Attached files
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8-K - FORM 8-K - BRIGHAM EXPLORATION CO | c21136e8vk.htm |
EX-99.2 - EX-99.2 - BRIGHAM EXPLORATION CO | c21136exv99w2.htm |
Exhibit 99.1
NEWS RELEASE FOR IMMEDIATE RELEASE |
BRIGHAM EXPLORATION REPORTS RECORD QUARTERLY PRODUCTION VOLUMES, RECORD EARNINGS EXCLUDING CERTAIN
ITEMS, SECOND QUARTER 2011 RESULTS AND UPDATES 2011 FORECASTS
Austin, TX August 8, 2011 Brigham Exploration Company (NASDAQ:BEXP) today announced
record quarterly production volumes, record earnings excluding certain items and its financial
results for the second quarter and six months ended June 30, 2011.
SECOND QUARTER 2011 RESULTS
Our average daily production volumes for the second quarter 2011 were a quarterly record
12,206 barrels of crude oil equivalent (Boe) per day, up 57% from the second quarter 2010 and up 8%
from the first quarter 2011. Our previous record quarterly production volumes of 11,384 Boe per
day were achieved in the fourth quarter 2010.
Benefiting from both our operated and non-operated drilling activity in the Williston Basin,
our crude oil production volumes for the second quarter 2011 averaged 10,208 barrels per day, which
represents an 83% increase from that in the second quarter 2010 and an 11% sequential increase from
that in the first quarter 2011. Our crude oil production volumes represented 84% of our total
production volumes in the second quarter 2011 as compared to 72% in the second quarter 2010 and 81%
in the first quarter 2011.
Our production volumes in the Williston Basin for the second quarter 2011 were 10,401 Boe per
day, which represents an 88% increase from that in the second quarter 2010 and an 11% sequential
increase from that in the first quarter 2011.
Our second quarter production volumes included approximately 18,156 barrels of crude oil
produced during the quarter and added to inventory. Adjusting our production volumes for amounts
included in inventory resulted in second quarter 2011 daily sales volumes of 12,004 Boe per day.
Revenues from the sale of crude oil and natural gas, including cash hedge settlements for the
second quarter 2011, were up 120% to $91.3 million as compared to that in the second quarter 2010.
Higher crude oil sales volumes and crude oil prices increased revenues by $27.9 million and $25.0
million, respectively. Higher natural gas prices also increased revenues by $0.7 million. Lower
cash hedge settlements and natural gas sales volumes decreased revenues by $3.3 million and $0.5
million, respectively.
During the second quarter 2011, our average realized price for crude oil was $93.86 per
barrel, which included a $3.15 per barrel cash loss due to the settlement of our crude oil
derivative contracts. This compares to an average realized price in the second quarter 2010 of
$68.93 per barrel, which included a $0.26 per barrel cash loss due to the settlement of our crude
oil derivative contracts. Our average realized price for natural gas inclusive of natural gas
liquids in the second quarter 2011 was $6.24 per Mcf, which included a $0.34 per Mcf cash gain
associated with the settlement of our natural gas derivative contracts. This compares to an
average realized price in the second quarter 2010 of $6.08 per Mcf, which included a $0.84 per Mcf
cash gain due to the settlement of our natural gas derivative contracts.
Our second quarter 2011 production costs, which include costs for operating and maintaining
(O&M expense) our producing wells, expensed workovers, ad valorem taxes and production taxes,
increased $4.90 per Boe when compared to those in the second quarter 2010. The increase was
largely attributable to a $3.12 per Boe increase in production taxes, which was driven by higher
commodity prices and higher levels of production in North Dakota, which are subject to an 11.5% tax
rate. The increase was also partially attributable to a $1.88 per Boe increase in O&M expense,
partially attributable to increased costs associated with surface location and road repairs
following the record winter snowfall melt and subsequent heavy rains and higher produced water
disposal costs for volumes injected at third party disposal wells.
Our general and administrative (G&A) expenses for the second quarter 2011 decreased by $0.98
per Boe to $2.93 per Boe due to our higher sales volumes. The per unit decrease associated with
our higher sales volumes was partially offset by an increase in employee compensation costs due to
higher levels of non-cash stock compensation expense.
