the final ten days and completed the testing period at a rate of 5.7 MMcf/d. The second horizontal well, the Neely well located 14 miles north of the Koskie discovery, is currently testing early in the flowback stage at 3.1 MMcf/d natural gas. Due to the encouraging results from the wells drilled to date, in 2009 we will operate a continuous program to evaluate the area and will begin construction of infrastructure. This is a widespread but shallow (5,500 to 6,500 feet) resource play where the Company has built a 397,000 gross acre position over the past four years.
“Execution of our development programs continues to deliver growth. During the third quarter, we achieved a record level of production, maintained cash flows consistent with the second quarter 2008 despite a 30% decrease in the average regional natural gas price, and ended the quarter posting the highest quarterly earnings ever in our corporate history.
“2008 is proving to be a very successful year and will position us well for 2009. As the broader market environment presents challenges going into 2009, we will continue to focus on our operating strengths while managing to a disciplined capital program. We will enter 2009 with a strong balance sheet, ample liquidity and a substantial hedging program, all to ensure financial stability and cash flows that support our exploration and development plans.”
Production for the quarter ended September 30, 2008 was 19.6 Bcfe, representing a 33% increase from the third quarter of 2007 and a 2% increase sequentially. For the first nine months of 2008, production totaled 57.0 Bcfe, representing a 30% increase compared with 44.0 Bcfe in the first nine months of 2007. Rocky Mountain regional natural gas prices and oil prices peaked early in the third quarter, then declined significantly. Regional natural gas prices tend to be lowest in the months of September and October due to lower demand as a result of mild seasonal weather. Including the effects of all of the Company’s hedging activities, the average sales price realized in the third quarter of 2008 was $7.86 per Mcfe compared with $5.58 per Mcfe in the third quarter of 2007.
Discretionary cash flow (a non-GAAP measure, see page 13 for explanation and reconciliation) was $105.6 million in the third quarter of 2008, or $2.34 per diluted common share, up 93% compared with the third quarter of 2007. The year-over-year increase was primarily the result of the 33% increase in production and a 41% increase in the average realized price, partially offset by higher per unit gathering and transportation expenses and production taxes. For the first nine months of 2008, discretionary cash flow was $327.3 million, or $7.24 per diluted common share, up 83% compared with $178.4 million, or $4.01 per diluted common share, in the prior year period, also due primarily to increased production and higher commodity prices as well as lower per unit lease operating expenses.
Net income was $36.1 million, or $0.80 per diluted common share, for the third quarter of 2008 compared with $0.2 million, or $0.01 per diluted common share, in the third quarter of 2007. The increase in net income was primarily a result of higher production and a higher per unit profit margin, including reduced per unit depreciation, depletion and amortization expenses. For the first nine months of 2008, net income was $100.8 million, or $2.23 per diluted common share, up from $24.3 million, or $0.55 per diluted common share, in the prior year period, also as a result of higher production and a higher per unit profit margin.
DEBT AND LIQUIDITY
At September 30, 2008, borrowings outstanding under the Company’s revolving credit facility were $174.0 million, and the Company also had outstanding 5% convertible senior notes in the amount of $172.5 million. Subsequent to quarter-end, the Company increased the borrowing capacity on its revolving line of credit to $592.8 million from $467.0 million, providing pro forma availability of $418.8 million at quarter-end. The Company is comfortable with its available financing and the status of all of its credit metrics.
