Exhibit 99.1
BRIGHAM EXPLORATION REPORTS YEAR END RESULTS
INCLUDING RECORD 2004 FINANCIAL RESULTS
AUSTIN, Texas, March 3 /PRNewswire-FirstCall/ -- Brigham Exploration
Company (Nasdaq: BEXP) today announced its financial results for the fiscal year
and quarter ended December 31, 2004 and its year-end reserve numbers.
Highlights from our performance for 2004 include:
-- 15% growth in 2004 production over production in 2003;
-- 40% growth in revenue to $72.2 million over revenue in 2003 of
$51.7 million; and
-- 28% growth in operating income to $27.9 million over operating income
in 2003 of $21.8 million.
YEAR-END 2004 RESULTS
Average net daily production volumes for 2004 were 34.1 MMcfe per day
compared to 29.7 MMcfe per day in 2003. Revenues from the sale of oil and
natural gas, net of hedging, grew 39% to $71.7 million in 2004 compared to $51.5
million last year. Higher production volumes for 2004 resulted in an increase in
revenue of approximately $9.6 million while a 14% increase in our average
equivalent sales price combined with a decrease in hedging losses increased
revenues by $10.6 million. Our average realized prices for 2004 were $5.84 per
Mcf for natural gas and $35.17 per barrel for oil, compared to $4.92 per Mcf and
$28.17 per barrel in 2003. Our average realized price for 2004 includes losses
from the cash settlement of hedging transactions of $0.21 per Mcf for natural
gas and $4.96 per barrel for oil compared to $0.76 per Mcf for natural gas and
$2.62 per barrel for oil in 2003.
Production cost, which includes lease operating expenses and production
taxes, were up 21% in 2004 and up 4% on a unit basis. An increase in costs for
compressor rental and maintenance and saltwater disposal and an increase in
production taxes due to an increase in the sales price we received from the sale
of oil and natural gas were the primary reasons for the increase in our unit
production costs.
General and administrative expenses for 2004 were up 20% when compared to
2003. General and administrative expenses for 2004 included approximately
$399,000 paid to outside consultants and our independent public accountants for
the implementation of Section 404 of Sarbanes-Oxley and $181,813 related to the
settlement of a legal dispute over the ownership of a well. Additional items
that led to higher general and administrative expenses for the fourth quarter
were increases in employee payroll and benefit expenses and fees paid to our
external reserve engineers. Due to these higher costs, general and
administrative expenses on a unit basis increased 5% in 2004 to $0.44 per Mcfe.
Depletion of oil and natural gas properties for 2004 was $28.8 million
($2.35 per Mcfe) compared to $17 million ($1.59 per Mcfe) in 2003. An increase
in production volumes accounted for 21% of the increase, while an increase in
our depletion rate accounted for the remaining 79%. The increase in our
depletion rate was due to a 15 Bcfe revision to our proved reserves at year-end
2004, an increase in finding and development costs in 2004 and an increase in
future development costs associated with our year-end 2004 reserves.
Interest expenses for 2004 were $3.1 million. The 35% decrease in interest
expenses was primarily due to a decrease in our weighted average debt
outstanding for 2004 combined with a lower interest rate that we paid on those
outstanding borrowings.
We recorded deferred income tax expenses of $9.1 million in 2004 compared
to an income tax benefit of $1.6 million in 2003. Net income available to common
stockholders for 2004 was $16.4 million ($0.39 diluted earnings per share)
compared to net income of $14.8 million ($0.53 diluted earnings per share) in
2003.
Our capital expenditures for oil and natural gas activities in 2004 and
2003 were:
(in millions)
2004 2003
-------- --------
Drilling $ 68.2 $ 35.1
Land and G&G 12.9 5.9
Capitalized Cost 5.7 6.1
Net capital expenditures $ 86.8 $ 47.1
FOURTH QUARTER 2004 RESULTS
Net daily production volumes for the fourth quarter 2004 were 34.1 MMcfe
per day and were 16% higher when compared with production volumes in last year's
fourth quarter. Higher production volumes, combined with higher commodity prices
and a decrease in losses due to the settlement of hedging contracts led to a 70%
increase in revenue from the sale of oil and natural gas.
