Exhibit 99.1
| | |
| | Press Release |
For immediate release
Company contact: Jennifer Martin, Director of Investor Relations, 303-312-8155
Bill Barrett Corporation Reports First Quarter 2009 Results
DENVER – May 5, 2009 – Bill Barrett Corporation (NYSE: BBG) today reported first quarter 2009 operating results highlighted by:
| | • | | Production growth, up 21% from the prior year period and up 7% sequentially to 22.1 Bcfe |
| | • | | Discretionary cash flow growth, up 24% from the prior year period and up 32% sequentially to $134.8 million, or $3.01 per diluted share |
| | • | | Net income of $26.4 million and adjusted net income of $39.6 million, or $0.89 per diluted share, up 26% from the prior year period on an adjusted basis |
| | • | | Received reaffirmation of the credit facility borrowing base of $600 million |
Chairman and Chief Executive Officer Fred Barrett commented: “Achieving record high production and discretionary cash flow in the first quarter of 2009 is testament to the Company’s ability to successfully operate under challenging market conditions. The 21% increase in production, combined with favorable hedge positions and continued strong operating efficiencies, supported our particularly strong performance.
“We are financially well positioned for the remainder of 2009 to operate under a difficult macro-economic environment. We are on track to keep our 2009 capital expenditure program for exploration and development aligned with discretionary cash flow. The Company expects to deliver 8% to 12% production growth from our key development assets, while continuing to drill our exciting exploration portfolio during a time when we can take advantage of lower costs. We currently have more than $345 million available on our bank line of credit, we have hedges in place at regional sales points for approximately 70% of remaining 2009 production that have an average floor price of $7.74 per thousand cubic feet equivalent (Mcfe), and we will continue to drive operating efficiencies. We are well-situated to execute our operations strategy and will maintain an opportunistic posture as the year unfolds.”
First quarter 2009 natural gas and oil production totaled 22.1 billion cubic feet equivalent (Bcfe), up 21% from 18.2 Bcfe in the first quarter of 2008 and up 7% sequentially from 20.6 Bcfe. Including the effects of the Company’s hedging activities, the average sales price realized in the first quarter of 2009 was $7.70 per Mcfe compared with $8.19 per Mcfe in the first quarter of 2008. The Company’s commodity hedging program increased its first quarter 2009 natural gas and oil revenues by $87.1 million, more than doubling the average price received.
Discretionary cash flow (a non-GAAP measure, see page 12) in the first quarter of 2009 was $134.8 million, or $3.01 per diluted common share, up 24% from $108.3 million, or $2.40 per diluted common share, in the first quarter of 2008 and up 32% sequentially from $101.8 million. The year-over-year increase was primarily a result of higher oil and gas production revenue, generated by a 21% increase in production, partially offset by a 6% decline in the average realized price received. In addition, first quarter 2009 cash operating income benefitted from lower production tax expense, which was a result of significantly lower wellhead prices and a one-time benefit of $4.4 million to reduce and re-estimate prior period tax expenses following a March 2009 agreement with the State of Colorado regarding certain calculations of severance taxes (see per unit metrics on page 8.)
Net income in the first quarter of 2009 was $26.4 million, or $0.59 per diluted common share, compared with $30.6 million, or $0.68 per diluted common share, in the prior year period. Net
income included a $26.0 million unrealized commodity derivative loss (principally related to basis only hedges), a one-time $4.4 million production tax benefit (discussed above) and a nominal loss on property sales. Adjusting for these items, tax effected, adjusted net income (a non-GAAP measure, see page 12) was $39.6 million or $0.89 per diluted common share.
As required, effective January 1, 2009 the Company adopted financial reporting rule FSP ABP 14-1 to account for convertible debt instruments that may be settled in cash upon conversion (see the Company’s 10-Q filed with the Securities and Exchange Commission for more detail). The new pronouncement requires the Company to record the value of the equity conversion at issuance, which resulted in a $23.1 million discount in value for the Company’s convertible senior notes. This discount is amortized as additional non-cash interest expense over the period the debt is expected to be outstanding, in this case four years through March 2012. As a result, first quarter 2008 financial statements have been adjusted to reflect the changed accounting treatment.
