Exhibit 99.1
For immediate release
Company contact: Jennifer Martin, Director of Investor Relations, 303-312-8155
Bill Barrett Corporation Reports Third Quarter 2009 Results
DENVER – November 3, 2009 – Bill Barrett Corporation (NYSE: BBG) today reported third quarter 2009 operating results highlighted by:
| | • | | Production of 22.8 Bcfe, up 16% from the prior year period and up 3% sequentially |
| | • | | Discretionary cash flow of $107.7 million, or $2.39 per diluted common share and $4.73 per Mcfe |
| | • | | Net income of $0.7 million, or $0.02 per diluted share, and adjusted net income of $7.9 million, or $0.18 per diluted share |
| | • | | Increased borrowing base on credit facility to $630 million following October bank redetermination |
| | • | | Encouraging results to date at Yellow Jacket prospect from larger fracture stimulations |
Chairman and Chief Executive Officer Fred Barrett commented: “Our team has met the challenges of a difficult market head-on throughout 2009. Third quarter and year-to-date results reflect increased production as well as growth in discretionary cash flows. Exploration and development expenditures will be well within discretionary cash flows for the year and will deliver production growth of 13% to 15%. As a result, we have further increased production guidance for 2009 to 88.0 to 89.0 billion cubic feet equivalent (Bcfe; see page 5 for details.) Year-to-date, we have been busy evaluating multiple projects on the exploration front and, not surprisingly, we have had both encouraging and disappointing results. At Yellow Jacket, we are encouraged with the performance to date from our two latest horizontal well completions. Our exploration strategy is to target large scale, repeatable resource plays like Yellow Jacket. However, in the Circus and Pine Ridge prospects, results to date, do not appear to meet these criteria, and we have expensed our exploration wells in these areas. Into the fourth quarter, we continue to benefit from operating and drilling efficiencies in core areas, favorable hedge positions and a very strong balance sheet.
“As 2009 nears a close, we are positioning ourselves for 2010. In October 2009, our borrowing base was increased and our lender commitments returned to the levels prior to our July debt offering, providing a solid $573 million in liquidity. To date, we have 55.9 Bcfe hedged for 2010 at an average floor price of $7.43 per thousand cubic feet equivalent (Mcfe) and will opportunistically add to these positions. While we are currently preparing our 2010 plan, we expect to align our capital program with cash flows while delivering continued production growth. Our exceptional financial strength will allow us to be flexible over the coming months as we continue to monitor market conditions. In addition, we are working hard to deliver key growth catalysts such as the EIS process at West Tavaputs and resolution with stakeholders in our Cottonwood Gulch area.”
Third quarter 2009 natural gas and oil production totaled 22.8 Bcfe, up 16% from 19.6 Bcfe in the third quarter of 2008 and up 3% from 22.1 Bcfe in the second quarter of 2009. For the first nine months of 2009, production totaled 67.0 Bcfe, an increase of 17% compared with the first nine months of 2008. Despite a significant decline in natural gas and oil market prices in the third quarter of 2009 compared with the third quarter of 2008, the Company was able to realize strong production revenue through its effective hedging program. The Company’s commodity hedging program increased its third quarter 2009 natural gas and oil revenues by $69.8 million, or more than $3.00 per Mcfe. Including the effects of hedging activities, the average sales price realized in the third quarter of 2009 was $7.03 per Mcfe, down from $7.86 per Mcfe in the third quarter of 2008 yet up from $6.64 per Mcfe in the second quarter of 2009.
Discretionary cash flow (a non-GAAP measure, see page 12) in the third quarter of 2009 was $107.7 million, or $2.39 per diluted common share, up 2% from $105.6 million, or $2.34 per diluted common share, in the third quarter of 2008. Higher production, a $0.07 per Mcfe decline in lease operating expense and a $0.40 per Mcfe decline in production taxes drove the increased discretionary cash flow. These benefits more than offset an $0.83 per Mcfe decline in the average realized price from $7.86 to $7.03 and a $0.19 per Mcfe increase in gathering and transportation expenses. (See per unit metrics on page 8.) The decline in lease operating expense is primarily due to lower water handling costs at West Tavaputs, and the lower production tax expense is primarily a result of significantly lower wellhead prices. Higher gathering and transportation expenses relate to natural gas processing charges and increased firm transportation charges with expansion of the Rockies Express Pipeline system. During the third quarter of 2009, the Company elected to process and sell natural gas liquids from the Piceance Basin, and the higher processing fees were more than offset by proceeds from the sale of resulting natural gas liquids. Discretionary cash flow for the first nine months of 2009 was $345.2 million, or $7.69 per diluted common share, up 5% compared with $327.3 million, or $7.24 per diluted common share, in the first nine months of 2008.
