Attached files
file | filename |
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EX-31.2 - EXHIBIT 31.2 - BRIGHAM EXPLORATION CO | c07726exv31w2.htm |
EX-32.2 - EXHIBIT 32.2 - BRIGHAM EXPLORATION CO | c07726exv32w2.htm |
EX-31.1 - EXHIBIT 31.1 - BRIGHAM EXPLORATION CO | c07726exv31w1.htm |
EX-32.1 - EXHIBIT 32.1 - BRIGHAM EXPLORATION CO | c07726exv32w1.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2010
OR
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-34224
Brigham Exploration Company
(Exact name of registrant as specified in its charter)
Delaware (State of other jurisdiction of incorporation or organization) |
75-2692967 (I.R.S. Employer Identification No.) |
6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730
(Address of principal executive offices) (Zip Code)
(Address of principal executive offices) (Zip Code)
(512) 427-3300
(Registrants telephone number, including area code)
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§ 232 405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer or a smaller reporting company. See definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer o | Accelerated Filer þ | Non-Accelerated Filer o | Smaller Reporting Company o | |||
(Do not check if smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
Class | Outstanding | |||
Common Stock, par value $.01 per share as of November 3, 2010 |
116,879,973 |
Brigham Exploration Company
Third Quarter 2010 Form 10-Q Report
TABLE OF CONTENTS
Page | ||||||||
1 | ||||||||
2 | ||||||||
3 | ||||||||
4 | ||||||||
5 | ||||||||
18 | ||||||||
35 | ||||||||
39 | ||||||||
40 | ||||||||
40 | ||||||||
40 | ||||||||
40 | ||||||||
40 | ||||||||
40 | ||||||||
41 | ||||||||
43 | ||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 |
Table of Contents
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
(Unaudited)
September 30, | December 31, | |||||||
2010 | 2009 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 126,004 | $ | 40,781 | ||||
Accounts receivable |
42,618 | 21,194 | ||||||
Short-term investments |
189,267 | 80,093 | ||||||
Inventory |
28,756 | 14,087 | ||||||
Other current assets |
6,113 | 2,284 | ||||||
Total current assets |
392,758 | 158,439 | ||||||
Oil and natural gas properties, using the full cost method including
Proved, net of accumulated depletion of $404,266 and $365,496 |
420,251 | 254,424 | ||||||
Unproved |
181,179 | 76,309 | ||||||
601,430 | 330,733 | |||||||
Other property and equipment, net |
16,311 | 3,025 | ||||||
Deferred loan fees |
8,622 | 5,213 | ||||||
Other noncurrent assets |
3,410 | 846 | ||||||
Total assets |
$ | 1,022,531 | $ | 498,256 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 39,825 | $ | 19,251 | ||||
Royalties payable |
27,604 | 8,268 | ||||||
Accrued drilling costs |
57,103 | 15,498 | ||||||
Participant advances received |
2,762 | 6,949 | ||||||
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000
shares authorized, 505,051 shares issued and outstanding at December 31, 2009 |
| 10,101 | ||||||
Senior Notes |
5,594 | | ||||||
Other current liabilities |
5,730 | 7,706 | ||||||
Total current liabilities |
138,618 | 67,773 | ||||||
Senior Notes |
300,000 | 158,968 | ||||||
Other noncurrent liabilities |
9,225 | 7,232 | ||||||
Commitments and contingencies (Note 4) |
||||||||
Stockholders equity: |
||||||||
Common stock, $.01 par value, 180 million shares authorized, 116,299,942 and 99,593,075 shares issued and
116,027,460 and 99,351,825 shares outstanding at September 30, 2010 and December 31, 2009, respectively |
1,163 | 996 | ||||||
Additional paid-in capital |
762,535 | 479,077 | ||||||
Treasury stock, at cost; 272,482 and 241,250 shares at September 30, 2010 and December 31, 2009, respectively |
(2,604 | ) | (2,133 | ) | ||||
Accumulated other comprehensive income (loss) |
(2,066 | ) | (205 | ) | ||||