Production cost for the fourth quarter 2004 were $2.5 million ($0.81 per
Mcfe) and 85% higher than production costs in the fourth quarter last year. On a
unit basis, lease operating expenses for the fourth quarter 2004 were $0.59
compared to $0.44 in last year's fourth quarter. The primary reasons for the
increase in lease operating expense were due to higher costs for salt-water
disposal, compressor rental and maintenance, well service and repair and an
increase in ad valorem taxes. Production taxes for the fourth quarter 2004 were
$673,000 compared to $180,000 in the fourth quarter last year. On a unit basis,
production taxes for the fourth quarter 2004 were $0.22 compared to $0.07 in
last year's fourth quarter. Production taxes in the fourth quarter of 2003
included a reclassification of a credit that we received from the settlement of
a gas imbalance liability with one of our participants. This reclassification
resulted in a decrease in our total production taxes and production taxes on a
unit basis in the fourth quarter of 2003. The credit, which based on preliminary
settlement information was booked in the third quarter 2003 as additional
revenue, was reclassified out of revenue as a reduction to production taxes in
the fourth quarter. Due to the reclassification from revenue to production taxes
both our production taxes and our production taxes on a per unit basis for the
fourth quarter 2003 appear low.
General and administrative expenses for the fourth quarter 2004 were up 55%
when compared to general and administrative expenses in the fourth quarter of
last year. General and administrative expenses for the fourth quarter 2004
included approximately $261,000 paid to outside consultants and our independent
public accountants for the implementation of Section 404 of Sarbanes-Oxley and
approximately $181,813 related to the settlement of a legal dispute over the
ownership of a well. Additional items that contributed to the increase in
general and administrative expenses were increases in financial reporting
expenses and fees paid to our external reserve engineers. Due to these higher
costs, general and administrative expenses on a unit basis increased 32% in the
fourth quarter 2004 to $0.54 per Mcfe.
Depletion expense for the fourth quarter 2004 was $12.5 million ($4.06 per
Mcfe) compared to $5.1 million ($1.93 per Mcfe) in the fourth quarter last year.
Higher production volumes in the fourth quarter represented 11% of this change,
while an increase in our depletion rate represented 89% of the increase in our
depletion expense.
A decrease in our weighted average subordinated notes outstanding combined
with a decrease in the interest rate that we paid on those notes and an increase
in the amount of interest that we capitalized in the fourth quarter of 2004 were
the primary reasons for the decrease in our reported interest expense for the
fourth quarter 2004. Interest expenses for the fourth quarter 2004 were
$636,000, compared to $1 million in 2003.
We recorded deferred income tax expenses of $1.9 million in the fourth
quarter of this year, compared to an income tax benefit of $1.6 million in the
fourth quarter 2003. We reported net income available to common stockholders of
$1.8 million ($0.04 per diluted share) for the fourth quarter 2004 versus net
income of $3.6 million ($0.10 per diluted share) for the prior year period.
Our capital expenditures during the fourth quarter of 2004 and 2003 were:
($'s in millions)
Three Months Ended
December 31,
2004 2003
--------- --------
Drilling $ 19.5 $ 14.5
Land and G&G 2.2 2.6
Capitalized Cost 1.1 1.5
Net capital expenditures $ 22.8 $ 18.6
FULL YEAR 2005 AND FIRST QUARTER 2005 FORECAST
The following forecasts and estimates of our full year 2005 production
volumes and first quarter 2005 results are forward looking statements subject to
the risks and uncertainties identified in the "Forward Looking Statements
Disclosure" at the end of this release.