Net income in the third quarter of 2009 was $0.7 million, or $0.02 per diluted common share, compared with $35.3 million, or $0.78 per diluted common share, in the prior year period. Net income included a $12.3 million unrealized commodity derivative loss and a nominal gain on property sales. Adjusting for these items, tax effected, adjusted net income (a non-GAAP measure, see page 12) was $7.9 million, or $0.18 per diluted common share, compared with $29.3 million, or $0.65 per diluted share, in the prior year period. For the first nine months of 2009, net income was $37.7 million, down from $99.1 million in the first nine months of 2008, and adjusted net income was $63.0 million, down from $95.5 million in the first nine months of 2008. Net income includes dry hole costs of $17.7 million for the third quarter of 2009 (related to three exploratory areas, details provided below) and $27.1 million for the first nine months of 2009, or $10.4 million and $16.5 million after tax, respectively.
DEBT AND LIQUIDITY
The Company ended the third quarter of 2009 with $33.0 million drawn on its revolving credit facility and had outstanding 5% Convertible Senior Notes in the principal amount of $172.5 million and 9.875% Senior Notes due 2016 in the principal amount of $250.0 million. In October 2009, the Company’s borrowing base under its bank credit facility increased to $630.0 million from $537.5 million with commitments of $592.8 million. Currently, $20 million is drawn on the credit facility, providing $572.8 million in available borrowing capacity. The Company has significant liquidity available from cash flows from operations and the credit facility to fund its planned capital programs.
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OPERATIONS
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital expenditures by basin for the three and nine months ended September 30, 2009:
| | | | | | | | | | | | | | |
| | | Three Months ended September 30, 2009 | | Nine Months ended September 30, 2009 |
| Basin | | Average Net
Production
(Mmcfe/d) | | Wells
Spud
(gross) | | Capital
Expenditures
(millions) | | Average Net
Production
(Mmcfe/d) | | Wells
Spud
(gross) | | Capital
Expenditures
(millions) |
| | | | | | |
Piceance | | 99 | | 41 | | $ | 57.5 | | 98 | | 81 | | $ | 203.2 |
Uinta | | 91 | | 0 | | | 16.9 | | 91 | | 16 | | | 80.1 |
Powder River (CBM) | | 36 | | 11 | | | 2.5 | | 32 | | 23 | | | 11.4 |
Wind River | | 21 | | 0 | | | 0.3 | | 24 | | 0 | | | 1.7 |
Other | | 1 | | 1 | | | 8.7 | | 1 | | 6 | | | 32.1 |
| |
| | | | | | |
Total | | 248 | | 53 | | $ | 85.9 | | 245 | | 126 | | $ | 328.5 |
| |
Third quarter 2009 capital expenditures totaled $85.9 million, bringing the total spent to $328.5 through the third quarter of 2009, including the $60 million Cottonwood Gulch acquisition. Exploration and development capital expenditures are expected to be less than discretionary cash flow and allocated approximately 80% to 85% to development projects at the Company’s key assets in the Piceance, Uinta and Powder River basins and approximately 15% to 20% to delineation of prior discoveries and on-going exploration activities. The Company has three rigs currently drilling, all of which are operating in the Piceance Basin, as well as a smaller rig operating in the Powder River Basin. As a result of improved drilling efficiencies, mainly in the Piceance Basin, the Company anticipates participating in the drilling of 170 to 180 total wells for the full year 2009, up from the previous estimate of 165 to 175 wells. This includes approximately 40 to 45 coal bed methane (CBM) wells.
Operating and Drilling Update
Piceance Basin, Colorado
Gibson Gulch – Current net production is approximately 102 million cubic feet equivalent per day (MMcfe/d) and the Company anticipates a 2009 exit rate of approximately 107 MMcfe/d. Piceance operations continue to improve. Year-to-date drilling times have averaged seven days spud-to-spud compared with 11 days one year ago. As a result, the Company expects improved costs on a per well basis and now plans to drill a 115 to 120 well program in the area for 2009. The Company currently has 140 MMcf/d gross operating compression capacity in the area and anticipates adding an additional 22 MMcf/d of capacity during 2010. The Gibson Gulch 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 September 30, 2009, the Company had an approximate 96% working interest in production from 506 gross wells in its Gibson Gulch program.
Cottonwood Gulch – The Company has a 90% working interest in 40,300 undeveloped acres in Cottonwood Gulch. The Company continues to work with stakeholders to arrive at a mutually satisfactory resolution of matters related to responsible development of this area.
Uinta Basin, Utah
West Tavaputs – Current net production is approximately 83 MMcfe/d, and the Company anticipates a 2009 exit rate of approximately 74 MMcfe/d. The Company has completed its 2009 drilling and completions program and continues to work with the BLM and other stakeholders toward approval of the Record of Decision on the Environmental Impact Statement for full-field development at West Tavaputs, which is targeted for the first half of 2010.
