![]() | NEWS RELEASE FOR IMMEDIATE RELEASE |
BRIGHAM EXPLORATION REPORTS YEAR END AND FOURTH QUARTER 2008 RESULTS
Austin, TX — March 11, 2009 — Brigham Exploration Company (NASDAQ:BEXP) today announced financial results for the year-ended and quarter-ended December 31, 2008.
YEAR END 2008 RESULTS
Revenues from the sale of oil and natural gas including hedge settlements for 2008 were $121.5 million, which represents a 3% decrease when compared to last year. Lower production volumes and hedge settlements decreased revenue by $20.4 million and $7.8 million, respectively, while higher prices increased revenue by $25.0 million. Average daily equivalent production volumes for 2008 were 31.8 MMcfe per day, down 23% when compared to those for 2007. Despite the fact that our overall equivalent volumes were down for the year, our oil volumes increased by 47% as we expanded both our operated and non-operated drilling activity in the Williston Basin.
Our average realized price for natural gas in 2008 was $9.08 per Mcf, which included a $0.13 per Mcf loss associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in 2007 of $7.66 per Mcf, which included a $0.36 per Mcf gain due to the settlement of our natural gas derivative contracts. Our average realized price for oil for 2008 was $84.63 per barrel, which included a $4.43 per barrel loss due to the settlement of our oil derivative contracts. This compares to an average realized price in 2007 of $71.51, which included a $0.79 per barrel loss due to the settlement of oil derivative contracts last year.
Our production costs per Mcfe, which include costs for operating and maintaining our producing wells (O&M expense), expensed workovers, ad valorem taxes and production taxes, increased 76%, or by $0.67 per Mcfe, when compared to 2007. Production taxes increased by $0.30 per Mcfe, due to a $2.7 million decrease in high cost gas production tax abatements received in 2008 as compared to 2007. O&M expenses increased by $0.28 per Mcfe, primarily due to increases in salt water disposal, compressor rental and fuel costs. Workover costs increased by $0.09 per Mcfe, due to an increase in the number and cost of workovers. Ad valorem taxes were in-line with 2007.
Our general and administrative (G&A) expenses rose by 3% in 2008 versus 2007 as higher contract and professional fees, office costs and franchise taxes were mostly offset by lower employee bonuses.
Our depletion expense for 2008 was $53.5 million ($4.67 per Mcfe) compared to $59.1 million ($3.94 per Mcfe) in 2007. Our decreased production volumes reduced depletion expense by $13.9 million while our higher depletion rate increased depletion expense by $8.3 million in 2008. The increase in our depletion rate was a result of an increase in the cost of reserve additions.
In 2008, we recorded a $237.2 million non-cash ceiling test impairment charge ($148.6 million after-tax) on our oil and gas properties. A ceiling test impairment is recorded when the capitalized cost of our oil and gas properties exceeds the present value (10% per annum discount rate) of estimated future net cash flows based on commodity prices at the end of the reporting period plus certain unevaluated property costs. Commodity spot prices as of December 31, 2008 for Henry Hub natural gas and West Texas intermediate crude oil were $5.71 per Mcf and $44.60 per barrel.
Our net interest expense for 2008 was 1% lower than last year. The primary driver behind the decrease in our interest expense was higher capitalized interest expense associated with our higher level of drilling activity. Our weighted average debt outstanding for 2008 was $220.1 million versus $189.1 million in 2007.
We recorded a deferred income tax benefit of $42.7 million in 2008 compared to a deferred income tax expense of $6.7 million in 2007. The deferred income tax benefit primarily resulted from our $237.2 million ceiling test writedown.
Our reported net income (loss) for 2008 was ($162.2) million (($3.57) per diluted share) versus net income of $10.2 million ($0.22 per diluted share) for the same period last year. Our after-tax earnings in 2008 excluding the effect of our unrealized derivative gains and ceiling test impairment charge were $15.4 million ($0.33 per diluted share), while our after-tax earnings in 2007 excluding the effect of our unrealized derivative losses and ceiling test impairment charge were $17.9 million ($0.39 per diluted share). After-tax earnings excluding the above items is a non-GAAP measure and a reconciliation of GAAP net income to after-tax earnings excluding the above items is included in our accompanying financial tables found later in this release.
As of December 31, 2008, we had $40.0 million in cash and $145.0 million of debt outstanding under our senior credit facility.