Our depletion expense for the second quarter 2011 was $23.5 million ($21.79 per Boe) compared
to $14.2 million
($20.56 per Boe) in the second quarter 2010. Our higher sales volumes increased depletion
expense by $8.0 million and our higher depletion rate increased depletion expense by $1.3 million.
Our net interest expense for the second quarter 2011 was $2.9 million higher than that in the
second quarter 2010. Interest expense increased due to the September 2010 issuance of our $300
million Senior Notes due 2018 and the May 2011 issuance of our $300 million Senior Notes due 2019.
These increases were partially offset by an increase in our capitalized interest associated with
our higher level of drilling activity in the Williston Basin.
We recorded deferred income tax expense of $8.9 million in the second quarter 2011, which
consists of $6.2 million in deferred federal income tax expense and $2.7 million in deferred North
Dakota state income tax expense.
Our reported net income for the second quarter 2011 was $70.8 million ($0.60 per diluted
share) versus net income of $18.5 million ($0.16 per diluted share) for the same period last year.
Our after-tax earnings in the second quarter 2011 excluding unrealized mark-to-market hedging gains
were $38.7 million ($0.33 per diluted share) as compared to our after-tax earnings in the second
quarter 2010 excluding unrealized mark-to-market hedging gains were $15.0 million ($0.13 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 second quarter, 2011, we spent $244.1 million in oil and gas capital expenditures.
Capital expenditures for the second quarter 2011 and 2010 were:
Three months ended June 30, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Drilling |
$ | 166,014 | $ | 71,324 | ||||
Support infrastructure |
27,572 | | ||||||
Land |
50,503 | 21,062 | ||||||
Oil and gas capital expenditures |
$ | 244,089 | $ | 92,386 | ||||
Capitalized costs |
6,918 | 4,405 | ||||||
Capitalized FAS 143 ARO |
374 | 205 | ||||||
Total capital expenditures |
$ | 251,381 | $ | 96,996 | ||||
FIRST SIX MONTHS 2011 RESULTS
Our average daily production volumes for the first six months of 2011 were 11,760 barrels of
crude oil equivalent (Boe) per day, up 79% from that in the first six months of 2010. Benefiting
from both our operated and non-operated drilling activity in the Williston Basin, our crude oil
production volumes for the first six months of 2011 averaged 9,710 barrels per day, which
represents a 113% increase from that in the first six months of 2010. Our crude oil production
volumes represented 83% of our total production volumes in the first six months of 2011 as compared
to 69% in the first six months of 2010.
Our production volumes in the Williston Basin for the first six months of 2011 were 9,890 Boe
per day, which represents a 126% increase from that in the first six months of 2010.
Our first six months of 2011 production volumes included approximately 18,888 barrels of crude
oil produced and added to inventory during the period. Adjusting our production volumes for
amounts included in inventory results in average first six months of 2011 daily sales volumes of
11,655 Boe per day.
Revenues from the sale of crude oil and natural gas, including cash hedge settlements for the
first six months of 2011, were up 136% to $167.3 million as compared to that in the first six
months of 2010. Higher crude oil sales volumes and crude oil prices increased revenues by $64.7
million and $35.0 million, respectively. Higher natural gas sales volumes and natural gas prices
also increased revenues by $0.2 million and $0.4 million, respectively. Lower cash hedge
settlements decreased revenues by $3.9 million.
Page 2
During the first six months of 2011, our average realized price for crude oil was $88.54 per
barrel, which included a
$2.25 per barrel cash loss due to the settlement of our crude oil derivative contracts. This
compares to an average realized price in the first six months of 2010 of $70.27 per barrel, which
included a $0.28 per barrel cash loss due to the settlement of our crude oil derivative contracts.
Our average realized price for natural gas inclusive of natural gas liquids in the first six months
of 2011 was $6.41 per Mcf, which included a $0.66 per Mcf cash gain associated with the settlement
of our natural gas derivative contracts. This compares to an average realized price in the first
six months of 2010 of $6.36 per Mcf, which included a $0.77 per Mcf cash gain due to the settlement
of our natural gas derivative contracts.
Our production costs for the first six months of 2011 increased $3.14 per Boe when compared to
those in the corresponding period last year. The increase was largely attributable to a $2.72 per
Boe increase in production taxes, which was driven by higher commodity prices and higher levels of
production in North Dakota, which are subject to an 11.5% tax rate, and a $1.07 per Boe increase in
O&M expense, partially due to increased costs associated with surface location and road repairs
following the record winter snowfall melt and subsequent heavy rains and higher produced water
disposal costs for volumes injected at third party disposal wells. These increases were partially
offset by a $0.77 per Boe decrease in expensed workovers due to our higher sales volumes.