Retained earnings (deficit) |
(184,340 | ) | (213,452 | ) | ||||
Total stockholders equity |
574,688 | 264,283 | ||||||
Total liabilities and stockholders equity |
$ | 1,022,531 | $ | 498,256 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
1
Table of Contents
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Revenues: |
||||||||||||||||
Oil and natural gas sales |
$ | 43,663 | $ | 18,747 | $ | 113,157 | $ | 45,765 | ||||||||
Gain (loss) on derivatives, net |
(7,057 | ) | 1,114 | 939 | 3,030 | |||||||||||
Other revenue |
4 | 6 | 17 | 72 | ||||||||||||
36,610 | 19,867 | 114,113 | 48,867 | |||||||||||||
Costs and expenses: |
||||||||||||||||
Lease operating |
3,964 | 3,279 | 12,684 | 10,651 | ||||||||||||
Production taxes |
4,250 | 1,551 | 10,658 | 3,196 | ||||||||||||
General and administrative |
3,255 | 2,082 | 9,052 | 6,468 | ||||||||||||
Depletion of oil and natural gas properties |
15,312 | 7,835 | 38,770 | 23,901 | ||||||||||||
Impairment of oil and natural gas properties |
| | | 114,781 | ||||||||||||
Depreciation and amortization |
362 | 234 | 856 | 550 | ||||||||||||
Accretion of discount on asset retirement obligations |
103 | 107 | 312 | 313 | ||||||||||||
Loss on inventory valuation |
| 29 | | 2,196 | ||||||||||||
27,246 | 15,117 | 72,332 | 162,056 | |||||||||||||
Operating income (loss) |
9,364 | 4,750 | 41,781 | (113,189 | ) | |||||||||||
Other income (expense): |
||||||||||||||||
Interest income |
1,716 | 157 | 3,056 | 361 | ||||||||||||
Interest expense, net |
(2,058 | ) | (4,521 | ) | (7,893 | ) | (12,899 | ) | ||||||||
Loss on redemption of Senior Notes |
(10,948 | ) | | (10,948 | ) | | ||||||||||
Other income (expense) |
1,250 | 400 | 3,116 | 482 | ||||||||||||
(10,040 | ) | (3,964 | ) | (12,669 | ) | (12,056 | ) | |||||||||
Income (loss) before income taxes |
(676 | ) | 786 | 29,112 | (125,245 | ) | ||||||||||
Income tax expense: |
||||||||||||||||
Current |
| | | | ||||||||||||
Deferred |
| (295 | ) | | (295 | ) | ||||||||||
| (295 | ) | | (295 | ) | |||||||||||
Net income (loss) |
$ | (676 | ) | $ | 491 | $ | 29,112 | $ | (125,540 | ) | ||||||
Net income (loss) per share available to common stockholders: |
||||||||||||||||
Basic |
$ | (0.01 | ) | $ | 0.01 | $ | 0.27 | $ | (2.00 | ) | ||||||
Diluted |
$ | (0.01 | ) | $ | 0.01 | $ | 0.26 | $ | (2.00 | ) | ||||||
Weighted average shares outstanding: |
||||||||||||||||
Basic |
115,921 | 82,085 | 109,657 | 62,633 | ||||||||||||
Diluted |
115,921 | 82,756 | 111,562 | 62,633 | ||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
2
Table of Contents
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
(In thousands)
(Unaudited)
Accumulated | ||||||||||||||||||||||||||||
Additional | Other | Total | ||||||||||||||||||||||||||
Common Stock | Paid In | Treasury | Comprehensive | Retained | Stockholders | |||||||||||||||||||||||
Shares | Amounts | Capital | Stock | Income (Loss) | Earnings | Equity | ||||||||||||||||||||||
Balance, December 31, 2009 |
99,593 | $ | 996 | $ | 479,077 | $ | (2,133 | ) | $ | (205 | ) | $ | (213,452 | ) | $ | 264,283 | ||||||||||||
Comprehensive income: |
||||||||||||||||||||||||||||
Net income |
| | | | | 29,112 | 29,112 | |||||||||||||||||||||
Unrealized gains (losses) on investments |
| | | | (1,861 | ) | | (1,861 | ) | |||||||||||||||||||
Tax benefit (provisions) |
| | | | | | | |||||||||||||||||||||
Comprehensive income |
27,251 | |||||||||||||||||||||||||||
Issuance of common stock |
16,100 | 161 | 277,386 | | | | 277,547 | |||||||||||||||||||||
Exercises of employee stock options |
487 | 5 | 2,479 | | | | 2,484 | |||||||||||||||||||||
Vesting of restricted stock |
120 | 1 | (1 | ) | | | | | ||||||||||||||||||||
Stock based compensation |
| | 3,594 | | | | 3,594 | |||||||||||||||||||||
Repurchases of common stock |
| | | (471 | ) | | | (471 | ) | |||||||||||||||||||