In 2008, we spent $185.3 million on oil and gas capital expenditures, which represents a 47% increase from 2007. Oil and gas capital expenditures for 2008 and 2007 were:
Year Ended December 31, | ||||||||
2008 | 2007 | |||||||
(in thousands) | ||||||||
Drilling | $ | 136,248 | $ | 96,833 | ||||
Net land and seismic | 35,796 | 17,527 | ||||||
Capitalized costs | 12,852 | 11,631 | ||||||
Capitalized SFAS 143 ARO | 412 | 325 | ||||||
Total oil and gas capital expenditures | $ | 185,308 | $ | 126,316 | ||||
FOURTH QUARTER 2008 RESULTS
Our average net daily equivalent production volumes for the fourth quarter 2008 were 37.4 MMcfe per day, up 5% when compared to those for the fourth quarter 2007. Benefiting from both our operated and non-operated drilling activity in the Williston Basin, our oil volumes for the fourth quarter 2008 averaged 2,279 barrels per day, which represents a 118% increase from the 1,045 barrels per day produced in the fourth quarter 2007. Revenues from the sale of oil and natural gas including hedge settlements for the fourth quarter 2008 were down 11% to $26.0 million when compared to those for the fourth quarter 2007. Lower realized prices decreased revenues by $10.5 million, while higher production volumes and higher hedge settlement gains increased revenues by $6.2 million and $1.2 million, respectively.
Our average realized price for natural gas for the fourth quarter 2008 was $7.04 per Mcf, which included a $0.61 per Mcf gain associated with the settlement of our natural gas derivative contracts. This compares to an average realized price in the fourth quarter 2007 of $8.02, which included a $0.45 per Mcf gain due to the settlement of our natural gas derivative contracts. During the fourth quarter 2008, our average realized price for oil was $53.35 per barrel, which included a $3.28 per barrel gain due to the settlement of our oil derivative contracts. This compares to an average realized price in the fourth quarter 2007 of $84.98, which included a $4.29 per barrel loss due to the settlement of our oil derivative contracts.
Our fourth quarter 2008 per Mcfe production costs were up 49% when compared to those for the fourth quarter 2007. The increase was largely driven by a $0.36 per Mcfe increase in O&M expense and a $0.08 per Mcfe increase in production taxes. O&M expense rose due to higher salt water disposal, compressor rental and fuel costs. Production taxes rose due to a $0.2 million decrease in high cost gas production tax abatements in 2008 as compared to 2007.
G&A expense for the fourth quarter 2008 decreased $0.4 million compared to the fourth quarter 2007 because of lower employee bonuses which were partially offset by both higher contract and professional services and higher franchise taxes.
Our depletion expense for the fourth quarter 2008 was $16.9 million ($5.03 per Mcfe) compared to $13.7 million ($4.30 per Mcfe) in the fourth quarter 2007. Our higher depletion rate increased depletion expense by $2.5 million and our higher production volumes increased depletion expense by $0.7 million. The increase in our depletion rate was a result of an increase in the cost of reserve additions.
In the fourth quarter 2008, we recorded a $237.2 million non-cash ceiling test impairment charge ($148.6 million after-tax) on our oil and gas properties. A ceiling test impairment is recorded when the capitalized cost of our oil and gas properties exceeds the present value (10% per annum discount rate) of estimated future net cash flows based on commodity prices at the end of the reporting period plus certain unevaluated property costs. Commodity spot prices as of December 31, 2008 for Henry Hub natural gas and West Texas intermediate crude oil were $5.71 per Mcf and $44.60 per barrel.
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Our net interest expense for the fourth quarter 2008 increased $0.3 million, or by 8%, from the fourth quarter 2007. This increase was primarily due to our higher weighted average debt outstanding of $260.1 million in the fourth quarter 2008 versus $176.6 million in the fourth quarter 2007. The increase in weighted average debt outstanding was partially offset by a 67% increase in capitalized interest expense.
We recorded a deferred income tax benefit of $53.9 million in the fourth quarter of this year compared to a deferred income tax expense of $1.5 million in the fourth quarter last year. The deferred income tax benefit primarily resulted from the ceiling test writedown of $237.2 million.
Our reported net income (loss) for the fourth quarter 2008 was ($180.6) million (($3.95) per diluted share) versus net income of $1.8 million ($0.04 per diluted share) for the same period last year. Our after-tax earnings (loss) in the fourth quarter 2008 excluding our unrealized derivative gains and ceiling test impairment charge were ($1.9) million (($0.04) per basic share), while our after-tax earnings in the fourth quarter 2007 excluding unrealized derivative losses were $3.4 million ($0.07 per diluted share). After-tax earnings excluding the above items is a non-GAAP measure and a reconciliation of GAAP net income to after-tax earnings excluding the above items is included in our accompanying financial tables found later in this release.