OPERATIONS
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital expenditures by basin for the third quarter and first nine months of 2008:
| | | | | | | | | | | | | | |
| | | Third Quarter 2008 | | Nine Months Ended
September 30, 2008 |
Basin | | Average Net
Production
(MMcfe/d) | | Wells
Spud
(gross) | | Capital
Expenditures
(millions) | | Average Net
Production
(MMcfe/d) | | Wells
Spud
(gross) | | Capital
Expenditures
(millions) |
Uinta | | 71 | | 25 | | $ | 78.8 | | 76 | | 51 | | $ | 156.0 |
Piceance | | 86 | | 37 | | | 84.0 | | 85 | | 98 | | | 188.3 |
Powder River | | 25 | | 52 | | | 12.2 | | 21 | | 165 | | | 28.9 |
Wind River | | 30 | | 1 | | | 9.0 | | 26 | | 2 | | | 24.0 |
Other | | 1 | | 4 | | | 12.8 | | — | | 7 | | | 26.6 |
| | | | | | | | | | | | | | |
Total | | 213 | | 119 | | $ | 196.8 | | 208 | | 323 | | $ | 423.8 |
| | | | | | | | | | | | | | |
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Capital expenditures totaled $196.8 million in the third quarter of 2008 and $423.8 for the first nine months of 2008. The Company expects its full year 2008 capital expenditures to range between $590 and $610 million, a reduction from previous guidance of $625 to $650 million, as a result of adjusting fourth quarter activity towards lower levels now planned for 2009. The Company continues to expect that expenditures will be allocated approximately 80% to development projects at its key assets in the Uinta, Piceance and Powder River Basins and approximately 20% on delineation of prior discoveries and new exploration. The Company has 12 rigs currently drilling and anticipates participating in the drilling of 465 to 470 gross wells for the full year 2008, including approximately 240 coal bed methane (CBM) wells.
Operating and Drilling Update
Uinta Basin, Utah
West Tavaputs – Current net production is approximately 71 MMcfe/d. Production during the quarter was reduced by the need to shut-in certain wells while drilling on previously producing well pads. During the third quarter, the Company operated three rigs in the area and is on track to spud nearly 60 wells at West Tavaputs in 2008. The Company expects to exit 2008 at a net production rate of approximately 76 MMcfe/d. As the Company prepares for its 2009 capital program, the number of active rigs will be gradually reduced from three to one by year-end 2008.
The Company currently anticipates the Record of Decision on the Environmental Impact Statement for full-field development of West Tavaputs by the end of January 2009. This schedule includes a contingency time period for extended consultation with the State of Utah and cultural preservation agencies.
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. At the end of the third quarter 2008, the Company had an approximate 97% working interest in production from 117 gross wells in its West Tavaputs shallow and deep programs.
Blacktail Ridge/Lake Canyon – Following encouraging results in the Blacktail Ridge area, the Company has moved the infill program into the development phase and continues to drill extension wells to the southwest to determine potential expansion of the field. The Company plans to operate a continuous one-rig program through 2009.
Currently in the area, there are 13 operated producing wells with gross production averaging approximately 1,300 barrels of oil equivalent per day (boepd) for the month of October. The Company continues to optimize the producing wells testing the productivity of selected depth intervals, completion methods and geologic areas.
Hook – The Company reached total depth at 7,585 feet with its first well (50% working interest) in the Hook prospect, targeting the Manning Canyon shale. Gas shows were encountered within 589 feet of Manning Canyon shale. More than 400 feet of core is being evaluated for rock properties and gas content. The Company plans to drill a horizontal well in this area in the first quarter of 2009. At the nearby Juana Lopez (Ferron coal equivalent) shale gas prospect, the Company has spud a 3,000 foot evaluation well.
Piceance Basin, Colorado
Gibson Gulch – Current net production is approximately 87 MMcfe/d. Operations in the Piceance Basin continue to be executed as projected. The Company currently has four rigs operating in the area, down from five in October, including one purpose-built rig added in late August. Operations are on track to spud 130-plus wells in 2008 and to exit 2008 with a net production rate of 96 MMcfe/d.
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As the Company prepares for its 2009 capital program, the number of active rigs will be gradually reduced to two at year-end 2008. The reduced level of activity in the Piceance will also accommodate a transition to the new comprehensive Colorado rules, some of which are expected to be effective in early 2009.
Drilling results on 10-acre density continue to be positive with 84 successful 10-acre wells drilled year-to-date. During August 2008, the Company added two compressors totaling 30 MMcf/d capacity at the Bailey station and is adding a third compressor having 20 MMcf/d capacity mid-fourth quarter. The Piceance program continues to be a key, low-risk, high growth development area for the Company.