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In the shallow development drilling program (Wasatch/Mesaverde), 40-acre density drilling continues successfully at Peter’s Point, and the Company remains encouraged by 20-acre density results at Prickly Pear. The West Tavaputs program offers low-risk growth in the shallow Mesaverde and Wasatch zones as well as upside opportunity through the Mancos shale.
At September 30, 2009, the Company had an approximate 97% working interest in production from 167 gross wells in its West Tavaputs shallow and deep programs.
Blacktail Ridge/Lake Canyon – Currently in the combined area, there are 19 operated wells with gross production capacity of approximately 3,600 barrels of oil equivalent per day (Boepd), most of which were returned to production during the quarter following completion of additional natural gas gathering capacity. In the first quarter of 2010, additional gathering and compression capacity is scheduled to be completed by a third party, which should provide sufficient capacity for the Company’s anticipated 2010 program. The Company anticipates initiating new drilling activity near year-end and maintaining a one-rig program in the area through 2010. The working interests in this area range from 19% to 100%.
Hook – In the deep Hook prospect (50% working interest) targeting the Manning Canyon shale, the Company drilled and completed its first horizontal well, the State 16H. The well flowed natural gas at a sub-commercial rate and was expensed as a dry hole in the third quarter of 2009. Although the well was not commercial, the Company will conduct further analysis of a longer horizontal section and improved completion techniques, building on the knowledge gained from this initial well, and will consider a second horizontal well in the area. Also during the third quarter of 2009, the Company expensed the costs associated with the second shallow well into the Juana Lopez horizon as well as the Woodside well previously drilled.
Powder River Basin, Wyoming
Coal Bed Methane (CBM) – Current CBM net production is approximately 35 MMcf/d, and the Company anticipates a 2009 exit rate of approximately 38 MMcf/d. Drilling activity recommenced in August 2009 with the end of seasonal wildlife stipulations, and the Company expects its 2009 drilling program for the area to include participation in a total of 40 to 45 CBM wells. Development of this area requires dewatering of wells, which takes an average of six to 12 months.
At September 30, 2009, the Company had an approximate 73% working interest in production from 644 gross CBM wells.
Wind River Basin, Wyoming
Cave Gulch/Bullfrog/Cave Gulch Deep – Current net production from the area is approximately 18 MMcfe/d, including the Bullfrog 14-18 recompletion well (94% working interest) that continues to be a strong producer. The Company anticipates a 2009 exit rate of approximately 13 MMcf/d.
Paradox Basin, Colorado
Yellow Jacket – At the Yellow Jacket shale gas discovery (55% working interest), targeting the Gothic shale, the Company continued to adjust completion techniques in order to improve well performance. All wells are now completed. The most recent completion technique was applied to one full lateral and one-half lateral and included substantially larger fracture stimulations than used on earlier well completions. To date, flow rates are encouraging. The larger completion of the full Koskie 13H-27 wellbore has been on production for 38 days at an average rate of 2.1 MMcf/d, and the well is currently flowing 2.4 MMcf/d. The one-half lateral completion of the Neely 13H-18 well has produced for 12 days at an average rate of 2.3 MMcf/d and is currently
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producing 2.1 MMcf/d. The Company will continue to monitor data from these wells before designing its 2010 capital program for the area. The Company currently has seven wells on production producing 5.7 MMcf/d (gross) and approximately 312,000 gross and 141,000 net undeveloped acres in the prospect.
Pine Ridge/Salt Flank - During the third quarter of 2009, the Company completed testing the first well in its Pine Ridge exploration prospect, a structural salt flank play. The well was drilled in 2008 to approximately 10,000 feet targeting the Cutler and Honaker Trail formations. The well did not produce commercial quantities of gas and was expensed as a dry hole during the third quarter of 2009. The Company has several prospects in the salt flank play.
Montana Overthrust, Montana
Circus – During the third quarter, the Company completed testing three vertical wells drilled during 2008 targeting the Cody shale. Well results varied but were non-commercial and included gas flows up to 1.1 MMcf/d, oil flows up to 117 bopd and significant quantities of water. As a result, four vertical wells in the area were expensed during the third quarter of 2009. The Company focused on this horizon to identify a large, repeatable natural gas resource play, but test results instead indicate more complex geology than anticipated that is not aligned with the Company’s strategy and timeline for development.