In the fourth quarter 2008, we spent $47.3 million on oil and gas capital expenditures, which represents a 31% increase from 2007. Oil and gas capital expenditures for 2008 and 2007 were:
Three Months Ended December 31, | ||||||||
2008 | 2007 | |||||||
(in thousands) | ||||||||
Drilling | $ | 36,815 | $ | 25,765 | ||||
Net land and seismic | 7,566 | 7,558 | ||||||
Capitalized costs | 2,724 | 2,782 | ||||||
Capitalized SFAS 143 ARO | 145 | 0 | ||||||
Total oil and gas capital expenditures | $ | 47,250 | $ | 36,105 | ||||
2008 PROVED RESERVES
Our estimated net proved reserve volumes at December 31, 2008 totaled 137.1 Bcfe of which approximately 69% was natural gas. During 2008, we added approximately 8.3 Bcfe in net proved reserves and replaced 73% of our 11.5 Bcfe of production. As of December 31, 2008, our estimated proved reserves were comprised of 63.4 Bcfe of net proved developed and 73.6 Bcfe of net proved undeveloped reserves.
Equivalent Reserves | ||||
(MMcfe) | ||||
2008 Beginning Proved Reserves | 140,202 | |||
Extensions, discoveries & other additions | 13,688 | |||
Revisions of prior estimates | (5,356 | ) | ||
Sale of minerals-in-place | ||||
Production | (11,464 | ) | ||
2008 Ending Proved Reserves | 137,070 | |||
At year-end 2008, the standardized measure and the pre-tax present value (“Pre-tax PV10% Value”) of our estimated proved reserves were $279.3 million and $288.0 million, respectively. For 2008, these measures were calculated using a West Texas Intermediate Sweet oil price of $44.60 per barrel and a Henry Hub natural gas price of $5.71 per MMBtu.
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Bud Brigham, the Chairman, President and CEO, commented, “At mid-year 2008, we had high expectations for reserve growth during the year. The biggest factor negatively impacting that growth was of course the dramatic fall in commodity prices, particularly for oil in our Bakken Three Forks play. In that play, we invested the largest portion of our capital, 62% of our drilling capex, drilling in a $100 per barrel of oil cost environment, and then subsequently booking the associated reserves at $44.60 per barrel. The drilling cost and oil price mismatch element was compounded by the fact that we could only book proved undeveloped reserves to a level associated with the drilling and completion technology used in the original, directly offsetting well. As a consequence, proved undeveloped locations offsetting older technology wells were booked at lower reserve volumes, or not at all, relative to the volumes associated with our more recent wells completed with a greater number of fracture stimulation stages.”
At December 31, 2008 | ||||
(in millions) | ||||
Standardized measure of discounted future net cash flows | $ | 279.3 | ||
Add present value of future income tax discounted at 10% | 8.7 | |||
Pre-tax PV10% Value | $ | 288.0 | ||
Pre-tax PV10% Value is the estimated present value of the future net revenues from our proved oil and natural gas reserves before income taxes, discounted using a 10% discount rate. Pre-tax PV10% Value is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows. We believe that Pre-tax PV10% Value is an important measure that can be used to evaluate the relative significance of our oil and natural gas properties and that Pre-tax PV10% Value is widely used by security analysts and investors when evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when evaluating companies. We believe that most other companies in the oil and natural gas industry calculate Pre-tax PV10% Value on the same basis. Pre-tax PV10% Value is computed on the same basis as the standardized measure of discounted future net cash flows, but without deducting income taxes.
2009 CAPITAL EXPENDITURE BUDGET
The current capital expenditure budget for 2009 includes completing several of our late 2008 wells in the Williston Basin in early 2009, completing additional 2008 Williston Basin wells in mid-summer 2009 after expected further reductions in service costs, hooking up our Southern Louisiana wells to production and drilling and completing a Gulf Coast well. Our budgeted capital expenditure program for 2009 is as follows:
(In millions) | ||||
Drilling | $ | 26.7 | ||
Net land and seismic | (2.4 | ) | ||
Exploration and development capital expenditures | $ | 24.3 | ||
Capitalized Costs | 12.5 | |||
Other non-oil & gas assets | 0.3 | |||
Total | $ | 37.1 | ||
Bud Brigham commented, “The capital budget that we’ve announced today positions us to maintain our financial flexibility in a very difficult environment. However, we will revisit the current 2009 cap-ex budget as we move through the year. Further, we anticipate closing one or several of the transactions outlined below after March, and as long as oil prices stabilize or improve and services costs continue to decrease, we would expect to be able to scale up our drilling during the second half of 2009.”