Our G&A expenses for the first six months of 2011 decreased by $1.81 per Boe as compared to
the first six months of 2010 due to our higher sales volumes. The per unit decrease associated
with our higher sales volumes was partially offset by an increase in employee compensation costs
due to higher levels of non-cash stock compensation expense.
Our depletion expense for the first six months of 2011 was $42.5 million ($20.24 per Boe)
versus $23.5 million ($19.95 per Boe) in the first six months of 2010. Our higher sales volumes
increased depletion expense by $18.4 million and our higher depletion rate increased depletion
expense by $0.6 million.
Our net interest expense for the first six months of 2011 was $3.3 million higher than that in
the corresponding period last year. Interest expense increased due to the September 2010 issuance
of our $300 million Senior Notes due 2018 and the May 2011 issuance of our $300 million Senior
Notes due 2019. These increases were partially offset by an increase in our capitalized interest
associated with our higher level of drilling activity in the Williston Basin.
We recorded deferred income tax expense of $9.1 million in the first six months of 2011, which
consists of $6.3 million in deferred federal income tax expense and $2.8 million in deferred North
Dakota state income tax expense.
Our reported net income for the first six months of 2011 was $72.4 million ($0.61 per diluted
share) versus net income of $29.8 million ($0.27 per diluted share) for the same period last year.
Our after-tax earnings in the first six months of 2011 excluding unrealized mark-to-market hedging
losses were $72.5 million ($0.61 per diluted share) as compared to our after-tax earnings in the
first six months of 2010 excluding unrealized mark-to-market hedging gains were $23.2 million
($0.21 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.
Through June 30, 2011, we spent $366.9 million in oil and gas capital expenditures. Capital
expenditures for the first six months of 2011 and 2010 were:
Six months ended June 30, | ||||||||
2011 | 2010 | |||||||
(in thousands) | ||||||||
Drilling |
$ | 276,792 | $ | 114,930 | ||||
Support infrastructure |
32,836 | | ||||||
Land |
57,273 | 29,539 | ||||||
Oil and gas capital expenditures |
$ | 366,901 | $ | 144,469 | ||||
Capitalized costs |
13,559 | 8,974 | ||||||
Capitalized FAS 143 ARO |
552 | 257 | ||||||
Total capital expenditures |
$ | 381,012 | $ | 153,700 | ||||
Page 3
THIRD QUARTER AND FULL YEAR 2011 FORECASTS
The following forecasts and estimates for the third quarter and fourth quarter 2011 are
forward-looking statements subject to the risks and uncertainties identified in the
Forward-Looking Statements Disclosure at the end of this release.
We are forecasting that our third quarter 2011 production volumes will average between 15,000
Boe per day and 16,200 Boe per day and that our crude oil volumes will comprise approximately 84%
of our third quarter production volumes. We are confirming that our previously issued full year
2011 production volumes will average between 14,000 Boe per day and 16,000 Boe per day and that our
crude oil volumes will comprise approximately 84% of our full year production volumes.
For the third quarter 2011, lease operating expenses are projected to be $7.92 per Boe based
on the mid-point of our production guidance, production taxes are projected to be approximately
10.0 to 10.5% of pre-hedge crude oil and natural gas revenues, and general and administrative
expenses are projected to be $3.1 million ($2.21 per Boe).
MANAGEMENT COMMENTS
Gene Shepherd, Brighams Chief Financial Officer, commented, Continued strong performance of
our horizontal Bakken and Three Forks drilling program led to another record quarter for production
volumes, revenues and operating income. Furthermore, based on our 2011 production guidance, we
expect to see significant growth in our production volumes in the second half of the year.
Gene Shepherd continued, Based on the growth in our production volumes and the strong
commodity price realizations during the quarter, our per unit operating margins, which represent
revenues including realized hedging gains and losses less lease operation expense, production taxes
and cash G&A, reached a record $65.14 per barrel, an improvement of 21% from the record $54.06 per
barrel operating margins that we achieved in the first quarter. Given that we have drilled a total
of 79 horizontal Bakken and Three Forks wells using our current formula and given the consistency
of our results, we have excellent visibility as to our future financial performance and future
liquidity needs.