At the end of the third quarter of 2008, the Company had an approximate 94% working interest in production from 390 gross wells in its Gibson Gulch program.
Powder River Basin, Wyoming
Coal Bed Methane (CBM) – Current CBM net production is approximately 24 MMcfe/d and the Company has two rigs operating in the area. Big George CBM production continues to slowly ramp-up; however, production remains constrained in the Cat Creek area due to insufficient compression capacity. During the third quarter, production was initiated from the Pumpkin Creek area and new production is expected to begin this month in the Willow Creek and Dobrenz Ranch areas, supporting a projected 2008 exit rate of approximately 27 MMcfe/d. The Company expects to operate two rigs in the area until wildlife stipulations go into effect in February 2009.
At the end of the third quarter of 2008, the Company had an approximate 74% working interest in production from 690 gross CBM wells.
Wind River Basin, Wyoming
Cave Gulch/Bullfrog – During the third quarter, the Company’s prolific Bullfrog 14-18 Frontier well (94% working interest) continued to produce approximately 20 MMcf/d gross. In November 2008, the Company expects to recomplete a similar opportunity along the same fault block. This recompletion effort was delayed from its original September timing due to low natural gas prices.
The Cave Gulch deep drilling program currently includes the 31-32 well (46% working interest) and the 23-6 well (50% working interest at casing point election) each targeting the Frontier, Muddy and Lakota formations at 17,000 to 19,000 feet. The 31-32 well reached total depth at 18,731 feet, and the Company is producing a nominal 1 MMcf/d from the Muddy and Lakota formations. The Frontier formation will be completed later this year with results expected by year-end. The 23-6 well was spud in late September and is expected to reach total depth in December.
Paradox Basin, Colorado
Yellow Jacket – The first horizontal test well, Koskie (55% working interest), is a natural gas discovery in the Gothic Shale that flowed an average of 4.5 MMcf/d of 1,200 British thermal units (Btus) per standard cubic foot (Scf) gas and yielded 20 barrels of condensate per MMcf during the final ten days of a 17 day test. The well produced at a final rate of 5.7 MMcf/d prior to being shut-in and awaiting connection to sales, which are expected to commence in December. At the second horizontal well, the Neely, the Company successfully completed an eight-stage fracture stimulation along a 3,655 foot lateral. While early in the flowback process, the well flowed 3.1 MMcf/d over the final three days of a seven day test. Further, the Company drilled a vertical well nine miles north of the Neely well in order to obtain core information and to evaluate field extension and spud during the last week of October a third horizontal well, the 15H-27, an offset to the Koskie horizontal well.
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The Company is planning a comprehensive delineation program for the area and production facilities and gathering infrastructure are being installed for sales later this year. The Company is also working with its partner and the pipelines in the area to determine long term processing and transportation alternatives. Both TransColorado and Northwest pipelines are located within the project area, which is approximately 60 miles northwest of the San Juan Basin. The Company has built a sizable acreage position in the area, which including the Green Jacket area is approximately 397,000 gross acres and 208,000 net undeveloped acres.
Green Jacket – A 5,800 foot vertical well (100% working interest) to test the Hovenweep shale is expected to spud in the fourth quarter 2008. The Green Jacket area is located west of Yellow Jacket. The Hovenweep shale is similar to the Gothic shale yet at slightly shallower depths.
Salt Flank – The Company reached total depth at 8,506 feet at its first Pine Ridge well (80% working interest), where good to excellent gas shows and porosity were noted in the targeted Cutler and Honaker Trail formations. Due to winter closures, testing of the well will be delayed until mid-2009.
Montana Overthrust, Montana
Circus – During the third quarter of 2008, the Company concluded drilling four appraisal wells planned for 2008 to analyze and test the Cody shale. Two of the four wells were cored extensively, and the Company is currently completing and testing the first well, including collecting micro-seismic data on the fracture stimulations. The Company will continue further completion work in the area in 2009. Production from this area will depend on the discovery of commercial quantities of natural gas to support construction of infrastructure. The Company has a 50% working interest in this potential regional resource play.