FIRST QUARTER 2009 FORECASTS
The following forecasts and estimates of our first quarter 2009 production volumes are forward looking statements subject to the risks and uncertainties identified in the “Forward Looking Statements Disclosure” at the end of this release. We currently expect our first quarter 2009 production volumes to average between 30.0 MMcfe per day and 33.0 MMcfe per day. Given the uncertainty around our 2009 cap-ex budget for the second half of 2009, we are electing not to provide a full year production forecast, but will revisit this decision as we move through the year.
For the first quarter 2009, lease operating expenses are projected to be $1.48 per Mcfe based on the mid-point of our production guidance, production taxes are projected to be approximately 5.25% to 5.50% of pre-hedge oil and natural gas revenues, and G&A expenses are projected to be $2.15 million ($0.80 to $0.72 per Mcfe).
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MANAGEMENT COMMENTS
Bud Brigham commented, “During early 2008, we brought on-line our first Bakken wells east of the Nesson Anticline in Mountrail County. Throughout the year, we rapidly acquired acreage in the Williston Basin and have assembled one of the premier acreage positions in the basin for a company our size. In addition, we rapidly advanced drilling and completion techniques, with our most recent wells being our most successful in term of initial rates and forecasted economic ultimate recoveries. The rapid improvement in our results with the Mrachek, Johnson, Carkuff and Adix wells gave us the confidence to pick up a second operated rig late in the year.”
Bud Brigham continued, “We moved our two operated rigs west of the Nesson Anticline in order to further test our 105,590 net acres in Williams and McKenzie Counties and our engineers developed a plan to be the first company in the basin to complete a long lateral with 19 swell packers and 20 fracture stimulation stages. We announced the highly successful results of our first well completed with this technology, the Olson 10-15 #1H, in early February at an initial production rate of 1,200 barrels of oil per day and 1.4 MMcf of natural gas per day. To date, the well continues to perform strongly and it has the highest cumulative recovery of any of our wells in the basin over a similar production period. It’s a huge compliment to our highly effective staff that we were able to drill and complete the first well of this type successfully.”
Bud Brigham continued, “Unfortunately at about the same time we picked up our second rig, the unprecedented economic upheaval firmly took root and the price of oil and natural gas rapidly decreased. Meanwhile, drilling day rates, steel costs and pressure pumping rates were elevated from the high levels of activity in the summer 2008. In response to rapidly decreasing commodity prices and high service costs, we dropped both of our Williston Basin operated rigs by mid February, as we wanted to maintain financial flexibility and believed that much more favorable service costs, and therefore better project economics, would be experienced this summer.”
Gene Shepherd, Brigham’s Chief Financial Officer, commented, “In response to the current economic uncertainty and in order to maintain financial flexibility, we drew down our unused availability under our senior credit facility just before year end and at the present time have $33.3 million of cash on the balance sheet. Based on our announced 2009 capital expenditure budget and our reduced level of drilling activity since mid February, we are forecasting to be free cash flow positive for the remainder of 2009. We have a number of additional initiatives under way to further enhance our liquidity during these uncertain times, including the $6 million sale of our Mountrail County mineral interests that we expect to close by the end of March. Further, we are actively marketing our non-operated 7,715 net acres in the Parshall / Austin / Sanish fields. We are also marketing up to 50% of our working interest in a portion of our remaining 301,058 net acres in the Williston Basin, but we will remain the operator. We believe that our strong acreage position in this premier oil resource play provides us the opportunity to sell working interest positions in portions of the play, thereby accessing additional capital, while retaining a very substantial inventory of net drilling locations for future net asset value growth. Lastly, we have reduced our cash G&A costs and will continue to do so throughout the year. During the second half of 2008, no bonuses were paid to employees. We currently anticipate reducing our 2009 cash G&A costs by 10 to 15% relative to those in 2008.”
CONFERENCE CALL INFORMATION
Our management will host a conference call to discuss operational and financial results for the year-end and fourth quarter 2008 with investors, analysts and other interested parties on Thursday March 12, at 10:00 a.m. Eastern Time. To participate in the call, participants within the U.S. please dial 888-713-4217 and participants outside the U.S. please dial 617-213-4869. The participant passcode for the call is 45020372. Participants may pre-register for the call at https://www.theconferencingservice.com/prereg/key.process?key=P6CTKHPEV. Pre-registrants will be issued a pin number to use when dialing into the live call which will provide quick access to the conference. A telephone recording of the conference call will be available to interested parties approximately two hours after the call is completed through 12:00 p.m. Eastern Time on Thursday, March 19, 2009. To access the recording, domestic callers dial 888-286-8010 and international callers dial 617-801-6888. The passcode for the conference call playback is 11926310. In addition, a live and archived web cast of the conference call will be available over the Internet at www.bexp3d.com.