Balance, September 30, 2010 |
116,300 | $ | 1,163 | $ | 762,535 | $ | (2,604 | ) | $ | (2,066 | ) | $ | (184,340 | ) | $ | 574,688 | ||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
3
Table of Contents
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Cash flows from operating activities: |
||||||||
Net income (loss) |
$ | 29,112 | $ | (125,540 | ) | |||
Adjustments to reconcile net income (loss) to cash provided by operating activities: |
||||||||
Depletion of oil and natural gas properties |
38,770 | 23,901 | ||||||
Impairment of oil and natural gas properties |
| 114,781 | ||||||
Depreciation and amortization |
856 | 550 | ||||||
Stock based compensation |
1,933 | 1,360 | ||||||
Amortization of deferred loan fees and debt issuance costs |
1,475 | 1,127 | ||||||
Loss on early redemption of Senior Notes |
10,948 | | ||||||
Market value and other adjustments for derivative instruments |
1,262 | 6,037 | ||||||
Accretion of discount on asset retirement obligations |
312 | 313 | ||||||
Deferred income taxes |
| 295 | ||||||
Other noncash items |
| 35 | ||||||
Changes in operating assets and liabilities: |
||||||||
Accounts receivable |
(21,424 | ) | 9,339 | |||||
Other current assets |
(2,218 | ) | (1,123 | ) | ||||
Accounts payable |
20,574 | (6,287 | ) | |||||
Royalties payable |
19,336 | (1,273 | ) | |||||
Participant advances received |
(4,187 | ) | 3,513 | |||||
Other current liabilities |
(2,067 | ) | 4,199 | |||||
Other noncurrent assets and liabilities |
(1,461 | ) | (16 | ) | ||||
Net cash provided by operating activities |
93,221 | 31,211 | ||||||
Cash flows from investing activities: |
||||||||
Additions to oil and natural gas properties |
(279,406 | ) | (51,113 | ) | ||||
Decrease (increase) in restricted cash |
| (9,464 | ) | |||||
Changes to inventory |
(14,805 | ) | | |||||
Decrease (increase) in short term investments |
(111,035 | ) | (8,852 | ) | ||||
Additions to other property and equipment |
(14,142 | ) | (1,334 | ) | ||||
Proceeds from the sale of assets |
12,544 | | ||||||
Decrease (increase) in drilling advances paid |
(1,397 | ) | 171 | |||||
Net cash provided (used) by investing activities |
(408,241 | ) | (70,592 | ) | ||||
Cash flows from financing activities: |
||||||||
Proceeds from issuance of common stock, net of issuance costs |
277,547 | 93,407 | ||||||
Redemption of Series A mandatorily redeemable preferred stock |
(10,101 | ) | | |||||
Proceeds from Senior Notes offering |
300,000 | | ||||||
Redemption of Senior Notes |
(162,789 | ) | | |||||
Repayment of senior credit facility |
| (35,000 | ) | |||||
Deferred loan fees paid and equity costs |
(6,427 | ) | (3,389 | ) | ||||
Proceeds from exercise of employee stock options |
2,484 | 474 | ||||||
Repurchases of common stock |
(471 | ) | (276 | ) | ||||
Net cash provided (used) by financing activities |
400,243 | 55,216 | ||||||
Net increase (decrease) in cash and cash equivalents |
85,223 | 15,835 | ||||||
Cash and cash equivalents, beginning of year |
40,781 | 40,043 | ||||||
Cash and cash equivalents, end of period |
$ | 126,004 | $ | 55,878 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
4
Table of Contents
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Organization and Nature of Operations
Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the
purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership
interests of Brigham Oil & Gas, L.P. (the Partnership). Hereinafter, Brigham Exploration Company
and the Partnership are collectively referred to as Brigham. The Partnership was formed in May
1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic
imaging and other advanced technologies. Brighams exploration and development of oil and natural
gas properties is currently focused in the Rocky Mountains, the Gulf Coast, the Anadarko Basin, and
West Texas.