ADDITIONAL FINANCIAL INFORMATION
Guidance
The Company is updating its 2008 full year guidance as follows:
| | • | | Oil and natural gas production of 77.0 to 78.5 Bcfe, which implies a growth rate over 2007 of 26% to 28%. The range is narrowed from the previous estimate of 77 to 80 Bcfe |
| | • | | Lease operating costs of $0.60 to $0.61 per Mcfe, reduced from $0.64 to $0.68 |
| | • | | Gathering and transportation costs of $0.52 to $0.55 per Mcfe, down from $0.54 to $0.59 |
| | • | | General and administrative expenses before non-cash stock-based compensation between $39.5 and $40.5 million, revised from $38 to $40 million |
| | • | | Capital budget to range between $590 and $610 million, down from $625 to $650 million |
Commodity Hedges Update
During the third quarter of 2008, the Company had hedges in place for approximately 71% of its natural gas production volumes and approximately 64% of its oil production volumes, which resulted in an increase in natural gas revenues of $8.6 million and a reduction in oil revenues of $4.1 million. The net effect increased the average price received per Mcfe to $7.86 from $7.63.
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For the remainder of 2008, the Company has hedges in place for approximately 15 Bcfe, or approximately 70% to 75% of projected production, at a weighted average blended floor price of $7.06 per MMBtu natural gas (or approximately $7.77 per Mcf) and $73.71 per barrel of oil. The Company also has hedges in place for approximately 60 Bcfe in 2009 at a weighted average blended floor price of $7.17 per MMBtu natural gas (or approximately $7.89 per Mcf) and $81.79 per barrel of oil, and approximately 44 Bcfe in 2010 at a weighted average blended floor price of $6.96 per MMBtu natural gas (or approximately $7.66 per Mcf) and $90.00 per barrel of oil. It is the Company’s strategy to typically hedge 50% to 70% of production through basis at regional sales points for the next 12 months on a rolling basis. Hedge positions will occasionally be below or above that range for short periods due to market conditions, but hedge positions will not exceed forecast production. Natural gas and oil hedging is intended to reduce the risks associated with unpredictable future natural gas and oil prices and to provide predictability for a portion of cash flows to support the Company’s capital expenditure program. Counterparties to the Company’s financial hedges are diversified among seven firms, and 99% of the outstanding hedge positions are with participants in the Company’s revolving line of credit.
The following table summarizes swap positions as of November 1, 2008:
| | | | | | | | |
| | | Natural Gas | | Oil |
Period | | Volume
(MMBtu/d) | | Weighted
Average Swap
Price (CIG,TCO
or PEPL/MMBtu) | | Volume
(Bbls/d) | | Weighted
Average Swap
Price (WTI/
Bbl) |
4Q08 | | 116 | | 7.10 | | 575 | | 73.84 |
1Q09 | | 159 | | 7.96 | | 375 | | 74.41 |
2Q09 | | 159 | | 6.89 | | 375 | | 74.41 |
3Q09 | | 159 | | 6.89 | | 375 | | 74.41 |
4Q09 | | 99 | | 7.32 | | 375 | | 74.41 |
1Q10 | | 89 | | 7.69 | | — | | — |
2Q10 | | 142 | | 6.94 | | — | | — |
3Q10 | | 142 | | 6.94 | | — | | — |
4Q10 | | 61 | | 7.02 | | — | | — |
In addition, the Company has hedged certain volumes with collar contracts as follows:
| | | | | | | | | | |
| | | Natural Gas | | Oil |
Period | | Volume
(MMBtu/d) | | Price (CIG or
PEPL/MMBtu) | | Volume
(Bbls/d) | | Price (WTI/Bbl) |
CAL 2008 | | 35 | | $ | 6.50/$10.00 | | 525 | | $ | 70.48/$81.62 |
Nov-Dec 2008 | | 30 | | | 7.83/12.08 | | | | | |
Jun-Dec 2008 | | | | | | | 100 | | | 90.00/160.00 |
CAL 2009 | | 25 | | | 6.45/10.22 | | 550 | | | 86.82/143.51 |
Jan-Mar 2009 | | 20 | | | 8.75/12.53 | | | | | |
Nov-Dec 2009 | | 10 | | | 6.00/9.63 | | | | | |
CAL 2010 | | | | | | | 300 | | | 90.00/163.00 |
Jan-Oct 2010 | | 20 | | | 6.00/10.41 | | | | | |
Apr-Oct 2010 | | 10 | | | 7.00/11.00 | | | | | |
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In addition to the swap and collar arrangements described above, the Company has hedged 3,210,000 MMBtu (or 2.9 Bcf) of anticipated natural gas production for April through October of 2010 with Colorado Interstate Gas (CIG) basis swaps at ($3.20) per MMBtu. A basis swap hedges the price differential between the NYMEX price and the CIG price received.