ADDITIONAL FINANCIAL INFORMATION
Guidance
The Company’s 2009 guidance is updated to include:
| | • | | Capital expenditures of approximately $350 million before acquisitions, unchanged from the previous estimate, or $410 million including the Cottonwood Gulch acquisition |
| | • | | Oil and natural gas production of 88 to 89 Bcfe, up from 86 to 88 Bcfe, which represents growth of 13% to 15% over 2008 |
| | • | | Lease operating costs per Mcfe of $0.53 to $0.54, narrowed from $0.53 to $0.55 |
| | • | | Gathering and transportation costs per Mcfe of $0.63 to $0.65, increased from $0.56 to $0.59 due to increased processing charges associated with natural gas liquids sales |
| | • | | General and administrative expenses before non-cash stock-based compensation between $39.0 and $40.0 million, narrowed and slightly reduced from $39.5 to $41.0 million |
Commodity Hedges Update
During the third quarter of 2009, the Company had hedges in place for 72% of its natural gas production volumes and 56% of its oil production volumes, which resulted in a net increase in natural gas revenues of $68.6 million and an increase in oil revenues of $1.2 million. The net effect increased the average price received per Mcfe to $7.03 from $3.97.
It is the Company’s strategy to typically hedge 50% to 70% of production through basis to regional sales points for the next 12 months on a rolling basis. 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.
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For the fourth quarter of 2009 through 2011, 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 2009, approximately 15.3 Bcfe, or approximately 69% to 73% of projected production, at a weighted average blended floor price of $7.46 per Mcfe. |
| | • | | For 2010, approximately 55.9 Bcfe at a weighted average blended floor price of $7.43 per Mcfe. These hedges are weighted more heavily through the third quarter of 2010 when summer natural gas prices tend to be lower. |
| | • | | For 2011, approximately 32.4 Bcfe at a weighted average blended floor price of $6.71 per Mcfe. |
Swaps and Collars
| | | | | | | | | | | | |
| | | Natural Gas | | Oil | | Equivalent |
| Period | | Volume
(MMBtu/d) | | Price
($/MMBtu) | | Volume
(bopd) | | Price
($/bbl) | | Volume
(MMcfe) | | Price
($/Mcfe) |
4Q09 | | 175,712 | | 6.55 | | 1,125 | | 80.27 | | 15,317 | | 7.46 |
| | | | | | |
1Q10 | | 174,000 | | 6.48 | | 800 | | 78.44 | | 14,668 | | 7.30 |
2Q10 | | 184,000 | | 6.65 | | 800 | | 78.44 | | 15,659 | | 7.48 |
3Q10 | | 184,000 | | 6.65 | | 800 | | 78.44 | | 15,831 | | 7.48 |
4Q10 | | 111,728 | | 6.55 | | 800 | | 78.44 | | 9,786 | | 7.47 |
| | | | | | |
1Q11 | | 92,500 | | 6.35 | | — | | — | | 7,568 | | 6.99 |
2Q11 | | 112,500 | | 5.98 | | — | | — | | 9,307 | | 6.58 |
3Q11 | | 112,500 | | 5.98 | | — | | — | | 9,409 | | 6.58 |
4Q11 | | 72,717 | | 6.18 | | — | | — | | 6,082 | | 6.80 |
The Company also has natural gas basis only hedges in place, none of which are currently in the money, including:
| | • | | For the fourth quarter of 2009: 1,530,000 MMBtu at an average differential of ($1.85) per MMBtu |
| | • | | For 2010: 12,940,000 MMBtu at an average differential of ($2.42) per MMBtu. |
| | • | | For 2011: 7,300,000 MMBtu at an average differential of ($1.72) per MMBtu. |
THIRD QUARTER 2009 WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held later this morning to discuss third quarter 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 800-261-3417 (617-614-3673 international callers) with passcode 83530527. 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 6, 2009 at call-in number 888-286-8010 (617-801-6888 international) with passcode 30551192. The Company has also tentatively scheduled its 2010 earnings conference calls for February 23, May 4, August 3 and November 2, each at noon Eastern time/10:00 a.m. Mountain time.
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UPCOMING EVENTS
Investor Conferences
Updated investor presentations are posted on the homepage of the Company’s website atwww.billbarrettcorp.com. Please check the website prior to investor events for the most recent presentation.
Chief Financial Officer and Treasurer Bob Howard plans to present at the Bank of America Merrill Lynch 2009 Credit Conference on December 3, 2009 at 3:00 p.m. Eastern time. The event will be webcast and may be accessed live and for replay on the Company’s website.
Chairman and CEO Fred Barrett plans to present at the Wells Fargo Exploration and Production, Energy Services and Utility Symposium on December 9, 2009 at 2:30 p.m. Eastern time. The event will be webcast and may be accessed live and for replay on the Company’s website.