CONFERENCE CALL INFORMATION
Our management will host a conference call to discuss operational and financial results for
the second quarter 2011 with investors, analysts and other interested parties on Tuesday, August 9,
at 11:00 a.m. Eastern Time. To participate in the call, participants within the U.S./Canada please
dial 877-398-9480 and participants outside the U.S./Canada please dial 708-290-1157. The
conference ID number for the call is 86489005. A telephone recording of the conference call will
be available approximately two hours after the call is completed through 11:59 p.m. Eastern Time on
Tuesday, August 16, 2011. For toll-free access to the recording, dial 855-859-2056. The
conference ID number for the call is 86489005. In addition, a live and archived web cast of the
conference call will be available over the Internet at www.bexp3d.com.
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 Tuesday, August 9, 2011, will be available on our
website. To access the press release, go to www.bexp3d.com, click on Investor Relations and then
click on Press Releases. The file with a copy of the press release is named Brigham Exploration
Reports Second Quarter 2011 Results and is dated Monday, August 8, 2011. To access the other
financial and statistical information that will be covered by the conference call that will take
place on Tuesday, August 9, 2011, go to www.bexp3d.com, click on Investor Relations and then click
on Events & Presentations. The file with the other financial and statistical information is named
Financial and Statistical Information for the Second Quarter 2011 Conference Call and is dated
Tuesday, August 9, 2011.
ABOUT BRIGHAM EXPLORATION
Brigham Exploration Company is an independent exploration, development and production company
that utilizes advanced exploration, drilling and completion technologies to systematically explore
for, develop and produce domestic onshore 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.
Page 4
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 federal securities laws. Important
factors that could cause our actual results to differ
materially from those contained in the forward-looking statements include early initial
production rates which decline steeply over the early life of wells, particularly our Williston
basin horizontal wells for which we estimate the average monthly production rates may decline by
approximately 70% in the first twelve months of production, our growth strategies, our ability to
successfully and economically explore for and develop oil and natural 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
companys 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 managements 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, Director of Finance & Investor Relations | |
(512) 427-3300 |
Page 5
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 | Six months ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues: |
||||||||||||||||
Crude oil sales |
$ | 87,361 | $ | 34,423 | $ | 156,957 | $ | 57,293 | ||||||||
Natural gas sales |
6,365 | 6,141 | 12,732 | 12,201 | ||||||||||||
Hedging settlements |
(2,468 | ) | 861 | (2,418 | ) | 1,443 | ||||||||||
91,258 | 41,425 | 167,271 | 70,937 | |||||||||||||
Unrealized hedging gains (losses) |
35,889 | 3,501 | (119 | ) | 6,553 | |||||||||||
127,147 | 44,926 | 167,152 | 77,490 | |||||||||||||
Support infrastructure |
890 | | 1,484 | | ||||||||||||
Other revenue |
3 | 4 | 5 | 13 | ||||||||||||
Total revenue |