In addition to providing guidance for the first quarter 2005, we have
elected to provide full year production guidance for 2005. We currently expect
to grow production volumes in 2005 by 10% to 15% relative to our 2004
production. This would result in average daily production of between 37.5 and
39.2 MMcfe per day (78% natural gas) for 2005.
We currently expect first quarter 2005 production volumes to average
between 28 and 32 MMcfe per day (75% natural gas). For the first quarter 2005,
lease operating expenses are projected to be $0.67 per Mcfe, production taxes
are projected to be approximately 5.5% of pre-hedge oil and gas revenues, and
general and administrative expenses are projected to be $1.3 million ($0.52 to
$0.45 per Mcfe). Based on these production and cost estimates, assumed average
NYMEX prices of $6.32 per MMBtu for natural gas and $47.45 per barrel for oil,
and taking into account our current outstanding hedging contracts, we forecast
that our first quarter revenue will be between $16.3 and $18.7 million and
operating income will be between $6.2 and $7.6 million.
Gene Shepherd, Brigham's Chief Financial Officer, commented, "2004 was
obviously a disappointing year for the company in terms of our drilling results.
However, 2004 was an outstanding year for the company from the standpoint of our
financial performance. A combination of strong commodity prices, production
growth and our ability to hold our costs relatively flat all contributed to
record revenue and operating income. Furthermore, we exited 2004 with one of the
strongest balance sheets that we have had in the company's history. The
company's strong underlying financial performance and it's strong balance sheet
should allow it to continue to benefit from Brigham's large and growing
inventory of exploration and development prospects in this outstanding commodity
price environment."
2004 PROVED RESERVES
Our estimated net proved reserves volumes at December 31, 2004 totaled
121.3 Bcfe. Our estimated net proved developed reserves at December 31, 2004
totaled 60.2 Bcfe and our net proved undeveloped reserves totaled 61.1 Bcfe.
During 2004, we added approximately 14.4 Bcfe in total proved reserves in our
Texas Gulf Coast, Anadarko Basin and West Texas 3-D seismic projects. Our 2004
drilling program generated proved reserve additions that replaced 117% of our
12.3 Bcfe of reserve volumes produced during the year. However, reserve
revisions at year-end 2004 totaled 15 Bcfe. These revisions resulted in large
part from proved undeveloped wells drilled during 2004 at our Mills Ranch and
Floyd fields. In addition, our late 2003 Floyd South discovery well, and its
development well drilled in early 2004, both underperformed. In total, these
revisions accounted for 83% of the total revisions. Approximately 84% of our
year-end 2004 reserve volumes are natural gas and 50% are proved developed.
At year-end 2004, the pre-tax present value ("Pre-tax PV10% Value") of our
estimated proved reserves was $294 million. Our Pre-tax PV10% Value at year-end
2003 was $344 million. Our Pre-tax PV10% Value for 2004 was calculated using a
Henry Hub natural gas price of $6.185 per MMBtu and a West Texas Intermediate
Sweet price of $43.46 per barrel versus a Henry Hub natural gas price of $5.825
per MMBtu and a West Texas Intermediate Sweet price of $32.55 per barrel that
were used for the 2003 year-end.
Bud Brigham, the Chairman and CEO stated, "While we had a number of
accomplishments during 2004, it was a very disappointing and we believe
anomalous year in terms of reserves and finding costs. During most of the year
we failed to achieve the drilling successes, both developmental and exploratory,
that we have historically delivered. That changed late in the year, particularly
with regard to our Sartwelle #3 Appling Deep Field discovery, which has the
potential to become the largest field discovery in our history. However, this
discovery occurred too late in the year to materially impact our 2004 reserves,
though we expect it to have a very positive impact on our 2005 results.
"Thus, for the first time in our fourteen-year history, our reserves at
year-end were actually lower than that of the prior year. There are a number of
contributing factors. First, we aggressively drilled our PUD's, with
approximately 50% of our capital spent developing reserves already in our 2003
year-end reserve report. Unfortunately, several of our large proved undeveloped
wells generated surprising results, despite being direct offsets to very strong
producers, negatively impacting our year-end reserves.