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We will be updating our corporate presentation prior to our conference call and will reference information contained therein. We encourage you to access the presentation in advance of the conference call. To access the presentation, go to www.bexp3d.com and click on Corporate Presentation along the left side of our home page. In addition, a copy of this press release and other financial and statistical information about the periods covered by this press release and by the conference call that will take place on Thursday, March 12, 2009, will be available on our website. To access the press release, go to www.bexp3d.com and click on News Releases. The file with a copy of the press release is named Brigham Exploration Reports Year-End and Fourth Quarter 2008 Results and is dated Wednesday, March 11, 2009. To access the other financial and statistical information that will be covered by the conference call that will take place on Thursday, March 12, go to www.bexp3d.com and click on Event Calendar. The file with the other financial and statistical information is named Financial and Statistical Information for the Fourth Quarter 2008 Conference Call and is dated Thursday, March 12, 2009.
ABOUT BRIGHAM EXPLORATION
Brigham Exploration Company is an independent exploration and production company that applies 3-D seismic imaging and other advanced technologies to systematically explore for and develop onshore domestic oil and natural gas reserves. For more information about Brigham Exploration, please visit our website at www.bexp3d.com or contact Investor Relations at 512-427-3444.
Forward-Looking Statement Disclosure
Except for the historical information contained herein, the matters discussed in this news release are forward-looking statements within the meaning of the federal securities laws. Important factors that could cause our actual results to differ materially from those contained in the forward-looking statements include our growth strategies, our ability to successfully and economically explore for and develop oil and gas resources, anticipated trends in our business, our liquidity and ability to finance our exploration and development activities, market conditions in the oil and gas industry, our ability to make and integrate acquisitions, the impact of governmental regulation and other risks more fully described in the company’s filings with the Securities and Exchange Commission. Forward- looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. All forward-looking statements contained in this release, including any forecasts and estimates, are based on management’s outlook only as of the date of this release, and we undertake no obligation to update or revise these forward-looking statements, whether as a result of subsequent developments or otherwise.
Contact: | Rob Roosa, Finance Manager | |
(512) 427-3300 |
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BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) (unaudited)
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) (unaudited)
Three Months Ended | Year Ended | |||||||||||||||
December 31, | December 31, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas sales | $ | 23,996 | $ | 28,307 | $ | 125,108 | $ | 120,557 | ||||||||
Hedging settlements | 1,981 | 762 | (3,592 | ) | 4,167 | |||||||||||
25,977 | 29,069 | 121,516 | 124,724 | |||||||||||||
Unrealized hedging gains (losses) | 4,495 | (2,846 | ) | 6,140 | (5,831 | ) | ||||||||||
30,472 | 26,223 | 127,656 | 118,893 | |||||||||||||
Other revenue | 28 | 15 | 132 | 88 | ||||||||||||
Total Revenue | 30,500 | 26,238 | 127,788 | 118,981 | ||||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 3,737 | 2,246 | 12,363 | 10,704 | ||||||||||||
Production taxes | 1,267 | 968 | 5,374 | 2,541 | ||||||||||||
General and administrative | 1,866 | 2,303 | 9,557 | 9,276 | ||||||||||||
Depletion of oil and natural gas properties | 16,932 | 13,732 | 53,498 | 59,079 | ||||||||||||
Impairment of oil and natural gas properties | 237,180 | — | 237,180 | 6,505 | ||||||||||||
Depreciation and amortization | 165 | 145 | 629 | 613 | ||||||||||||
Accretion of discount on asset retirement obligations | 98 | 81 | 361 | 379 | ||||||||||||