2. Basis of Presentation
The accompanying unaudited consolidated financial statements include the accounts of Brigham
and its wholly-owned subsidiaries, and its proportionate share of assets, liabilities and income
and expenses of the limited partnership in which Brigham, or any of its subsidiaries, has a
participating interest. All significant intercompany accounts and transactions have been
eliminated.
The accompanying consolidated financial statements are unaudited, and in the opinion of
management, reflect all adjustments that are necessary for a fair presentation of the financial
position and results of operations for the periods presented. All such adjustments are of a normal
and recurring nature. The unaudited consolidated financial statements are presented in accordance
with the requirements of Form 10-Q and do not include all disclosures normally required by
accounting principles generally accepted in the United States of America (U.S. GAAP). The
preparation of financial statements in conformity with U.S. GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from
those estimates. The results of operations for the periods presented are not necessarily
indicative of the results to be expected for the entire year. The unaudited consolidated financial
statements should be read in conjunction with Brighams 2009 Annual Report on Form 10-K filed
pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
3. Commitments and Contingencies
Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary
course of business. While the outcome of lawsuits and claims cannot be predicted with certainty,
management does not expect these matters to have a materially adverse effect on the financial
condition, results of operations or cash flows of Brigham.
As of September 30, 2010, there are no known environmental or other regulatory matters related
to Brighams operations that are reasonably expected to result in a material liability to Brigham.
Compliance with environmental laws and regulations has not had, and is not expected to have, a
material adverse effect on Brighams financial position, results of operations or cash flows.
4. Net Income Available Per Common Share
Basic earnings per share (EPS) is computed by dividing net income (the numerator) by the
weighted average number of common shares outstanding for the period (the denominator). Diluted EPS
is computed by dividing net income by the weighted average number of common shares and potential
common shares outstanding (if dilutive) during each period. Potential common shares include stock
options and restricted stock. The number of potential common shares outstanding relating to stock
options and restricted stock is computed using the treasury stock method.
5
Table of Contents
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The reconciliation of the denominators used to calculate basic EPS and diluted EPS for the
three and nine months ended September 30, 2010 and 2009 are as follows (in thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Weighted average common shares outstanding basic |
115,921 | 82,085 | 109,657 | 62,633 | ||||||||||||
Plus: Potential common shares
Stock options and restricted stock |
| 671 | 1,905 | | ||||||||||||
Weighted average common shares outstanding diluted |
115,921 | 82,756 | 111,562 | 62,633 | ||||||||||||
Stock options excluded from diluted EPS due to the anti-dilutive effect |
5,178 | 2,688 | 1,125 | 4,779 | ||||||||||||
5. Income Taxes
There was no federal income tax expense (benefit) for the nine months ended September
30, 2010 and 2009. There was no state income tax expense (benefit)
for the nine months ended September 30, 2010. There was $0.3 million
in deferred state income tax expense for the nine months ended
September 30, 2009.
Brigham has a net deferred tax asset at September 30, 2010, due to its net operating loss
carryovers and ceiling test writedowns in the fourth quarter of 2008 and the first quarter of 2009.
However, no net deferred tax asset was recorded on Brighams balance sheet at September 30, 2010,
due to a valuation allowance required to be recorded in 2008 and 2009. Deferred tax assets are
reduced by a valuation allowance when, in the opinion of management, it is more likely than not
that some portion or all of the deferred tax assets will not be realized. After testing to
determine if the deferred tax assets would meet the more likely than not criteria, Brigham
determined that the valuation allowance should be $66.6 million at September 30, 2010.
The tax effects from an uncertain tax position can be recognized in the financial statements
only if the position is more likely than not of being sustained if the position were to be
challenged by a taxing authority. Brigham has examined the tax positions taken in its tax returns
and determined that there are no uncertain tax positions. As a result, Brigham has recorded no
uncertain tax liabilities in its consolidated balance sheet.
The tax years that remain subject to examination by Federal and major state tax jurisdictions
are the years ended December 31, 2009, 2008, and 2007. In addition, Brigham is open to examination
for the years 1997 through 2006, resulting from net operating losses generated and available for
carryforward.
6. Derivative Instruments and Hedging Activities
Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of
volatility in price changes on the oil and natural gas commodities it produces and sells, (ii)
reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can
execute at least a portion of its capital spending plans.