THIRD QUARTER RESULTS AND FUTURE WEBCASTS AND CONFERENCE CALLS
As previously announced, a webcast and conference call will be held later this morning to discuss third quarter 2008 operating and financial 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 866-742-9716 (832-445-1682 international callers) with passcode 66067282. 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 7, 2008 at call-in number 800-642-1687 (706-645-9291 international callers) with passcode 66067282. The Company has also tentatively scheduled its 2009 quarterly reporting dates and conference calls for February 24, 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
Forward-looking statements:
This press release contains forward-looking statements, including statements regarding projected results and future events. In particular the Company is: confirming and updating 2008 full year guidance, which contains projections for certain 2008 operational and financial results; providing forward-looking statements regarding the Company’s 2009 capital expenditure program and operations plan; and, announcing preliminary results from the Paradox shale gas prospect, including the potential to produce natural gas and condensate from the area in 2009. 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, 2007, filed with the Securities and Exchange Commission on February 27, 2008, and other filings with the SEC, for a description 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, 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, governmental regulations and other factors discussed in the Company’s reports filed with the SEC. The Company 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.
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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
September 30, | | Nine Months Ended
September 30, |
| | | 2008 | | 2007 | | 2008 | | 2007 |
Production Data: | | | | | | | | | | | | |
Natural gas (MMcf) | | | 18,568 | | | 14,226 | | | 54,173 | | | 41,181 |
Oil (MBbls) | | | 172 | | | 85 | | | 473 | | | 463 |
Combined volumes (MMcfe) | | | 19,600 | | | 14,736 | | | 57,011 | | | 43,959 |
Daily combined volumes (Mmcfe/d) | | | 213 | | | 160 | | | 208 | | | 161 |
Average Prices (before the effects of realized hedges): | | | | | | | | | | | | |
Natural gas (per Mcf) | | $ | 7.10 | | $ | 3.28 | | $ | 8.11 | | $ | 4.45 |
Oil (per Bbl) | | | 102.98 | | | 70.57 | | | 99.47 | | | 57.48 |
Combined (per Mcfe) | | | 7.63 | | | 3.57 | | | 8.53 | | | 4.78 |
Average Prices (includes effects of realized hedges): | | | | | | | | | | | | |
Natural gas (per Mcf) (1) | | $ | 7.57 | | $ | 5.36 | | $ | 7.87 | | $ | 5.86 |
Oil (per Bbl) | | | 79.07 | | | 70.26 | | | 76.57 | | | 58.08 |
Combined (per Mcfe) | | | 7.86 | | | 5.58 | | | 8.12 | | | 6.10 |
Average Costs (per Mcfe): | | | | | | | | | | | | |
Lease operating expense | | $ | 0.64 | | $ | 0.67 | | $ | 0.57 | | $ | 0.75 |
Gathering and transportation expense | | | 0.52 | | | 0.33 | | | 0.52 | | | 0.35 |
Production tax expense | | | 0.69 | | | 0.29 | | | 0.66 | | | 0.34 |
Depreciation, depletion and amortization | | | 2.53 | | | 2.92 | | | 2.63 | | | 2.91 |
General and administrative expense, excluding stock-based compensation | | | 0.50 | | | 0.52 | | | 0.53 | | | 0.51 |