261,245 | 19,475 | 318,962 | 89,097 | |||||||||||||
Operating income (loss) | (230,745 | ) | 6,763 | (191,174 | ) | 29,884 | ||||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net Interest income | (3,832 | ) | (3,551 | ) | (14,495 | ) | (14,622 | ) | ||||||||
Interest income | 28 | 118 | 191 | 654 | ||||||||||||
Other income (expense) | 111 | 15 | 530 | 1,022 | ||||||||||||
(3,693 | ) | (3,418 | ) | (13,774 | ) | (12,946 | ) | |||||||||
Income (loss) before income taxes | (234,438 | ) | 3,345 | (204,948 | ) | 16,938 | ||||||||||
Income tax (expense) benefit: | ||||||||||||||||
Current | — | — | — | — | ||||||||||||
Deferred | 53,887 | (1,501 | ) | 42,701 | (6,728 | ) | ||||||||||
53,887 | (1,501 | ) | 42,701 | (6,728 | ) | |||||||||||
Net income (loss) | $ | (180,551 | ) | $ | 1,844 | $ | (162,247 | ) | $ | 10,210 | ||||||
Net income (loss) per share available to common stockholders: | ||||||||||||||||
Basic | $ | (3.95 | ) | $ | 0.04 | $ | (3.57 | ) | $ | 0.23 | ||||||
Diluted | $ | (3.95 | ) | $ | 0.04 | $ | (3.57 | ) | $ | 0.22 | ||||||
Weighted average shares outstanding: | ||||||||||||||||
Basic | 45,685 | 45,184 | 45,441 | 45,110 | ||||||||||||
Diluted | 45,685 | 45,708 | 45,441 | 45,531 | ||||||||||||
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BRIGHAM EXPLORATION COMPANY
PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA
(unaudited)
PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Average net daily production: | ||||||||||||||||
Natural gas (MMcf) | 23.7 | 29.2 | 22.2 | 35.1 | ||||||||||||
Oil (Bbls) | 2,279 | 1,045 | 1,605 | 1,089 | ||||||||||||
Equivalent natural gas (MMcfe) (6:1) | 37.4 | 35.5 | 31.8 | 41.6 | ||||||||||||
Total net production: | ||||||||||||||||
Natural gas (MMcf) | 2,135 | 2,629 | 7,996 | 12,626 | ||||||||||||
Oil (MBbls) | 205 | 94 | 578 | 392 | ||||||||||||
Equivalent natural gas (MMcfe) (6:1) | 3,366 | 3,194 | 11,463 | 14,978 | ||||||||||||
% Natural gas | 63 | % | 82 | % | 70 | % | 84 | % | ||||||||
Sales price: | ||||||||||||||||
Natural gas ($/Mcf) | $ | 6.43 | $ | 7.57 | $ | 9.21 | $ | 7.30 | ||||||||
Oil ($/Bbl) | 50.07 | 89.27 | 89.06 | 72.30 | ||||||||||||
Equivalent natural gas ($/Mcfe) (6:1) | 7.13 | 8.86 | 10.91 | 8.05 | ||||||||||||
Sales price including derivative settlement gains (losses): | ||||||||||||||||
Natural gas ($/Mcf) | $ | 7.04 | $ | 8.02 | $ | 9.08 | $ | 7.66 | ||||||||
Oil ($/Bbl) | 53.35 | 84.98 | 84.63 | 71.51 | ||||||||||||
Equivalent natural gas ($/Mcfe) (6:1) | 7.72 | 9.10 | 10.60 | 8.33 | ||||||||||||
Sales price including derivative settlement gains (losses) and unrealized gains (losses): | ||||||||||||||||
Natural gas ($/Mcf) | $ | 8.18 | $ | 7.52 | $ | 9.48 | $ | 7.38 | ||||||||
Oil ($/Bbl) | 63.41 | 68.66 | 89.79 | 65.57 | ||||||||||||
Equivalent natural gas ($/Mcfe) (6:1) | 9.05 | 8.21 | 11.14 | 7.94 |
SUMMARY CONSOLIDATED BALANCE SHEETS
(in thousands)
(in thousands)
December 31, 2008 | December 31, 2007 | |||||||
Assets: | ||||||||
Current assets | $ | 78,520 | $ | 32,505 | ||||
Oil and natural gas properties, net (full cost method) | 404,839 | 510,207 | ||||||
Other property and equipment, net | 1,873 | 1,034 | ||||||
Other non-current assets | 3,824 | 4,682 | ||||||
Total assets | $ | 489,056 | $ | 548,428 | ||||
Liabilities and stockholders’ equity: | ||||||||
Current liabilities | $ | 48,215 | $ | 41,718 | ||||
Senior notes | 158,730 | 158,492 | ||||||
Senior credit facility | 145,000 | 10,000 | ||||||
Mandatorily redeemable preferred stock, Series A | 10,101 | 10,101 | ||||||
Deferred income tax liability | 149 | 41,625 | ||||||
Other non-current liabilities | 5,592 | 7,465 | ||||||
Total liabilities | $ | 367,787 | $ | 269,401 | ||||
Stockholders’ equity | 121,269 | 279,027 | ||||||
Total liabilities and stockholders’ equity | $ | 489,056 | $ | 548,428 | ||||
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BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) (unaudited)
SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) (unaudited)
Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Cash flows from operating activities: | ||||||||||||||||
Net income (loss) | $ | (180,551 | ) | $ | 1,844 | $ | (162,247 | ) | $ | 10,210 | ||||||