DEBT AND LIQUIDITY
The Company ended the first quarter of 2009 with $276.0 million drawn on its revolving credit facility and has subsequently repaid $30.0 million since March 31, 2009. In April 2009, the Company’s bank group reaffirmed the borrowing base of $600.0 million with commitments of $592.8 million, currently providing $346.8 million in available borrowing capacity. The Company also had outstanding 5% convertible senior notes in the principal amount of $172.5 million. The Company believes it has significant liquidity available from cash flows from operations and the credit facility to fund its planned capital program.
OPERATIONS
Production, Wells Spud and Capital Expenditures
The following table lists production, wells spud and total capital expenditures by basin for the first quarter of 2009:
| | | | | | | |
| | | First Quarter 2009 |
Basin | | Average Net
Production
(MMcfe/d) | | Wells
Spud
(gross) | | Capital
Expenditures
(millions) |
Uinta | | 93.5 | | 8 | | $ | 43.8 |
Piceance | | 95.5 | | 16 | | | 47.3 |
Powder River (CBM) | | 27.2 | | 12 | | | 5.8 |
Wind River | | 27.1 | | — | | | 1.6 |
Paradox | | 1.0 | | 4 | | | 10.1 |
Other | | 1.1 | | — | | | 2.4 |
| | | | | | | |
Total | | 245.4 | | 40 | | $ | 111.0 |
| | | | | | | |
First quarter 2009 capital expenditures totaled $111.0 million. The Company plans to spend up to $350 million for capital expenditures before acquisitions in 2009, intending to align full-year expenditures with discretionary cash flow. The Company will allocate approximately 80% to 85% of expenditures to development projects at its key assets in the Piceance, Uinta and Powder River basins and approximately 15% to 20% to delineation of prior discoveries and new
2
exploration. The Company has three rigs currently drilling, with plans to add a fourth rig in early May, and anticipates participating in the drilling of 145 to 155 wells for the full year 2009, including approximately 50 to 55 coal bed methane (CBM) wells, down from 430 wells in 2008.
Operating and Drilling Update
Piceance Basin, Colorado
Gibson Gulch – Current net production is approximately 100 million cubic feet equivalent per day (MMcfe/d). The Company plans to operate one to two rigs in the area throughout 2009 and has all permits in place to drill a planned 75 to 80 well program. All current year drilling is on 10-acre density. In mid-April 2009, 24 MMcf/d of compression capacity was added in the area, increasing gross capacity to 165 MMcf/d. 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 the end of the first quarter 2009, the Company had an approximate 94% working interest in production from 448 gross wells in its Gibson Gulch program.
Uinta Basin, Utah
West Tavaputs – Current net production is approximately 90 MMcfe/d. The Company has one rig in the area and has drilled eight of the 14 shallow wells planned for 2009, all of which have been permitted.
The Company continues to work towards completion of the Record of Decision on the Environmental Impact Statement for full-field development at West Tavaputs. In the transition to the new administration, appointments and nominees are in the process of being named to critical posts within the Bureau of Land Management and Department of Interior. This leads the Company to believe that authorization could take months to obtain, and we are currently seeking a definitive timeline.
To date in the shallow drilling program (Wasatch/Mesaverde), the Company has increased the density of well spacing to include 42 wells successfully drilled on 40-acre density and early indications from the most recent 20-acre pilot tests are positive. In addition, the Company has continued to drive improvements in operating costs in the West Tavaputs program by reducing water handling charges.
The West Tavaputs program continues to offer low-risk growth in the shallow Mesaverde and Wasatch 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 first quarter 2009, the Company had an approximate 96% working interest in production from 138 gross wells in its West Tavaputs shallow and deep programs.
Blacktail Ridge/Lake Canyon – Currently in the combined area, there are 17 operated and producing wells with gross production capacity of approximately 3,200 barrels of oil per day (Bopd). The Company has shut-in most of its wells due to gas gathering, marketing and refining constraints, which limited first quarter production to an average of approximately 1,000 Bopd gross, or approximately 500 Bopd net. The working interests in this area range from 19% to 100%.