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 providing updated “2009 Guidance,” and certain general guidelines for 2010 capital expenditures. 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 and Form 10-Q, 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, the ability to receive drilling and other permits and regulatory approvals, governmental regulations, transportation, processing, availability and costs of financing to fund the Company’s operations, availability of third party gathering, market conditions, supply and demand changes and resulting 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, the impact of commodity price changes on reserve estimates, 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
September 30, | | Nine Months Ended
September 30, |
| | | | | 2009 | | 2008 | | 2009 | | 2008 |
| |
Production Data: | | | | | | | | | | | | | | |
Natural gas (MMcf) | | | | | 21,711 | | | 18,568 | | | 63,859 | | | 54,173 |
Oil (MBbls) | | | | | 180 | | | 172 | | | 517 | | | 473 |
Combined volumes (MMcfe) | | | | | 22,791 | | | 19,600 | | | 66,961 | | | 57,011 |
Daily combined volumes (MMcfed) | | | | | 248 | | | 213 | | | 245 | | | 208 |
Average Prices (before the effects of realized hedges): | | | | | | | | | | | | | | |
Natural gas (per Mcf) | | | | $ | 3.70 | | $ | 7.10 | | $ | 3.48 | | $ | 8.11 |
Oil (per Bbl) | | | | | 56.53 | | | 102.98 | | | 43.59 | | | 99.47 |
Combined (per Mcfe) | | | | | 3.97 | | | 7.63 | | | 3.66 | | | 8.53 |
Average Prices (includes the effects of realized hedges): | | | | | | | | | | | | | | |
Natural gas (per Mcf) | | | | $ | 6.86 | | $ | 7.57 | | $ | 7.02 | | $ | 7.87 |
Oil (per Bbl) | | | | | 63.30 | | | 79.07 | | | 55.76 | | | 76.57 |
Combined (per Mcfe) | | | | | 7.03 | | | 7.86 | | | 7.12 | | | 8.12 |
Average Costs (per Mcfe): | | | | | | | | | | | | | | |
Lease operating expense | | | | $ | 0.57 | | $ | 0.64 | | $ | 0.52 | | $ | 0.57 |
Gathering and transportation expense | | | | | 0.71 | | | 0.52 | | | 0.60 | | | 0.52 |
Production tax expense | | (1) | | | 0.29 | | | 0.69 | | | 0.18 | | | 0.66 |
Depreciation, depletion and amortization | | | | | 2.93 | | | 2.53 | | | 2.83 | | | 2.63 |
General and administrative expense, excluding stock-based compensation | | (2) | | | 0.45 | | | 0.50 | | | 0.44 | | | 0.53 |
| (1) | Production tax expense for the nine months ended September 30, 2009 includes a one-time benefit to reduce and re-estimate prior periods as a result of an agreement with the State of Colorado regarding certain calculations of severance taxes. Exclusive of the one-time benefit, the production tax expense per unit would have been $0.25 for the nine-month period. |
| (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 Statements of Operations
(Unaudited)
| | | | | | | | | | | | | | | | | | | |
| | | | | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
(in thousands, except per share amounts) | | | | | | | | (As Adjusted) | | | | | | (As Adjusted) | |
Operating and Other Revenues: | | | | | | | | | | | | | | | | | | | |
Oil and gas production | | (1 | ) | | $ | 161,719 | | | $ | 155,050 | | | $ | 479,455 | | | $ | 463,759 | |
Commodity derivative gain (loss) | | (1 | ) | | | (13,693 | ) | | | 8,490 | | | | (48,612 | ) | | | 3,647 | |
Other | | | | | | 734 | | | | 875 | | | | 1,547 | | | | 3,730 | |
Total operating and other revenues | | | | | | 148,760 | | | | 164,415 | | | | 432,390 | | | | 471,136 | |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Operating Expenses: | | | | | | | | | | | | | | | | | | | |
Lease operating | | | | | | 13,005 | | | | 12,548 | | | | 34,921 | | | | 32,391 | |
Gathering and transportation | | | | | | 16,260 | | | | 10,103 | | | | 40,012 | | | | 29,746 | |
Production tax | | (2 | ) | | | 6,547 | | | | 13,519 | | | | 11,850 | | | | 37,405 | |
Exploration | | | | | | 630 | | | | 1,010 | | | | 2,172 | | | | 2,935 | |
Impairment, dry hole costs and abandonment | | | | | | 19,103 | | | | 463 | | | | 29,834 | | | | 5,618 | |
Depreciation, depletion and amortization | | | | | | 66,742 | | | | 49,681 | | | | 189,459 | | | | 149,798 | |
General and administrative | | (3 | ) | | | 10,291 | | | | 9,704 | | | | 29,193 | | | | 30,124 | |
Non-cash stock-based compensation | | (3 | ) | | | 4,343 | | | | 3,950 | | | | 12,081 | | | | 12,096 | |