(1) | The average realized gas price for the quarter and nine months ended September 30, 2008 includes $1.0 million in realized losses related to Mid-continent hedges that were not designated as cash flow hedges. These losses are reported as a component of Commodity derivative gain in the Statement of Operations. |
9
BILL BARRETT CORPORATION
Consolidated Statements of Operations
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
(in thousands, except per share amounts) | | | | | | | | | | | | | | | | |
Operating and Other Revenues: | | | | | | | | | | | | | | | | |
Oil and gas production | | $ | 155,050 | | | $ | 82,216 | | | $ | 463,759 | | | $ | 268,194 | |
Commodity derivative gain (1) | | | 8,490 | | | | — | | | | 3,647 | | | | — | |
Other | | | 875 | | | | 39 | | | | 3,730 | | | | 13,094 | |
| | | | | | | | | | | | | | | | |
Total operating and other revenues | | | 164,415 | | | | 82,255 | | | | 471,136 | | | | 281,288 | |
| | | | | | | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | | | | | | |
Lease operating | | | 12,548 | | | | 9,846 | | | | 32,391 | | | | 32,932 | |
Gathering and transportation | | | 10,103 | | | | 4,873 | | | | 29,746 | | | | 15,265 | |
Production tax | | | 13,519 | | | | 4,220 | | | | 37,405 | | | | 14,916 | |
Exploration | | | 1,010 | | | | 4,004 | | | | 2,935 | | | | 6,762 | |
Impairment, dry hole costs and abandonment | | | 463 | | | | 3,609 | | | | 5,618 | | | | 10,481 | |
Depreciation, depletion and amortization | | | 49,681 | | | | 43,070 | | | | 149,798 | | | | 124,928 | |
General and administrative (2) | | | 9,704 | | | | 7,610 | | | | 30,124 | | | | 22,475 | |
Non-cash stock-based compensation (2) | | | 3,950 | | | | 2,461 | | | | 12,096 | | | | 6,942 | |
| | | | | | | | | | | | | | | | |
Total operating expenses | | | 100,978 | | | | 79,693 | | | | 300,113 | | | | 234,701 | |
| | | | | | | | | | | | | | | | |
Operating Income: | | | 63,437 | | | | 2,562 | | | | 171,023 | | | | 46,587 | |
| | | | | | | | | | | | | | | | |
Other Income and Expense | | | | | | | | | | | | | | | | |
Interest and other income | | | 805 | | | | 676 | | | | 1,672 | | | | 1,724 | |
Interest expense | | | (3,846 | ) | | | (2,739 | ) | | | (11,407 | ) | | | (8,693 | ) |
| | | | | | | | | | | | | | | | |
Total other income and expense | | | (3,041 | ) | | | (2,063 | ) | | | (9,735 | ) | | | (6,969 | ) |
| | | | | | | | | | | | | | | | |
Income before Income Taxes | | | 60,396 | | | | 499 | | | | 161,288 | | | | 39,618 | |
Provision for Income Taxes | | | 24,331 | | | | 266 | | | | 60,533 | | | | 15,343 | |
| | | | | | | | | | | | | | | | |
Net Income | | $ | 36,065 | | | $ | 233 | | | $ | 100,755 | | | $ | 24,275 | |
| | | | | | | | | | | | | | | | |
Net Income Per Common Share: | | | | | | | | | | | | | | | | |
Basic | | $ | 0.81 | | | $ | 0.01 | | | $ | 2.27 | | | $ | 0.55 | |
Diluted | | $ | 0.80 | | | $ | 0.01 | | | $ | 2.23 | | | $ | 0.55 | |
Weighted Average Common Shares Outstanding: | | | | | | | | | | | | | | | | |
Basic | | | 44,493 | | | | 44,085 | | | | 44,399 | | | | 44,009 | |
Diluted | | | 45,056 | | | | 44,562 | | | | 45,184 | | | | 44,499 | |