Hook – In the deep Hook prospect (50% working interest), the Company is targeting the Manning Canyon shale at a depth of approximately 8,000 feet. The initial vertical well drilled in 2008
3
indicated good gas shows and high gas contents from core samples, and the Company has spud a horizontal offset well and expects results by mid-summer. The Company also drilled two vertical test wells in the shallower Juana Lopez shale (100% working interest), at approximately 4,000 feet, and plans to complete testing of these wells in 2010.
Powder River Basin, Wyoming
Coal Bed Methane (CBM) – Current CBM net production is approximately 30 MMcf/d, slightly constrained in the Cat Creek area due to insufficient compression capacity. Currently, there is no drilling activity in the region due to seasonal wildlife stipulations that are in effect through July. The Company plans to participate in approximately 50 to 55 CBM wells during 2009. Development of this area requires dewatering of wells, which takes an average of six to 12 months. During 2009, the Company will continue to dewater wells with production expected to increase to approximately 35 MMcf/d in the fourth quarter.
At the end of the first quarter 2009, the Company had an approximate 74% working interest in production from 737 gross CBM wells.
Wind River Basin, Wyoming
Cave Gulch/Bullfrog – The Bullfrog 14-18 recompletion well (94% working interest) continues to be a strong producer, currently averaging approximately 15 MMcf/d gross. Recompletion of the Bullfrog 33-19 well (94% working interest), located along the same fault block, remains postponed due to 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. While the 23-6 continues to produce from the Muddy and Lakota formations, the Company has postponed any further completion activity at these wells until natural gas prices improve.
Paradox Basin, Colorado
Yellow Jacket – At the Yellow Jacket shale gas discovery (55% working interest), the Company has drilled eight horizontal wells in the Gothic shale, is in the process of making its fifth completion and has three wells on production totaling approximately 3 MMcf/d gross. The Company continues to adjust completion and pumping techniques in an effort to mitigate salt migration into the wellbore, including utilization of cemented casing and micro-seismic monitoring during fracture stimulations. The Company and its partner plan to drill approximately ten wells in the prospect during 2009 to help delineate the scope and scale of this discovery. The Company has approximately 307,000 gross and 140,000 net undeveloped acres in the prospect.
Green Jacket – At the Green Jacket prospect (100% working interest), targeting the Hovenweep shale, the Company began completion of its first horizontal well during the second quarter 2009 with results anticipated in the third quarter of 2009. The Company has approximately 150,000 gross and 110,000 net undeveloped acres in the prospect.
Montana Overthrust, Montana
Circus – The Company plans to resume completion work and testing in June 2009 on four vertical wells drilled during 2008 targeting the Cody shale. Depending upon test results, the Company may drill a horizontal well in the third quarter of 2009. The Company has a 50% working interest in this prospect.
4
ADDITIONAL FINANCIAL INFORMATION
Guidance
The Company’s 2009 guidance as provided in February 2009 remains unchanged and includes:
| | • | | Capital expenditures of up to $350 million |
| | • | | Oil and natural gas production of 84 to 87 Bcfe, an 8% to 12% increase over 2008 |
| | • | | Lease operating costs per Mcfe of $0.60 to $0.66 |
| | • | | Gathering and transportation costs per Mcfe of $0.55 to $0.60 |
| | • | | General and administrative expenses before noncash stock-based compensation between $41 and $43 million |
Commodity Hedges Update
During the first quarter of 2009, the Company had hedges in place for 79% of its natural gas production volumes and 49% of its oil production volumes, which resulted in an increase in natural gas revenues of $83.9 million and an increase in oil revenues of $3.2 million. The net effect increased the average price received per Mcfe to $7.70 from $3.76.