Total operating expenses | | | | | | 136,921 | | | | 100,978 | | | | 349,522 | | | | 300,113 | |
Operating Income | | | | | | 11,839 | | | | 63,437 | | | | 82,868 | | | | 171,023 | |
Other Income and Expense: | | | | | | | | | | | | | | | | | | | |
Interest and other income | | | | | | 44 | | | | 805 | | | | 294 | | | | 1,672 | |
Interest expense | | (4 | ) | | | (9,746 | ) | | | (5,067 | ) | | | (20,098 | ) | | | (14,039 | ) |
Total other income and expense | | | | | | (9,702 | ) | | | (4,262 | ) | | | (19,804 | ) | | | (12,367 | ) |
Income before Income Taxes | | | | | | 2,137 | | | | 59,175 | | | | 63,064 | | | | 158,656 | |
Provision for Income Taxes | | (4 | ) | | | 1,419 | | | | 23,860 | | | | 25,325 | | | | 59,518 | |
Net Income | | (4 | ) | | $ | 718 | | | $ | 35,315 | | | $ | 37,739 | | | $ | 99,138 | |
| | | | | |
| | | | | | | | | | | | | | | | | | | | |
Net Income Per Common Share | | | | | | | | | | | | | | | | | | | |
Basic | | | | | $ | 0.02 | | | $ | 0.79 | | | $ | 0.84 | | | $ | 2.23 | |
Diluted | | | | | $ | 0.02 | | | $ | 0.78 | | | $ | 0.84 | | | $ | 2.19 | |
| | | | | |
| | | | | | | | | | | | | | | | | | | | |
Weighted Average Common Shares Outstanding | | | | | | | | | | | | | | | | | | | |
Basic | | | | | | 44,758 | | | | 44,493 | | | | 44,703 | | | | 44,399 | |
Diluted | | | | | | 45,109 | | | | 45,056 | | | | 44,899 | | | | 45,184 | |
| | (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 period indicated: |
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
Included in oil and gas production revenue: | | | | | | | | | | | | | | | | |
Realized gains (losses) on cash flow hedges | | $ | 71,210 | | | $ | 5,457 | | | $ | 234,664 | | | $ | (22,699 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Included in commodity derivative loss: | | | | | | | | | | | | | | | | |
Realized losses on derivatives not designated cash flow hedges | | $ | (1,423 | ) | | $ | (963 | ) | | $ | (2,446 | ) | | $ | (963 | ) |
Unrealized ineffectiveness gains (losses) recognized on derivatives designated cash flow hedges | | | 741 | | | | 5,687 | | | | (5,721 | ) | | | 3,121 | |
Unrealized gains (losses) on derivatives not designated cash flow hedges | | | (13,011 | ) | | | 3,766 | | | | (40,445 | ) | | | 1,489 | |
| | | | | | | | | | | | | | | | |
Total commodity derivative gain (loss) | | $ | (13,693 | ) | | $ | 8,490 | | | $ | (48,612 | ) | | $ | 3,647 | |
| | | | | | | | | | | | | | | | |
| | (2) | Production tax expense for the 2009 nine-month period includes a one-time benefit to reduce and re-estimate prior periods as a result of an agreement with the State of Colorado regarding certain calculations of severance taxes. |
| | (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. |
| | (4) | Effective January 1, 2009, the Company adopted financial reporting rule FSP ABP 14-1, which was incorporated into Accounting Standard Codification (ASC) Subtopic 470-20, to account for convertible debt instruments that may be settled in cash upon conversion. The new rule applies a fair value to the equity conversion feature of the debt and results in reporting the convertible notes at a discount to the principal value. The debt discount is amortized as non-cash interest expense over the expected term of the convertible notes. The 2008 financial statements have been adjusted to reflect the changed accounting treatment. |
9
BILL BARRETT CORPORATION
Consolidated Condensed Balance Sheets
(Unaudited)
| | | | | | | | | |
| | | | | | As of
September 30, 2009 | | As of
December 31, 2008 |
| |
(in thousands) | | | | | | | (As Adjusted) |
| |
Assets: | | | | | | | | | |
| |
Cash and cash equivalents | | | | | $ | 53,551 | | $ | 43,063 |
Other current assets | | (1 | ) | | | 131,431 | | | 270,311 |
Property and equipment, net | | | | | | 1,668,133 | | | 1,561,819 |
Other noncurrent assets | | (1 | ) | | | 25,825 | | | 119,300 |
| |
Total assets | | | | | $ | 1,878,940 | | $ | 1,994,493 |
| |
|
| |
Liabilities and Stockholders’ Equity: | | | | | | | | | |
| |
Current liabilities | | (1 | ) | | $ | 164,060 | | $ | 225,794 |
Notes payable under bank credit facility | | | | | | 33,000 | | | 254,000 |
Senior notes | | (2 | ) | | | 238,179 | | | — |
Convertible senior notes | | (3 | ) | | | 157,358 | | | 153,411 |
Other long-term liabilities | | (1 | ) | | | 263,779 | | | 262,055 |
Stockholders’ equity | | | | | | 1,022,564 | | | 1,099,233 |
| |
