Brigham Exploration Reports Year-End, 4Q 2008 Results

Brigham Exploration Company 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.

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 saltwater 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.

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.

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.

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.

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."

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.

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).

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."
 

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