For the remainder of 2009 and 2010, the Company has hedges in place as outlined in the table below. These hedge positions include:
| | • | | Swap and collar positions tied to regional sales points for the remaining three quarters of 2009 totaling approximately 44.5 Bcfe, or approximately 70% of projected production for that period. These have a weighted average blended floor price of $6.84 per MMBtu natural gas (or approximately $7.53 per Mcf) and $81.79 per barrel of oil. |
| | • | | Natural gas basis only hedges for the remainder of 2009 totaling 3.0 Bcf natural gas at an average differential of ($2.28) per Mcf. |
| | • | | Swap and collar positions tied to regional sales points for 2010 totaling approximately 45.2 Bcfe. These have a weighted average blended floor price of $6.87 per MMBtu natural gas (or approximately $7.56 per Mcf) and $90.00 per barrel of oil. These hedges are weighted more heavily through the third quarter of 2010 when summer natural gas prices tend to be lower. |
| | • | | Natural gas basis only hedges for 2010 totaling 11.8 Bcf natural gas at an average differential of ($2.66) per Mcf. |
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.
5
The following table summarizes hedge positions as of April 24, 2009:
| | | | | | | | | | | | |
| | | Natural Gas | | Oil |
| | | Swaps and Collars | | Basis Only | | Swaps and Collars |
Period | | Volume
(MMBtu/d) | | Weighted Average
Floor/Swap Price
(CIG/NWPL/PEPL/
TCO/DomApp)
(MMBtu) | | Volume
(MMBtu/d | | Weighted
Average Spread
(CIG/NWPL)
(MMBtu) | | Volume
(Bbls/d) | | Weighted Average
Floor/Swap Price
(WTI/Bbl) |
2Q09 | | 184,000 | | $ 6.83 | | 10,000 | | $ (2.25) | | 925 | | $ 81.79 |
3Q09 | | 184,000 | | 6.83 | | 10,000 | | (2.25) | | 925 | | 81.79 |
4Q09 | | 148,000 | | 6.87 | | 17,000 | | (1.85) | | 925 | | 81.79 |
1Q10 | | 134,000 | | 6.97 | | 30,000 | | (1.92) | | 300 | | 90.00 |
2Q10 | | 167,000 | | 6.82 | | 45,000 | | (2.57) | | 300 | | 90.00 |
3Q10 | | 167,000 | | 6.82 | | 45,000 | | (2.57) | | 300 | | 90.00 |
4Q10 | | 69,000 | | 6.91 | | 22,000 | | (2.47) | | 300 | | 90.00 |
FIRST QUARTER 2009 WEBCAST AND CONFERENCE CALL
As previously announced, a webcast and conference call will be held later this morning to discuss first 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 866-362-4666 (617-597-5313 international callers) with passcode 24739822. The webcast will remain available on the Company’s website for approximately 30 days, and a replay of the call will be available through May 8, 2009 at call-in number 888-286-8010 (617-801-6888 international) with passcode 34495664. The Company has also tentatively scheduled its remaining 2009 quarterly reporting dates and conference calls for 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.
UPCOMING EVENTS
Annual Meeting of Stockholders
The 2009 Annual Meeting of Stockholders of Bill Barrett Corporation will be held on May 14, 2009 at 9:30 a.m. Mountain time. The meeting will be webcast and may be accessed live and for replay on the Company’s website atwww.billbarrettcorp.com.
Investor Conference
Chairman and CEO Fred Barrett plans to present at the Deutsche Bank 2009 Energy, Utilities and Power Conference on May 27, 2009 at 2:50 p.m. eastern time. The event will be webcast and may be accessed live and for replay on the Company’s website atwww.billbarrettcorp.com.
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 “2009 Guidance,” which contain
6
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, 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, 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.