Total liabilities and stockholders’ equity | | | | | $ | 1,878,940 | | $ | 1,994,493 |
| |
| (1) | At September 30, 2009, the estimated fair value of all of our commodity derivative instruments was a net asset of $66.8 million, comprised of: $79.0 million current assets; $15.4 million non-current assets; $8.5 million current liabilities; and $19.1 million non-current liabilities. This amount will fluctuate quarterly based on estimated future commodity prices. |
| (2) | The 9.875% Senior Notes were issued at a 95.172% discount to par and have a principal amount of $250.0 million. |
| (3) | Effective January 1, 2009, the Company adopted financial reporting rule FSP ABP 14-1, which was incorporated into ASC Subtopic 470-20, to account for convertible debt instruments that may be settled in cash upon conversion. This rule applies a fair value to the equity conversion feature of the debt and results in reporting the convertible notes at a discount to the principal value. The debt discount is amortized as non-cash interest expense over the expected term of the convertible notes. The 2008 financial statements have been adjusted to reflect the changed accounting treatment. The principal amount of the notes is $172.5 million. |
10
BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| | |
(in thousands) | | | | | (As Adjusted) | | | | | | (As Adjusted) | |
| | |
Operating Activities: | | | | | | | | | | | | | | | | |
| | |
Net income | | $ | 718 | | | $ | 35,315 | | | $ | 37,739 | | | $ | 99,138 | |
Adjustments to reconcile to net cash provided by operations: | | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 66,742 | | | | 49,681 | | | | 189,459 | | | | 149,798 | |
Impairment, dry hole costs and abandonment costs | | | 19,103 | | | | 463 | | | | 29,834 | | | | 5,618 | |
Unrealized derivative loss (gain) | | | 12,270 | | | | (9,453 | ) | | | 46,166 | | | | (4,610 | ) |
Deferred income taxes | | | 1,419 | | | | 23,155 | | | | 20,871 | | | | 58,591 | |
Stock compensation and other non-cash charges | | | 4,529 | | | | 4,273 | | | | 13,075 | | | | 13,160 | |
Amortization of deferred financing costs | | | 2,381 | | | | 1,692 | | | | 5,953 | | | | 3,818 | |
Gain on sale of properties | | | (100 | ) | | | (561 | ) | | | (34 | ) | | | (1,134 | ) |
| | |
Change in assets and liabilities: | | | | | | | | | | | | | | | | |
Accounts receivable | | | (5,421 | ) | | | 30,391 | | | | 19,845 | | | | (479 | ) |
Prepayments and other assets | | | (672 | ) | | | 1,535 | | | | (1,842 | ) | | | (4,633 | ) |
Accounts payable, accrued and other liabilities | | | 3,901 | | | | 175 | | | | 12,913 | | | | 3,372 | |
Amounts payable to oil & gas property owners | | | 1,285 | | | | (4,070 | ) | | | (5,435 | ) | | | (1,424 | ) |
Production taxes payable | | | 4,523 | | | | 8,693 | | | | 4,273 | | | | 18,973 | |
| | |
| | | | |
Net cash provided by operating activities | | $ | 110,678 | | | $ | 141,289 | | | $ | 372,817 | | | $ | 340,188 | |
| | |
Investing Activities: | | | | | | | | | | | | | | | | |
| | |
Additions to oil and gas properties, including acquisitions | | | (85,814 | ) | | | (161,320 | ) | | | (372,820 | ) | | | (384,775 | ) |
Additions of furniture, equipment and other | | | (1,364 | ) | | | (491 | ) | | | (3,287 | ) | | | (1,957 | ) |
Proceeds from sale of properties | | | — | | | | 715 | | | | 2,714 | | | | 2,354 | |
| | |
| | | | |
Net cash used in investing activities | | $ | (87,178 | ) | | $ | (161,096 | ) | | $ | (373,393 | ) | | $ | (384,378 | ) |
| | |
Financing Activities: | | | | | | | | | | | | | | | | |
| | |
Proceeds from credit facility | | | — | | | | 20,000 | | | | 100,000 | | | | 67,300 | |
Principal payments on credit facility | | | (266,000 | ) | | | (265 | ) | | | (321,000 | ) | | | (167,300 | ) |
Proceeds from issuance of senior convertible notes | | | — | | | | — | | | | — | | | | 172,500 | |
Proceeds from issuance of 9.875% senior notes | | | 237,930 | | | | — | | | | 237,930 | | | | — | |
Offering costs | | | (5,543 | ) | | | (150 | ) | | | (6,440 | ) | | | (5,164 | ) |
Proceeds from sale of common stock | | | 146 | | | | 627 | | | | 628 | | | | 4,071 | |
Deferred financing costs and other | | | (5 | ) | | | (9 | ) | | | (54 | ) | | | (98 | ) |
| | |
| | | | |
Net cash provided by (used in) financing activities | | $ | (33,472 | ) | | $ | 20,203 | | | $ | 11,064 | | | $ | 71,309 | |