128,040 | 44,930 | 168,641 | 77,503 | ||||||||||||
Costs and expenses: |
||||||||||||||||
Lease operating |
8,724 | 4,371 | 16,444 | 8,720 | ||||||||||||
Production taxes |
9,451 | 3,900 | 17,149 | 6,408 | ||||||||||||
Support infrastructure |
529 | | 719 | | ||||||||||||
General and administrative |
3,165 | 2,711 | 6,547 | 5,797 | ||||||||||||
Depletion of crude oil and natural gas properties |
23,531 | 14,247 | 42,471 | 23,458 | ||||||||||||
Depreciation and amortization |
1,244 | 261 | 2,215 | 494 | ||||||||||||
Accretion of discount on asset retirement obligations |
113 | 104 | 223 | 209 | ||||||||||||
46,757 | 25,594 | 85,768 | 45,086 | |||||||||||||
Operating income (loss) |
81,283 | 19,336 | 82,873 | 32,417 | ||||||||||||
Other income (expense): |
||||||||||||||||
Interest expense, net |
(5,794 | ) | (2,931 | ) | (9,172 | ) | (5,835 | ) | ||||||||
Interest income |
342 | 887 | 709 | 1,340 | ||||||||||||
Other income (expense) |
3,934 | 1,181 | 7,088 | 1,866 | ||||||||||||
(1,518 | ) | (863 | ) | (1,375 | ) | (2,629 | ) | |||||||||
Income before income taxes |
79,765 | 18,473 | 81,498 | 29,788 | ||||||||||||
Income tax (expense): |
||||||||||||||||
Current |
| | | | ||||||||||||
Deferred |
(8,930 | ) | | (9,109 | ) | | ||||||||||
(8,930 | ) | | (9,109 | ) | | |||||||||||
Net income (loss) |
$ | 70,835 | $ | 18,473 | $ | 72,389 | $ | 29,788 | ||||||||
Net income per share available to common stockholders: |
||||||||||||||||
Basic |
$ | 0.61 | $ | 0.16 | $ | 0.62 | $ | 0.28 | ||||||||
Diluted |
$ | 0.60 | $ | 0.16 | $ | 0.61 | $ | 0.27 | ||||||||
Weighted average shares outstanding: |
||||||||||||||||
Basic |
116,408 | 113,426 | 116,384 | 106,473 | ||||||||||||
Diluted |
118,524 | 115,383 | 118,533 | 108,491 | ||||||||||||
Page 6
BRIGHAM EXPLORATION COMPANY
PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA
(unaudited)
PRODUCTION, SALES PRICES AND OTHER FINANCIAL DATA
(unaudited)
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Average net daily production volumes: |
||||||||||||||||
Crude oil (Bbls) |
10,208 | 5,584 | 9,710 | 4,568 | ||||||||||||
Natural gas (MMcf) |
12.0 | 13.0 | 12.3 | 12.1 | ||||||||||||
Equivalent crude oil (Boe) (6:1) |
12,206 | 7,756 | 11,760 | 6,588 | ||||||||||||
Total net production volumes: |
||||||||||||||||
Crude oil (MBbls) |
919 | 503 | 1,748 | 822 | ||||||||||||
Natural gas (MMcf) |
1,079 | 1,173 | 2,215 | 2,182 | ||||||||||||
Equivalent crude oil (MBoe) (6:1) |
1,099 | 698 | 2,117 | 1,186 | ||||||||||||
% Crude oil |
84 | % | 72 | % | 83 | % | 69 | % | ||||||||
Increase in inventory: |
||||||||||||||||
Crude oil (Bbls) |
18,156 | 5,089 | 18,888 | 10,101 | ||||||||||||
Natural gas (MMcf) |
| | | | ||||||||||||
Equivalent crude oil (Boe) (6:1) |
18,156 | 5,089 | 18,888 | 10,101 | ||||||||||||
Average net daily sales volumes (Average net
production
volumes less average net daily increase in inventory): |
||||||||||||||||
Crude oil (Bbls) |
10,007 | 5,528 | 9,605 | 4,512 | ||||||||||||
Natural gas (MMcf) |
12.0 | 13.0 | 12.3 | 12.1 | ||||||||||||
Equivalent crude oil (Boe) (6:1) |
12,004 | 7,700 | 11,655 | 6,532 | ||||||||||||
Total net sales volumes (Total net production volumes
less increase in inventory): |
||||||||||||||||
Crude oil (MBbls) |
901 | 497 | 1,729 | 812 | ||||||||||||
Natural gas (MMcf) |
1,079 | 1,173 | 2,215 | 2,182 | ||||||||||||
Equivalent crude oil (MBoe) (6:1) |
1,080 | 693 | 2,098 | 1,176 | ||||||||||||
% Crude oil |
83 | % | 72 | % | 82 | % | 69 | % | ||||||||
Sales price: |
||||||||||||||||
Crude oil ($/Bbl) |