| (1) | In accordance with FAS No. 133, there is ineffectiveness associated with a small portion of the value of hedges entered into for forward periods due to slight differences in the delivery point and/or timing of delivery. During the third quarter of 2008, the Company recorded a $5.7 million gain related to this ineffectiveness. In addition, certain transactions, to which Mid-continent natural gas hedges were designated, were deemed no longer probable of occurring. The Company discontinued hedge accounting for these hedges and recorded $3.8 million to gains on commodity derivatives. Total non-cash gains were $9.5 million for the third quarter and $4.6 million year-to-date. In addition, in the third quarter the Company realized a loss of $1.0 million on settlement of hedges not designated as cash flow hedges. |
| (2) | 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)
| | | | | | |
| | | As of
September 30,
2008 | | As of
December 31,
2007 |
(in thousands) | | | | | | |
Assets: | | | | | | |
Cash and cash equivalents | | $ | 87,404 | | $ | 60,285 |
Other current assets (1) | | | 172,065 | | | 71,142 |
Property and equipment, net | | | 1,465,102 | | | 1,195,832 |
Other noncurrent assets (1) | | | 83,287 | | | 2,428 |
| | | | | | |
Total assets | | $ | 1,807,858 | | $ | 1,329,687 |
| | | | | | |
Liabilities and Stockholders’ Equity: | | | | | | |
Current liabilities (1) | | $ | 230,959 | | $ | 139,568 |
Notes payable under bank credit facility | | | 174,000 | | | 274,000 |
Convertible senior notes | | | 172,500 | | | — |
Other long-term liabilities (1) | | | 229,782 | | | 142,608 |
Stockholders’ equity | | | 1,000,617 | | | 773,511 |
| | | | | | |
Total liabilities and stockholders’ equity | | $ | 1,807,858 | | $ | 1,329,687 |
| | | | | | |
| (1) | At September 30, 2008, the estimated fair value of all of our commodity derivative instruments was a net asset of $190.2 million, comprised of: current assets of $113.0 million; non-current assets of $77.4 million; current liabilities of $0.07 million; and non-current liabilities of $0.1 million. This amount will fluctuate quarterly based on estimated future commodity prices. |
11
BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
(in thousands) | | | | | | | | | | | | | | | | |
Operating Activities: | | | | | | | | | | | | | | | | |
Net income | | $ | 36,065 | | | $ | 233 | | | $ | 100,755 | | | $ | 24,275 | |
Adjustments to reconcile to net cash provided by operations: | | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 49,681 | | | | 43,070 | | | | 149,798 | | | | 124,928 | |
Impairment, dry hole costs and abandonment costs | | | 463 | | | | 3,609 | | | | 5,618 | | | | 10,481 | |
Unrealized derivative gain | | | (9,453 | ) | | | — | | | | (4,610 | ) | | | — | |
Deferred income taxes | | | 23,626 | | | | 266 | | | | 59,606 | | | | 15,343 | |
Stock compensation and other non-cash charges | | | 4,273 | | | | 2,967 | | | | 13,160 | | | | 7,789 | |
Amortization of deferred financing costs | | | 471 | | | | 119 | | | | 1,186 | | | | 352 | |
(Gain) loss on sale of properties | | | (561 | ) | | | 459 | | | | (1,134 | ) | | | (11,537 | ) |
Change in assets and liabilities: | | | | | | | | | | | | | | | | |
Accounts receivable | | | 30,391 | | | | 6,128 | | | | (479 | ) | | | 30,887 | |
Prepayments and other assets | | | 1,535 | | | | 1,583 | | | | (4,633 | ) | | | (943 | ) |
Accounts payable, accrued and other liabilities | | | 175 | | | | (13,637 | ) | | | 3,372 | | | | (14,948 | ) |
Amounts payable to oil & gas property owners | | | (4,070 | ) | | | 3,073 | | | | (1,424 | ) | | | 4,796 | |
Production taxes payable | | | 8,693 | | | | 2,301 | | | | 18,973 | | | | 6,781 | |
| | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 141,289 | | | $ | 50,171 | | | $ | 340,188 | | | $ | 198,204 | |
| | | | | | | | | | | | | | | | |
Investing Activities: | | | | | | | | | | | | | | | | |
Additions to oil and gas properties, including acquisitions | | | (161,320 | ) | | | (100,663 | ) | | | (384,775 | ) | | | (288,788 | ) |
Additions of furniture, equipment and other | | | (491 | ) | | | (1,588 | ) | | | (1,957 | ) | | | (3,702 | ) |
Proceeds from sale of properties | | | 715 | | | | (44 | ) | | | 2,354 | | | | 82,800 | |
| | | | | | | | | | | | | | | | |
Net cash used in investing activities | | $ | (161,096 | ) | | $ | (102,295 | ) | | $ | (384,378 | ) | | $ | (209,690 | ) |
| | | | | | | | | | | | | | | | |
Financing Activities: | | | | | | | | | | | | | | | | |
Proceeds from debt | | | 20,000 | | | | 75,000 | | | | 239,800 | | | | 97,000 | |
Principal payments on debt | | | (265 | ) | | | — | | | | (167,300 | ) | | | (78,000 | ) |
Proceeds from sale of common stock | | | 627 | | | | 980 | | | | 4,071 | | | | 3,232 | |
Deferred financing costs and other | | | (159 | ) | | | 2 | | | | (5,262 | ) | | | (82 | ) |
| | | | | | | | | | | | | | | | |
Net cash provided by financing activities | | $ | 20,203 | | | $ | 75,982 | | | $ | 71,309 | | | $ | 22,150 | |
| | | | | | | | | | | | | | | | |
Increase in Cash and Cash Equivalents | | | 396 | | | | 23,858 | | | | 27,119 | | | | 10,664 | |
Beginning Cash and Cash Equivalents | | | 87,008 | | | | 28,128 | | | | 60,285 | | | | 41,322 | |
| | | | | | | | | | | | | | | | |
Ending Cash and Cash Equivalents | | $ | 87,404 | | | $ | 51,986 | | | $ | 87,404 | | | $ | 51,986 | |
| | | | | | | | | | | | | | | | |
12
BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow(1)from Net Income
(Unaudited)
| | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | |
| | | 2008 | | | 2007 | | 2008 | | | 2007 | |
(in thousands, except per unit amounts) | | | | | | | | | | | | | | | |
Net Income | | $ | 36,065 | | | $ | 233 | | $ | 100,755 | | | $ | 24,275 | |
Adjustments to reconcile to discretionary cash flow (1): | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 49,681 | | | | 43,070 | | | 149,798 | | | | 124,928 | |
Impairment, dry hole costs and abandonment costs | | | 463 | | | | 3,609 | | | 5,618 | | | | 10,481 | |
Exploration expense | | | 1,010 | | | | 4,004 | | | 2,935 | | | | 6,762 | |
Unrealized derivative gain | | | (9,453 | ) | | | — | | | (4,610 | ) | | | — | |
Deferred income taxes | | | 23,626 | | | | 266 | | | 59,606 | | | | 15,343 | |
Stock compensation and other non-cash charges | | | 4,273 | | | | 2,967 | | | 13,160 | | | | 7,789 | |
Amortization of deferred financing costs | | | 471 | | | | 119 | | | 1,186 | | | | 352 | |
(Gain) loss on sale of properties | | | (561 | ) | | | 459 | | | (1,134 | ) | | | (11,537 | ) |
| | | | | | | | | | | | | | | |
Discretionary Cash Flow (1) | | $ | 105,575 | | | $ | 54,727 | | $ | 327,314 | | | $ | 178,393 | |
| | | | | | | | | | | | | | | |
Per share, diluted | | $ | 2.34 | | | $ | 1.23 | | $ | 7.24 | | | $ | 4.01 | |
Per Mcfe | | $ | 5.39 | | | $ | 3.71 | | $ | 5.74 | | | $ | 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, amortization of deferred financing costs, 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 generally accepted accounting principles (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.
13