"Second, in prior years we drilled significant discoveries that elevated
our overall results. In 2004 these came late in the year with our Sullivan C #30
well in our Triple Crown North joint venture, and with the Sartwelle #3 Appling
Deep Field discovery. However, because these wells came in so late in the year
their impact was limited. In the case of the Sartwelle #3 discovery, only 1.9
net Bcfe made our 2004 reserve report, thus we expect this field discovery to
have a positive impact on our 2005 performance.
"Since our first third party reserve report in 1992, inclusive of 2004,
we've averaged a total proved all-sources finding cost of $1.79. The last
disappointing year we had for finding costs was 1998. Subsequent to 1998, we
generated five consecutive years of attractive finding costs and reserve growth.
Since then, inclusive of 2004, our all sources total proved finding costs has
averaged $1.98 per Mcfe. As was the case in 1998, we believe that many of the
factors that negatively impacted 2004, position us for a very strong rebound in
both reserves and finding costs in 2005."
Equivalent Reserves
(Bcfe)
-------------------
2004 Beginning Reserves 134,182
Discoveries & Extensions 14,369
Revisions of Previous Estimates (14,996)
Production (12,265)
2004 Ending Reserves 121,290
CONFERENCE CALL INFORMATION
Brigham management will host a conference call to discuss its operational
and financial results for the fourth quarter and FY 2004 with investors,
analysts and other interested parties on Thursday, March 3rd, at 9:00 a.m.
Central time. To participate in the call, participants within the U.S. please
dial 800-299-7089 and participants outside the U.S. please dial 617-801-9714.
The participant passcode for the call is 31524905. A telephone recording of the
conference call will be available to interested parties approximately two hours
after the call is completed through 11:59 p.m. Central time on Thursday, March
17th. 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 61118666. In addition, a live and archived web cast of the
conference call will be available over the Internet at either
http://www.bexp3d.com or http://www.streetevents.com . 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
March 3, 2005, will be available on our website. To access the press release go
to http://www.bexp3d.com and click on News Releases. The file with a copy of the
press release is named Brigham Exploration Reports Year End Results Including
Record 2004 Financial Results and is dated March 2, 2005. To access the other
financial and statistical information that will be covered by the conference
call that will take place on March 3, 2005, go to http://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 2004 Conference Call and is dated March 2, 2005.
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 and develop onshore domestic natural gas and oil
provinces. For more information about Brigham Exploration, please visit our
website at http://www.bexp3d.com or contact Investor Relations at 512-427-3444.
FORWARD LOOKING STATEMENTS DISCLOSURE
Except for the historical information contained herein, the matters
discussed in this news release are forward looking statements within the meaning
of the Private Securities Litigation Reform Act of 1995 that are based upon
current expectations. Important factors that could cause actual results to
differ materially from those in the forward looking statements include risks
inherent in exploratory drilling activities, the timing and extent of changes in
commodity prices, unforeseen engineering and mechanical or technological
difficulties in drilling wells, availability of drilling rigs, land issues,