Natural Gas and Crude Oil Derivative Contracts
Brigham enters into contracts to hedge against the variability in cash flows associated with
the forecasted sale of future oil and gas production. Brighams cash flow hedges have historically
consisted of swaps, purchased put options, costless collars (purchased put options and written call
options), and three-way collars (a standard collar plus a sold put below the floor price of the
collar). The costless collars and three-way collars are used to establish floor and ceiling prices
on anticipated future oil and natural gas production. There are no net premiums paid or received
when Brigham enters into these costless collar and three-way collar agreements. Brigham has
elected not to designate any of its derivative contracts as cash flow hedges for accounting
purposes under Financial Accounting Standards Board Accounting Standards Codification Topic 815
Derivatives and Hedging (FASB ASC 815). As such, all derivative positions are carried at their
fair value on the consolidated balance sheet and are marked-to-market at the end of each period.
See Note 7, Fair Values, for a discussion of the calculation of the fair values of natural gas
and oil derivative contracts. Any realized and unrealized gains or losses are recorded as gain
(loss) on derivatives, net, as an increase or decrease in revenue on the consolidated statement of
operations.
6
Table of Contents
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The
following tables reflect open commodity derivative contracts at September 30, 2010, the
associated volumes and the corresponding weighted average NYMEX reference price (WTI and Henry
Hub).
Natural | Crude | Purchased | Written | |||||||||||||
Gas | Oil | Put | Call | |||||||||||||
Settlement Period | (MMBTU) | (Barrels) | Nymex | Nymex | ||||||||||||
Natural Gas Costless Collars |
||||||||||||||||
10/01/10 - 12/31/10 |
210,000 | $ | 5.15 | $ | 7.00 | |||||||||||
10/01/10 - 03/31/11 |
240,000 | $ | 6.50 | $ | 8.25 | |||||||||||
10/01/10 - 03/31/11 |
420,000 | $ | 6.40 | $ | 7.80 | |||||||||||
01/01/11 - 12/31/11 |
360,000 | $ | 5.75 | $ | 7.65 | |||||||||||
01/01/11 - 12/31/11 |
480,000 | $ | 5.75 | $ | 7.40 | |||||||||||
04/01/11 - 12/31/11 |
360,000 | $ | 5.00 | $ | 6.55 | |||||||||||
Oil Costless Collars |
||||||||||||||||
10/01/10 - 12/31/10 |
30,000 | $ | 48.70 | $ | 80.00 | |||||||||||
10/01/10 - 12/31/10 |
9,000 | $ | 60.00 | $ | 86.50 | |||||||||||
10/01/10 - 12/31/10 |
15,000 | $ | 60.00 | $ | 88.80 | |||||||||||
10/01/10 - 12/31/10 |
12,000 | $ | 70.00 | $ | 101.75 | |||||||||||
10/01/10 - 12/31/10 |
9,000 | $ | 70.00 | $ | 91.50 | |||||||||||
10/01/10 - 12/31/10 |
6,000 | $ | 60.00 | $ | 100.00 | |||||||||||
10/01/10 - 12/31/10 |
9,000 | $ | 60.00 | $ | 96.00 | |||||||||||
10/01/10 - 11/30/10 |
6,000 | $ | 70.00 | $ | 95.50 | |||||||||||
10/01/10 - 12/31/10 |
24,000 | $ | 57.50 | $ | 82.15 | |||||||||||
10/01/10 - 12/31/10 |
15,000 | $ | 65.00 | $ | 94.25 | |||||||||||
10/01/10 - 12/31/10 |
6,000 | $ | 65.00 | $ | 107.70 | |||||||||||
10/01/10 - 12/31/10 |
15,000 | $ | 75.00 | $ | 101.00 | |||||||||||
10/01/10 - 10/31/10 |