7
BILL BARRETT CORPORATION
Selected Operating Highlights
(Unaudited)
| | | | | | | | |
| | | | | Quarter Ended
March 31, |
| | | | | 2009 | | 2008 |
Production Data: | | | | | | | | |
Natural gas (MMcf) | | | | | 21,073 | | | 17,332 |
Oil (MBbls) | | | | | 169 | | | 144 |
Combined volumes (MMcfe) | | | | | 22,087 | | | 18,196 |
Daily combined volumes (MMcfe/d) | | | | | 245 | | | 200 |
| | | |
Average Prices (before the effects of realized hedges): | | | | | | | | |
Natural gas (per Mcf) | | | | $ | 3.74 | | $ | 8.00 |
Oil (per Bbl) | | | | | 25.00 | | | 84.18 |
Combined (per Mcfe) | | | | | 3.76 | | | 8.29 |
| | | |
Average Prices (includes effects of hedges): | | | | | | | | |
Natural gas (per Mcf) | | | | $ | 7.72 | | $ | 8.02 |
Oil (per Bbl) | | | | | 43.95 | | | 69.83 |
Combined (per Mcfe) | | | | | 7.70 | | | 8.19 |
| | | |
Average Costs (per Mcfe): | | | | | | | | |
Lease operating expense | | | | $ | 0.53 | | $ | 0.51 |
Gathering and transportation expense | | | | | 0.50 | | | 0.52 |
Production tax expense | | (1) | | | 0.04 | | | 0.56 |
Depreciation, depletion and amortization | | | | | 2.66 | | | 2.80 |
General and administrative expense, excluding stock-based compensation | | | | | 0.43 | | | 0.58 |
| (1) | Production tax expense for the 2009 quarter 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 $0.24. |
8
BILL BARRETT CORPORATION
Consolidated Statements of Operations
(Unaudited)
| | | | | | | | | | |
| | | | | Quarter Ended
March 31, | |
| | | | | 2009 | | | 2008 | |
| | | | | (As Adjusted) | |
| | | | | (in thousands, except per share amounts) | |
Operating and Other Revenues: | | | | | | | | | | |
Oil and gas production | | (1) | | $ | 170,176 | | | $ | 149,045 | |
Commodity derivative loss | | (1) | | | (25,956 | ) | | | (1,530 | ) |
Other | | | | | 520 | | | | 1,687 | |
| | | | | | | | | | |
Total operating and other revenues | | | | | 144,740 | | | | 149,202 | |
| | | | | | | | | | |
Operating Expenses: | | | | | | | | | | |
Lease operating | | | | | 11,680 | | | | 9,301 | |
Gathering and transportation | | | | | 11,024 | | | | 9,399 | |
Production tax | | (2) | | | 926 | | | | 10,259 | |
Exploration | | | | | 760 | | | | 641 | |
Impairment, dry hole costs and abandonment | | | | | 185 | | | | 1,552 | |
Depreciation, depletion and amortization | | | | | 58,757 | | | | 50,957 | |
General and administrative | | (3) | | | 9,586 | | | | 10,632 | |
Non-cash stock-based compensation | | (3) | | | 3,794 | | | | 3,583 | |
| | | | | | | | | | |
Total operating expenses | | | | | 96,712 | | | | 96,324 | |
| | | | | | | | | | |
| Operating Income | | | | | 48,028 | | | | 52,878 | |
| | | |
| Other Income and Expense: | | | | | | | | | | |
Interest and other income | | | | | 198 | | | | 472 | |
Interest expense | | (4) | | | (5,129 | ) | | | (3,879 | ) |
| | | | | | | | | | |
Total other income and expense | | | | | (4,931 | ) | | | (3,407 | ) |
| | | | | | | | | | |
| Income before Income Taxes | | | | | 43,097 | | | | 49,471 | |
| Provision for Income Taxes | | (4) | | | 16,684 | | | | 18,917 | |
| | | | | | | | | | |
| Net Income | | (4) | | $ | 26,413 | | | $ | 30,554 | |
| | | | | | | | | | |
Net Income Per Common Share | | | | | | | | | | |
Basic | | | | $ | 0.59 | | | $ | 0.69 | |
Diluted | | | | | 0.59 | | | | 0.68 | |
Weighted Average Common Shares Outstanding | | | | | | | | | | |
Basic | | | | | 44,618 | | | | 44,279 | |
Diluted | | | | | 44,740 | | | | 45,225 | |
| (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: |
| | | | | | | | |
| | | Quarter Ended March 31, | |