$ | 97.01 | $ | 69.19 | $ | 90.79 | $ | 70.55 | ||||||||
Natural gas ($/Mcf) |
5.90 | 5.24 | 5.75 | 5.59 | ||||||||||||
Equivalent crude oil ($/Boe) (6:1) |
86.75 | 58.53 | 80.88 | 59.09 | ||||||||||||
Sales price including derivative settlement gains
(losses): |
||||||||||||||||
Crude oil ($/Bbl) |
$ | 93.86 | $ | 68.93 | $ | 88.54 | $ | 70.27 | ||||||||
Natural gas ($/Mcf) |
6.24 | 6.08 | 6.41 | 6.36 | ||||||||||||
Equivalent crude oil ($/Boe) (6:1) |
84.47 | 59.78 | 79.73 | 60.32 | ||||||||||||
Sales price including derivative settlement gains
(losses) and unrealized gains (losses): |
||||||||||||||||
Crude oil ($/Bbl) |
$ | 134.01 | $ | 79.16 | $ | 89.20 | $ | 77.12 | ||||||||
Natural gas ($/Mcf) |
5.98 | 4.73 | 5.84 | 6.81 | ||||||||||||
Equivalent crude oil ($/Boe) (6:1) |
117.69 | 64.83 | 79.67 | 65.89 |
Page 7
SUMMARY CONSOLIDATED BALANCE SHEETS
(in thousands)
(in thousands)
June 30, 2011 | December 31, 2010 | |||||||
(unaudited) | ||||||||
Assets: |
||||||||
Current assets |
$ | 528,503 | $ | 360,857 | ||||
Oil and natural gas properties, net (full cost method) |
973,983 | 669,356 | ||||||
Other property and equipment, net |
75,075 | 42,837 | ||||||
Other non-current assets |
22,922 | 12,351 | ||||||
Total assets |
$ | 1,600,483 | $ | 1,085,401 | ||||
Liabilities and stockholders equity: |
||||||||
Current liabilities |
$ | 307,807 | $ | 176,545 | ||||
Senior notes |
600,000 | 300,000 | ||||||
Other non-current liabilities |
23,734 | 15,586 | ||||||
Total liabilities |
$ | 931,541 | $ | 492,131 | ||||
Stockholders equity |
668,942 | 593,270 | ||||||
Total liabilities and stockholders equity |
$ | 1,600,483 | $ | 1,085,401 | ||||
BRIGHAM EXPLORATION COMPANY
SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) (unaudited)
SUMMARY CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) (unaudited)
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Cash flows from operating activities: |
||||||||||||||||
Net income |
$ | 70,835 | $ | 18,473 | $ | 72,389 | $ | 29,788 | ||||||||
Depletion, depreciation and amortization |
24,775 | 14,508 | 44,686 | 23,952 | ||||||||||||
Accretion of discount on ARO |
113 | 104 | 223 | 209 | ||||||||||||
Amortization of deferred loan fees and debt issuance costs |
615 | 508 | 1,141 | 1,014 | ||||||||||||
Non-cash stock compensation |
1,097 | 611 | 1,844 | 1,038 | ||||||||||||
Market value adjustments for derivatives instruments |
(35,889 | ) | (6,208 | ) | 119 | (9,260 | ) | |||||||||
Deferred income tax expense |
8,930 | | 9,109 | | ||||||||||||
Provision for doubtful accounts |
| | (2 | ) | | |||||||||||
Other noncash items |
| | | (1 | ) | |||||||||||
Changes in operating assets and liabilities |
23,754 | 12,951 | 30,932 | 20,180 | ||||||||||||
Cash flows provided by operating activities |
$ | 94,230 | $ | 40,947 | $ | 160,441 | $ | 66,920 | ||||||||
Cash flows (used) by investing activities |
(227,344 | ) | (250,882 | ) | (292,869 | ) | (293,792 | ) | ||||||||
Cash flows provided by financing activities |
294,217 | 268,281 | 290,374 | 268,913 | ||||||||||||
Net increase (decrease) in cash and cash equivalents |
$ | 161,103 | $ | 58,346 | $ | 157,946 | $ | 42,041 | ||||||||
Page 8
SUMMARY PER BOE DATA
(unaudited)
(unaudited)
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenues: |
||||||||||||||||
Crude oil and natural gas sales |
$ | 86.75 | $ | 58.53 | $ | 80.88 | $ | 59.09 | ||||||||
Hedge settlements |
(2.28 | ) | 1.24 | (1.15 | ) | 1.23 | ||||||||||
Unrealized hedge gains (losses) |
33.22 | 5.05 | (0.06 | ) | 5.57 | |||||||||||