Depletion, depreciation and amortization | 17,097 | 13,877 | 54,127 | 59,692 | ||||||||||||
Impairment of oil and gas properties | 237,180 | — | 237,180 | 6,505 | ||||||||||||
Accretion of discount on ARO | 98 | 81 | 361 | 379 | ||||||||||||
Amortization of deferred loan fees and debt issuance costs | 295 | 255 | 1,105 | 968 | ||||||||||||
Non-cash stock compensation | 369 | 450 | 1,592 | 1,905 | ||||||||||||
Market value adjustments for derivatives instruments | (4,495 | ) | 2,846 | (6,140 | ) | 5,831 | ||||||||||
Deferred income tax expense (benefit) | (53,887 | ) | 1,501 | (42,701 | ) | 6,728 | ||||||||||
Provision for Doubtful Accounts | 17 | — | 17 | — | ||||||||||||
Other noncash items | — | — | 4 | (4 | ) | |||||||||||
Changes in operating assets and liabilities | (20,131 | ) | (3,757 | ) | (13,668 | ) | (1,765 | ) | ||||||||
Cash flows provided by operating activities | $ | (4,008 | ) | $ | 17,097 | $ | 69,630 | $ | 90,449 | |||||||
Cash flows used by investing activities | (36,615 | ) | (23,930 | ) | (179,866 | ) | (99,093 | ) | ||||||||
Cash flows (used) provided by financing activities | 72,003 | 10,200 | 136,416 | 18,207 | ||||||||||||
Net increase (decrease) in cash and cash equivalents | $ | 31,380 | $ | 3,367 | $ | 26,180 | $ | 9,563 | ||||||||
SUMMARY PER MCFE DATA
(unaudited)
(unaudited)
Three Months Ended December 31, | Year Ended December 31, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Revenues: | ||||||||||||||||
Oil and natural gas sales | $ | 9.05 | $ | 8.21 | $ | 11.14 | $ | 7.94 | ||||||||
Other revenue | 0.01 | — | 0.01 | — | ||||||||||||
$ | 9.06 | $ | 8.21 | $ | 11.15 | $ | 7.94 | |||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 1.11 | 0.70 | 1.08 | 0.71 | ||||||||||||
Production taxes | 0.38 | 0.30 | 0.47 | 0.17 | ||||||||||||
General and administrative | 0.55 | 0.72 | 0.83 | 0.62 | ||||||||||||
Depletion of oil and natural gas properties | 5.03 | 4.30 | 4.67 | 3.94 | ||||||||||||
Impairment of oil and natural gas properties | 70.46 | — | 20.69 | 0.43 | ||||||||||||
Depreciation and amortization | 0.05 | 0.05 | 0.05 | 0.04 | ||||||||||||
Accretion of discount on ARO | 0.03 | 0.03 | 0.03 | 0.03 | ||||||||||||
$ | 77.61 | $ | 6.10 | $ | 27.82 | $ | 5.94 | |||||||||
Operating income | $ | (68.55 | ) | $ | 2.11 | $ | (16.67 | ) | $ | 2.00 | ||||||
Interest expense, net of interest income (a) | (1.13 | ) | (1.07 | ) | (1.25 | ) | (0.93 | ) | ||||||||
Other income (expense) (b) | 0.03 | — | 0.05 | 0.07 | ||||||||||||
Adjusted income | $ | (69.65 | ) | $ | 1.04 | $ | (17.87 | ) | $ | 1.14 | ||||||
(a) | Calculated as interest expense minus interest income divided by production for period. | |
(b) | Excludes non-cash gains/(losses) arising from hedge accounting for certain of our oil and natural gas hedges. |
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BRIGHAM EXPLORATION COMPANY
RECONCILIATION OF GAAP NET INCOME TO AFTER-TAX EARNINGS
EXCLUDING THE EFFECT OF CERTAIN ITEMS
(in thousands)
RECONCILIATION OF GAAP NET INCOME TO AFTER-TAX EARNINGS
EXCLUDING THE EFFECT OF CERTAIN ITEMS
(in thousands)
Three months | Year | |||||||||||||||
ended December 31, | ended December 31, | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
Net income (loss) as reported | $ | (180,551 | ) | $ | 1,844 | $ | (162,247 | ) | $ | 10,210 | ||||||
Unrealized derivative (gains) losses | (4,495 | ) | 2,846 | (6,140 | ) | 5,831 | ||||||||||
Unrealized derivative (gains) losses on ineffective hedges | — | — | — | — | ||||||||||||
Impairment of oil and natural gas properties | 237,180 | — | 237,180 | 6,505 | ||||||||||||
Tax impact | (54,021 | ) | (1,277 | ) | (53,397 | ) | (4,678 | ) | ||||||||
Earnings (loss) excluding the effect of certain items | $ | (1,887 | ) | $ | 3,413 | $ | 15,396 | $ | 17,868 | |||||||
Earnings without the effect of certain items represents net income excluding the following: unrealized gains and losses on derivative contracts; unrealized gains and losses related to ineffectiveness on our derivatives that were previously classified as cash flow hedges; and our non-cash impairment charge on our oil and gas properties. Management believes that exclusion of these items enhances comparability of operating results between periods.