| | |
|
| | |
Increase (Decrease) in Cash and Cash Equivalents | | | (9,972 | ) | | | 396 | | | | 10,488 | | | | 27,119 | |
| | | | |
Beginning Cash and Cash Equivalents | | | 63,523 | | | | 87,008 | | | | 43,063 | | | | 60,285 | |
| | |
| | | | |
Ending Cash and Cash Equivalents | | $ | 53,551 | | | $ | 87,404 | | | $ | 53,551 | | | $ | 87,404 | |
| | |
11
BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income from Net Income
(Unaudited)
Discretionary Cash Flow Reconciliation
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
(in thousands, except per share amounts) | | | | | (As Adjusted) | | | | | | (As Adjusted) | |
Net Income | | $ | 718 | | | $ | 35,315 | | | $ | 37,739 | | | $ | 99,138 | |
| | | | |
Adjustments to reconcile to discretionary cash flow: | | | | | | | | | | | | | | | | |
Depreciation, depletion and amortization | | | 66,742 | | | | 49,681 | | | | 189,459 | | | | 149,798 | |
Impairment, dry hole costs and abandonment costs | | | 19,103 | | | | 463 | | | | 29,834 | | | | 5,618 | |
Exploration expense | | | 630 | | | | 1,010 | | | | 2,172 | | | | 2,935 | |
Unrealized derivative loss (gain) | | | 12,270 | | | | (9,453 | ) | | | 46,166 | | | | (4,610 | ) |
Deferred income taxes | | | 1,419 | | | | 23,155 | | | | 20,871 | | | | 58,591 | |
Stock compensation and other non-cash charges | | | 4,529 | | | | 4,273 | | | | 13,075 | | | | 13,160 | |
Amortization of deferred financing and discount on convertible notes | | | 2,381 | | | | 1,692 | | | | 5,953 | | | | 3,818 | |
Gain on sale of properties | | | (100 | ) | | | (561 | ) | | | (34 | ) | | | (1,134 | ) |
Discretionary Cash Flow | | $ | 107,692 | | | $ | 105,575 | | | $ | 345,235 | | | $ | 327,314 | |
| | | | |
Per share, diluted | | $ | 2.39 | | | $ | 2.34 | | | $ | 7.69 | | | $ | 7.24 | |
Per Mcfe | | $ | 4.73 | | | $ | 5.39 | | | $ | 5.16 | | | $ | 5.74 | |
| | | | |
| Adjusted Net Income Reconciliation | | | | | | | | | | | | | | | | |
| | |
| | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
(in thousands except per share amounts) | | | | | (As Adjusted) | | | | | | (As Adjusted) | |
Net Income | | $ | 718 | | | $ | 35,315 | | | $ | 37,739 | | | $ | 99,138 | |
| | | | |
Adjustments to net income: | | | | | | | | | | | | | | | | |
Unrealized derivative loss (gain) | | | 12,270 | | | | (9,453 | ) | | | 46,166 | | | | (4,610 | ) |
Gain on sale of properties | | | (100 | ) | | | (561 | ) | | | (34 | ) | | | (1,134 | ) |
One time items: | | | | | | | | | | | | | | | | |
Production tax expense | | | — | | | | — | | | | (4,796 | ) | | | — | |
Subtotal Adjustments | | | 12,170 | | | | (10,014 | ) | | | 41,336 | | | | (5,744 | ) |
Effective tax rate | | | 41 | % | | | 40 | % | | | 39 | % | | | 38 | % |
Tax effected adjustments | | | 7,180 | | | | (5,976 | ) | | | 25,215 | | | | (3,589 | ) |
Adjusted Net Income | | $ | 7,898 | | | $ | 29,339 | | | $ | 62,954 | | | $ | 95,549 | |
| | | | |
Per share, diluted | | $ | 0.18 | | | $ | 0.65 | | | $ | 1.40 | | | $ | 2.11 | |
Per Mcfe | | $ | 0.35 | | | $ | 1.50 | | | $ | 0.94 | | | $ | 1.68 | |
The non-GAAP (Generally Accepted Accounting Principals) measures of discretionary cash flow and adjusted net income are presented because management believes that they provide useful additional information to investors for analysis of the Company’s ability to internally generate funds for exploration, development and acquisitions as well as adjusting net income for unusual items to allow for easier comparison from period to period. In addition, these measures are widely used by professional research analysts and others in the valuation, comparison and investment recommendations of companies in the oil and gas exploration and production industry, and many investors use the published research of industry research analysts in making investment decisions.
These measures should not be considered in isolation or as a substitute for net income, income from operations, net cash provided by operating activities or other income, profitability, cash flow or liquidity measures prepared in accordance with GAAP. Because discretionary cash flow and adjusted net income exclude some, but not all, items that affect net income and net cash provided by operating activities and may vary among companies, the amounts presented may not be comparable to similarly titled measures of other companies.
12