Support infrastructure |
0.82 | | 0.71 | | ||||||||||||
Other revenue |
0.00 | 0.01 | 0.00 | 0.01 | ||||||||||||
$ | 118.51 | $ | 64.83 | $ | 80.38 | $ | 65.90 | |||||||||
Costs and expenses: |
||||||||||||||||
Lease operating |
8.08 | 6.30 | 7.84 | 7.42 | ||||||||||||
Production taxes |
8.75 | 5.63 | 8.17 | 5.45 | ||||||||||||
Support infrastructure |
0.49 | | 0.34 | | ||||||||||||
General and administrative |
2.93 | 3.91 | 3.12 | 4.93 | ||||||||||||
Depletion of crude oil and natural gas properties |
21.79 | 20.56 | 20.24 | 19.95 | ||||||||||||
Depreciation and amortization |
1.15 | 0.38 | 1.06 | 0.42 | ||||||||||||
Accretion of discount on ARO |
0.10 | 0.15 | 0.11 | 0.18 | ||||||||||||
$ | 43.29 | $ | 36.93 | $ | 40.88 | $ | 38.35 | |||||||||
Operating income (loss) |
$ | 75.22 | $ | 27.90 | $ | 39.50 | $ | 27.55 | ||||||||
Interest expense, net of interest income (a) |
(5.05 | ) | (2.94 | ) | (4.04 | ) | (3.82 | ) | ||||||||
Other income (expense) |
3.64 | 1.70 | 3.38 | 1.59 | ||||||||||||
Adjusted income |
$ | 73.81 | $ | 26.66 | $ | 38.84 | $ | 25.32 | ||||||||
(a) | Calculated as interest expense minus interest income divided by production for period. |
BRIGHAM EXPLORATION COMPANY
RECONCILIATION OF GAAP NET INCOME TO EARNINGS WITHOUT THE EFFECT OF CERTAIN ITEMS
(in thousands)
RECONCILIATION OF GAAP NET INCOME TO EARNINGS WITHOUT THE EFFECT OF CERTAIN ITEMS
(in thousands)
Three months ended June 30, | Six months ended June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income (loss) as reported |
$ | 70,835 | $ | 18,473 | $ | 72,389 | $ | 29,788 | ||||||||
Unrealized derivative (gains) losses |
(35,889 | ) | (3,501 | ) | 119 | (6,553 | ) | |||||||||
Tax impact |
3,707 | | (13 | ) | | |||||||||||
Earnings without the effect of certain items |
$ | 38,653 | $ | 14,972 | $ | 72,495 | $ | 23,235 | ||||||||
Earnings without the effect of certain items represent net income excluding both unrealized
gains and losses on derivative contracts and our non-cash impairment change in our oil and gas
properties. Management believes that exclusion of both of these items will help enhance
comparability of operating results between periods.
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SUMMARY OF COMMODITY PRICE HEDGES OUTSTANDING AS OF AUGUST 8, 2011
(unaudited)
(unaudited)
2011 | 2012 | 2013 | ||||||||||||||||||||||||||||||
Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | |||||||||||||||||||||||||
Crude Oil Costless Collars: |
||||||||||||||||||||||||||||||||
Daily volumes Bbls/d |
7,587 | 9,207 | 8,239 | 8,580 | 10,168 | 10,000 | 9,000 | 1,341 | ||||||||||||||||||||||||
Floor $/Bbl |
$ | 67.69 | $ | 70.84 | $ | 69.03 | $ | 69.46 | $ | 71.71 | $ | 73.99 | $ | 80.38 | $ | 85.00 | ||||||||||||||||
Cap $/Bbl |
$ | 103.57 | $ | 109.45 | $ | 109.07 | $ | 110.07 | $ | 114.56 | $ | 116.11 | $ | 125.25 | $ | 134.00 | ||||||||||||||||
Crude Oil Floors: |
||||||||||||||||||||||||||||||||
Daily volumes Bbls/d |
| | 1,500 | 1,500 | 1,500 | 1,500 | | | ||||||||||||||||||||||||
Floor $/Bbl |
$ | | $ | | $ | 65.00 | $ | 65.00 | $ | 80.00 | $ | 80.00 | $ | | $ | | ||||||||||||||||
Natural Gas Costless Collars: |
||||||||||||||||||||||||||||||||
Daily volumes MMBtu/d |
3,587 | 3,587 | | | | | | | ||||||||||||||||||||||||
Floor $/MMBtu |
$ | 5.48 | $ | 5.48 | $ | | $ | | $ | | $ | | $ | | $ | | ||||||||||||||||
Cap $/MMBtu |
$ | 7.16 | $ | 7.16 | $ | | $ | | $ | | $ | | $ | | $ | | ||||||||||||||||
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.
Page 10