federal and state regulatory developments and other risks more fully described
in the company's filings with the Securities and Exchange Commission. 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: John Turner, Manager - Finance & Investor Relations
(512) 427-3300 / investor@bexp3d.com
BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Three Months Ended Year Ended
December 31, December 31,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
(unaudited)
Revenues:
Oil and natural gas
sales $ 19,738 $ 11,598 $ 71,713 $ 51,545
Other 446 19 515 132
$ 20,184 $ 11,617 $ 72,228 $ 51,677
Costs and expenses:
Lease operating 1,811 1,163 6,173 5,200
Production taxes 673 180 3,107 2,477
General and
administrative 1,669 1,080 5,392 4,500
Depletion of natural
gas and oil
properties 12,450 5,119 28,824 16,972
Depreciation and
amortization 178 180 722 629
Accretion of discount
on ARO 42 32 159 142
$ 16,823 $ 7,754 $ 44,377 $ 29,920
Operating income $ 3,361 $ 3,863 $ 27,851 $ 21,757
Interest expense, net (636) (1,038) (3,144) (4,815)
Interest income 29 9 84 45
Other income (expense) (a) 901 (351) 742 (601)
Income before income
taxes & cumulative
effect of adoption of
accounting principle $ 3,655 $ 2,483 $ 25,533 $ 16,386
Income tax benefit (1,866) 1,636 (9,120) 1,636
Cumulative effect of
adoption of accounting
principle - - - 268
Net income $ 1,769 $ 4,119 $ 16,413 $ 18,290
Preferred stock dividends
& accretion - 521 - 3,448
Net income (loss) to
common $ 1,769 $ 3,598 $ 16,413 $ 14,842
Net income (loss) to
common per share:
Basic $ 0.04 $ 0.11 $ 0.41 $ 0.64
Diluted $ 0.04 $ 0.10 $ 0.39 $ 0.53
Wt. Avg. common shares
outstanding:
Basic 42,005 32,346 40,445 23,363
Diluted 43,151 38,457 41,616 34,354
(a) Includes non-cash
gains/(losses) related
to our derivative
contracts: $ 852 $ (419) $ 625 $ (669)
BRIGHAM EXPLORATION COMPANY
PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA
Three Months Ended Year Ended
December 31, December 31,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
(unaudited)
Avg. net daily production:
Natural gas (MMcf) 25.8 19.0 24.5 17.7
Oil (Bbls) 1,375 1,754 1,590 1,999
Equivalent natural
gas (MMcfe) (6:1) 34.1 29.5 34.1 29.7
Total net production:
Natural gas (MMcf) 2,325 1,708 8,830 6,356
Oil (MBbls) 124 158 573 720
Equivalent natural
gas (MMcfe) (6:1) 3,067 2,655 12,265 10,674
% Natural gas 76% 64% 72% 60%
Sales prices (Before hedging):
Natural gas ($/Mcf) $ 6.56 $ 4.36 $ 6.05 $ 5.68
Oil ($/Bbl) 47.84 29.76 40.13 30.79
Equivalent natural gas
($/Mcfe) (6:1) 6.90 4.58 6.23 5.46
Realized prices (Post hedging):
Natural gas ($/Mcf) (a) $ 6.30 $ 4.23 $ 5.84 $ 4.92
Oil ($/Bbl) (a) 41.19 27.67 35.17 28.17
Equivalent natural gas
($/Mcfe) (6:1) (a) 6.44 4.37 5.85 4.83
(a) Includes the effects of
hedging gains (losses) of:
Natural gas ($/Mcf) $ (0.26) $ (0.13) $ (0.21) $ (0.76)
Oil ($/Bbl) (6.65) (2.09) (4.96) (2.62)
SUMMARY CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31, December 31,
2004 2003
------------ ------------
Assets:
Current assets $ 20,994 $ 20,835
Natural gas and oil properties, net (full cost
method) 255,820 197,311
Other property and equipment, net 1,209 1,219
Other non-current assets 2,125 4,851
Total assets $ 280,148 $ 224,216
Liabilities and stockholders' equity:
Current liabilities $ 40,494 $ 35,579
Notes payable 21,000 19,000
Senior subordinated notes 20,000 20,000
Redeemable preferred stock, Series A 9,520 8,794
Deferred income tax liability 6,875 -
Other non-current liabilities 2,986 2,498
Total liabilities $ 100,875 $ 85,871
Stockholders' equity 179,273 138,345
Total liabilities and stockholders' equity $ 280,148 $ 224,216
BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Three Months Ended Year Ended
December 31, December 31,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
(unaudited)
Cash flows from operating
activities:
Net income $ 1,769 $ 4,119 $ 16,413 $ 18,290
Depletion, depreciation and
amortization 12,628 5,299 29,546 17,601
Accretion of discount on ARO 42 32 159 142
Interest paid through issuance
of add'l senior sub. notes - 308 - 1,196
Interest paid through issuance
of add'l redeemable
preferred stock 188 179 726 340
Amortization of deferred loan
fees 192 244 766 1,053
Mkt value adjustments for
derivatives instruments (852) 419 (625) 669
Cumulative effect of adoption
of change in acctg prin - - - (268)
Tax benefit for the exercise of
stock options 577 - 577 -
Deferred income tax expense
(benefit) 1,309 (1,636) 8,543 (1,636)
Changes in working capital and
other items 3,023 302 276 4,304
Cash flows provided by
operating activities $ 18,876 $ 9,266 $ 56,381 $ 41,691
Cash flows used by investing
activities (23,162) (16,687) (84,645) (46,089)
Cash flows (used) provided by
financing activities (2,384) 2,184 24,766 (5,141)
Net increase (decrease) in
cash and cash equivalents $ (6,670) $ (5,237) $ (3,498) $ (9,539)
SUMMARY PER MCFE DATA
(unaudited)
Three Months Ended Year Ended
December 31, December 31,
------------------------ ------------------------
2004 2003 2004 2003
---------- ---------- ---------- ----------
Revenues:
Natural gas and oil sales $ 6.44 $ 4.37 $ 5.85 $ 4.83
Other revenue 0.15 0.01 0.04 0.01
$ 6.59 $ 4.38 $ 5.89 $ 4.84
Costs and expenses:
Lease operating 0.59 0.44 0.50 0.49
Production taxes 0.22 0.07 0.25 0.23
General and administrative 0.54 0.41 0.44 0.42
Depletion of natural gas
and oil properties 4.06 1.93 2.35 1.59
Depreciation and
amortization 0.06 0.07 0.06 0.06
Accretion of discount on ARO 0.01 0.01 0.01 0.01
$ 5.48 $ 2.93 $ 3.61 $ 2.80
Operating income $ 1.11 $ 1.45 $ 2.28 $ 2.04
Interest expense, net (a) (0.20) (0.45) (0.25) (0.45)
Other income (expense) (b) 0.02 0.03 0.01 0.01
Adjusted income before
dividends & accretion $ 0.93 $ 1.03 $ 2.04 $ 1.60
(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
BRIGHAM EXPLORATION COMPANY
SUMMARY OF COMMODITY PRICE HEDGES OUTSTANDING AS OF MARCH 2, 2005
(unaudited)
FY 2005 FY 2006
Hedge ------------------- -------------------
Strategy Q1 Q2 Q3 Q4 Q1
------------ -------- -------- -------- -------- --------
Natural Gas Collars:
Daily MMBtu/d 5,750 6,978 1,957 652 --
volumes
Floor $/MMBtu Cash flow $ 4.663 $ 4.931 $ 5.450 $ 5.450 --
(Purchased put)
Cap $/MMBtu Cash flow $ 7.100 $ 7.077 $ 8.000 $ 8.000 --
(Written call)
Natural Gas Three Way Costless Collars:
Daily MMBtu/d 2,333 -- 3,261 2,174 1,667
volumes
Floor $/MMBtu Cash flow $ 6.400 -- $ 6.000 $ 6.380 $ 6.750
(Purchased put)
Cap $/MMBtu Cash flow $ 7.640 -- $ 7.200 $ 8.000 $ 8.800
(Written call)
Written $/MMBtu Undesignated $ 5.500 -- $ 5.000 $ 5.250 $ 5.500
put
Crude Oil Collars:
Daily Bbls/d 305 205 -- -- --
volumes
Floor $/Bbl Cash flow $ 25.56 $ 26.80 -- -- --
(Purchased put)
Cap $/Bbl Cash flow $ 30.18 $ 32.51 -- -- --
(Written call)
Crude Oil Three Way Costless Collars:
Daily Bbls/d -- -- 163 163 --
volumes
Floor $/Bbl Cash flow -- -- $ 40.00 $ 40.00 --
(Purchased put)
Cap $/Bbl Cash flow -- -- $ 53.00 $ 53.00 --
(Written call)
Written $/Bbl Undesignated -- -- $ 30.00 $ 30.00 --
put
Note: 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.
SOURCE Brigham Exploration Company
-0- 03/03/2005
/CONTACT: John Turner, Manager - Finance & Investor Relations of Brigham
Exploration Company, +1-512-427-3300, or investor@bexp3d.com /
/Web site: http://www.bexp3d.com /