| | | 2009 | | | 2008 | |
Included in oil and gas production revenue: | | | | | | | | |
Realized gains on cash flow hedges | | $ | 87,119 | | | $ | (1,732 | ) |
| | | | | | | | |
Included in commodity derivative loss: | | | | | | | | |
Realized gains on derivatives not designated cash flow hedges | | $ | — | | | $ | — | |
Unrealized ineffectiveness recognized on derivatives designated cash flow hedges | | | (5,863 | ) | | | (1,530 | ) |
Unrealized gains (losses) on derivatives not designated cash flow hedges (basis only swaps) | | | (20,093 | ) | | | — | |
| | | | | | | | |
Total commodity derivative loss | | $ | (25,956 | ) | | $ | (1,530 | ) |
| | | | | | | | |
| (2) | Production tax expense for the 2009 quarter 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 allows for a more accurate comparison to the Company's peers who 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 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
March 31, | | As of
December 31, |
| | | | | 2009 | | 2008 |
| | | | | (As Adjusted) |
| | | | | (in thousands) |
Assets: | | | | | | | | |
Cash and cash equivalents | | | | $ | 71,470 | | $ | 43,063 |
Other current assets | | (1) | | | 273,650 | | | 270,311 |
Property and equipment, net | | | | | 1,614,183 | | | 1,561,819 |
Other noncurrent assets | | (1) | | | 93,193 | | | 119,300 |
| | | | | | | | |
Total assets | | | | $ | 2,052,496 | | $ | 1,994,493 |
| | | | | | | | |
| Liabilities and Stockholders’ Equity: | | | | | | | | |
Current liabilities | | | | $ | 208,588 | | $ | 225,794 |
Notes payable under bank credit facility | | | | | 276,000 | | | 254,000 |
Convertible senior notes | | (2) | | | 154,660 | | | 153,411 |
Other long-term liabilities | | | | | 278,510 | | | 262,055 |
Stockholders’ equity | | | | | 1,134,738 | | | 1,099,233 |
| | | | | | | | |
Total liabilities and stockholders’ equity | | | | $ | 2,052,496 | | $ | 1,994,493 |
| | | | | | | | |
| (1) | At March 31, 2009, the estimated fair value of all of our commodity derivative instruments was a net asset of $298.5 million, comprised of: $213.8 million current assets; $88.2 million non-current assets; and $3.5 million non-current liabilities. This amount will fluctuate quarterly based on estimated future commodity prices. |
| (2) | Effective January 1, 2009, the Company adopted financial reporting rule FSP ABP 14-1 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. The principal value of the notes is $172.5 million. |
10
BILL BARRETT CORPORATION
Consolidated Statements of Cash Flows
(Unaudited)
| | | | | | | | |
| | | Quarter Ended March 31, | |
| | | 2009 | | | 2008 | |
| | | (As Adjusted) | |
| | | (in thousands) | |
Operating Activities: | | | | | | | | |
Net income | | $ | 26,413 | | | $ | 30,554 | |
Adjustments to reconcile to net cash provided by operations: | | | | | | | | |
Depreciation, depletion and amortization | | | 58,757 | | | | 50,957 | |
Impairment, dry hole costs and abandonment costs | | | 185 | | | | 1,552 | |
Unrealized derivative loss | | | 25,956 | | | | 1,530 | |
Deferred income taxes | | | 16,628 | | | | 18,807 | |
Stock compensation and other non-cash charges | | | 4,314 | | | | 3,974 | |
Amortization of deferred financing costs | | | 503 | | | | 234 | |
Amortization of discount on convertible notes | | | 1,248 | | | | 267 | |
(Gain) loss on sale of properties | | | 1 | | | | (172 | ) |
| | |
Change in assets and liabilities: | | | | | | | | |
Accounts receivable | | | 12,909 | | | | (19,532 | ) |
Prepayments and other assets | | | (2,504 | ) | | | (3,114 | ) |