BRIGHAM EXPLORATION COMPANY
SUMMARY OF 2009 AND 2010 COMMODITY PRICE HEDGES OUTSTANDING AS OF MARCH 11, 2009
(unaudited)
SUMMARY OF 2009 AND 2010 COMMODITY PRICE HEDGES OUTSTANDING AS OF MARCH 11, 2009
(unaudited)
2009 | 2010 | |||||||||||||||||||||||||||||||||||
Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | |||||||||||||||||||||||||||||
Natural Gas Costless Collars: | ||||||||||||||||||||||||||||||||||||
Daily volumes | MMBtu/d | 9,111 | 5,934 | 5,870 | 2,283 | 2,333 | 3,626 | 3,587 | 1,304 | |||||||||||||||||||||||||||
Floor | $/MMBtu | $ | 7.954 | $ | 7.139 | $ | 7.139 | $ | 5.750 | $ | 5.750 | $ | 5.750 | $ | 5.750 | $ | 6.500 | |||||||||||||||||||
Cap | $/MMBtu | $ | 9.621 | $ | 7.950 | $ | 7.950 | $ | 7.050 | $ | 7.050 | $ | 7.191 | $ | 7.191 | $ | 8.250 | |||||||||||||||||||
Natural Gas Three Way Costless Collars: | ||||||||||||||||||||||||||||||||||||
Daily volumes | MMBtu/d | 1,667 | 2,308 | 2,283 | 4,239 | 4,333 | — | — | — | |||||||||||||||||||||||||||
Floor | $/MMBtu | $ | 8.000 | $ | 6.250 | $ | 6.250 | $ | 6.962 | $ | 6.962 | $ | — | $ | — | $ | — | |||||||||||||||||||
Written Put | $/MMBtu | $ | 4.500 | $ | 4.750 | $ | 4.750 | $ | 4.577 | $ | 4.577 | $ | — | $ | — | $ | — | |||||||||||||||||||
Cap | $/MMBtu | $ | 10.350 | $ | 8.800 | $ | 8.800 | $ | 8.615 | $ | 8.615 | $ | — | $ | — | $ | — | |||||||||||||||||||
Natural Gas Swaps: | ||||||||||||||||||||||||||||||||||||
Daily volumes | MMBtu/d | 2,000 | 4,176 | 1,522 | 652 | — | — | — | — | |||||||||||||||||||||||||||
Price | $/MMBtu | $ | 5.225 | $ | 4.956 | $ | 4.745 | $ | 4.900 | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||
Oil Costless Collars: | ||||||||||||||||||||||||||||||||||||
Daily volumes | Bbls/d | 333 | 99 | — | — | — | — | — | — | |||||||||||||||||||||||||||
Floor | $/Bbl | $ | 79.15 | $ | 62.00 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||
Cap | $/Bbl | $ | 108.53 | $ | 81.75 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||
Oil Swaps | ||||||||||||||||||||||||||||||||||||
Daily volumes | Bbls/d | — | 330 | 326 | 326 | — | — | — | — | |||||||||||||||||||||||||||
Price | $/Bbl | $ | — | $ | 50.75 | $ | 50.75 | $ | 50.75 | $ | — | $ | — | $ | — | $ | — |
Hedged volumes and prices reflected in this table represent average contract amounts for the quarterly periods presented; natural gas hedge prices and crude oil hedge contract prices are based on NYMEX pricing.
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