Accounts payable, accrued and other liabilities | | | 6,668 | | | | (3,082 | ) |
Amounts payable to oil & gas property owners | | | (5,337 | ) | | | (1,145 | ) |
Production taxes payable | | | (3,205 | ) | | | 4,366 | |
| | | | | | | | |
Net cash provided by operating activities | | $ | 142,536 | | | $ | 85,196 | |
| | | | | | | | |
Investing Activities: | | | | | | | | |
Additions to oil and gas properties, including acquisitions | | $ | (134,901 | ) | | $ | (114,992 | ) |
Additions of furniture, equipment and other | | | (1,226 | ) | | | (605 | ) |
Proceeds from sale of properties | | | — | | | | 1,212 | |
| | | | | | | | |
Net cash used in investing activities | | $ | (136,127 | ) | | $ | (114,385 | ) |
| | | | | | | | |
Financing Activities: | | | | | | | | |
Proceeds from debt | | $ | 42,000 | | | $ | 199,800 | |
Principal payments on debt | | | (20,000 | ) | | | (167,014 | ) |
Proceeds from sale of common stock | | | — | | | | 1,629 | |
Deferred financing costs and other | | | (2 | ) | | | (4,588 | ) |
| | | | | | | | |
Net cash provided by financing activities | | $ | 21,998 | | | $ | 29,827 | |
| | | | | | | | |
Increase in Cash and Cash Equivalents | | $ | 28,407 | | | $ | 638 | |
Beginning Cash and Cash Equivalents | | | 43,063 | | | | 60,285 | |
| | | | | | | | |
Ending Cash and Cash Equivalents | | $ | 71,470 | | | $ | 60,923 | |
| | | | | | | | |
11
BILL BARRETT CORPORATION
Reconciliation of Discretionary Cash Flow & Adjusted Net Income from Net Income
(Unaudited)
Discretionary Cash Flow Reconciliation
| | | | | | | |
| | | Quarter Ended March 31, | |
| | | 2009 | | 2008 | |
| | | (As Adjusted) | |
| | | (in thousands, except per unit amounts) | |
Net Income | | $ | 26,413 | | $ | 30,554 | |
| | |
Adjustments to reconcile to discretionary cash flow Depreciation, depletion and amortization | | | 58,757 | | | 50,957 | |
Impairment, dry hole costs and abandonment costs | | | 185 | | | 1,552 | |
Exploration expense | | | 760 | | | 641 | |
Unrealized derivative loss | | | 25,956 | | | 1,530 | |
Deferred income taxes | | | 16,628 | | | 18,807 | |
Stock compensation and other non-cash charges | | | 4,314 | | | 3,974 | |
Amortization of deferred financing and discount on convertible notes | | | 1,751 | | | 501 | |
(Gain) loss on disposal of properties | | | 1 | | | (172 | ) |
| | | | | | | |
Discretionary Cash Flow | | $ | 134,765 | | $ | 108,344 | |
| | | | | | | |
Per share, diluted | | $ | 3.01 | | $ | 2.40 | |
Per Mcfe | | $ | 6.10 | | $ | 5.95 | |
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.
Adjusted Net Income Reconciliation
| | | | | | | | |
| | | Quarter Ended March 31, | |
| | | 2009 | | | 2008 | |
| | | (As Adjusted) | |
| | | (in thousands, except per unit amounts) | |
Net Income | | $ | 26,413 | | | $ | 30,554 | |
| | |
Adjustments to net income: | | | | | | | | |
Unrealized derivative loss | | | 25,956 | | | | 1,530 | |
(Gain) loss on sale of properties | | | 1 | | | | (172 | ) |
One time items: | | | | | | | | |
Production tax expense | | | (4,400 | ) | | | — | |
| | | | | | | | |
Subtotal Adjustments | | | 21,557 | | | | 1,358 | |
Effective tax rate | | | 39 | % | | | 38 | % |
| | | | | | | | |
Tax effected adjustments | | | 13,212 | | | | 839 | |
| | | | | | | | |
Adjusted Net Income | | $ | 39,625 | | | $ | 31,393 | |
| | | | | | | | |
Per share, diluted | | $ | 0.89 | | | $ | 0.69 | |
The non-GAAP 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 accounting principles generally accepted in the United States of America (“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