5,000 | $ | 75.00 | $ | 101.00 | |||||||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 97.20 | |||||||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 98.55 | |||||||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 100.40 | |||||||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 100.00 | |||||||||||
10/01/10 - 12/31/10 |
3,000 | $ | 70.00 | $ | 88.50 | |||||||||||
11/01/10 - 02/28/11 |
60,000 | $ | 65.00 | $ | 98.75 | |||||||||||
01/01/11 - 02/28/11 |
10,000 | $ | 70.00 | $ | 92.00 | |||||||||||
01/01/11 - 02/28/11 |
8,000 | $ | 75.00 | $ | 103.50 | |||||||||||
01/01/11 - 03/31/11 |
9,000 | $ | 75.00 | $ | 93.50 | |||||||||||
01/01/11 - 06/30/11 |
18,000 | $ | 65.00 | $ | 97.50 | |||||||||||
01/01/11 - 06/30/11 |
24,000 | $ | 70.00 | $ | 92.50 | |||||||||||
01/01/11 - 07/31/11 |
21,000 | $ | 70.00 | $ | 94.80 | |||||||||||
01/01/11 - 12/31/11 |
84,000 | $ | 65.00 | $ | 88.25 | |||||||||||
01/01/11 - 12/31/11 |
60,000 | $ | 60.00 | $ | 97.25 | |||||||||||
01/01/11 - 12/31/11 |
60,000 | $ | 65.00 | $ | 108.00 | |||||||||||
01/01/11 - 12/31/11 |
48,000 | $ | 70.00 | $ | 106.80 | |||||||||||
01/01/11 - 12/31/11 |
48,000 | $ | 75.00 | $ | 102.60 | |||||||||||
01/01/11 - 12/31/11 |
36,000 | $ | 65.00 | $ | 100.00 | |||||||||||
01/01/11 - 12/31/11 |
36,000 | $ | 75.00 | $ | 104.30 | |||||||||||
01/01/11 - 12/31/11 |
182,500 | $ | 65.00 | $ | 100.00 | |||||||||||
03/01/11 - 04/30/11 |
16,000 | $ | 75.00 | $ | 104.50 | |||||||||||
03/01/11 - 08/31/11 |
46,000 | $ | 65.00 | $ | 96.75 | |||||||||||
03/01/11 - 08/31/11 |
46,000 | $ | 65.00 | $ | 94.80 | |||||||||||
05/01/11 - 12/31/11 |
122,500 | $ | 65.00 | $ | 100.00 | |||||||||||
05/01/11 - 12/31/11 |
122,500 | $ | 65.00 | $ | 106.50 | |||||||||||
07/01/11 - 09/30/11 |
9,000 | $ | 70.00 | $ | 95.00 | |||||||||||
07/01/11 - 12/31/11 |
12,000 | $ | 75.00 | $ | 103.00 | |||||||||||
07/01/11 - 12/31/11 |
12,000 | $ | 75.00 | $ | 95.15 | |||||||||||
09/01/11 - 12/31/11 |
61,000 | $ | 65.00 | $ | 99.00 | |||||||||||
09/01/11 - 12/31/11 |
61,000 | $ | 65.00 | $ | 97.40 | |||||||||||
10/01/11 - 12/31/11 |
6,000 | $ | 70.00 | $ | 96.35 |
7
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Natural | Crude | Purchased | Written | |||||||||||||
Gas | Oil | Put | Call | |||||||||||||
Settlement Period | (MMBTU) | (Barrels) | Nymex | Nymex | ||||||||||||
Oil Costless Collars cont. |
||||||||||||||||
01/01/12 - 06/30/12 |
60,000 | $ | 75.00 | $ | 106.90 | |||||||||||
01/01/12 - 06/30/12 |
182,000 | $ | 65.00 | $ | 100.75 | |||||||||||
01/01/12 - 06/30/12 |
91,000 | $ | 65.00 | $ | 101.00 | |||||||||||
01/01/12 - 06/30/12 |
182,000 | $ | 65.00 | $ | 99.25 | |||||||||||
01/01/12 - 06/30/12 |
91,000 | $ | 65.00 | $ | 102.75 | |||||||||||
01/01/12 - 06/30/12 |
136,500 | $ | 65.00 | $ | 107.25 | |||||||||||
01/01/12 - 07/31/12 |
106,500 | $ | 65.00 | $ | 110.00 | |||||||||||
07/01/12 - 07/31/12 |
62,000 | $ | 65.00 | $ | 102.25 | |||||||||||
07/01/12 - 07/31/12 |
31,000 | $ | 65.00 | $ | 105.25 | |||||||||||
07/01/12 - 09/30/12 |
92,000 | $ | 65.00 | $ | 109.40 | |||||||||||
08/01/12 - 09/30/12 |
61,000 | $ | 65.00 | $ | 110.25 | |||||||||||
08/01/12 - 09/30/12 |
61,000 | $ | 65.00 | $ | 112.00 | |||||||||||
10/01/12 - 10/31/12 |
62,000 | $ | 65.00 | $ | 112.65 |
Natural | Crude | Purchased | ||||||||||
Gas | Oil | Put | ||||||||||
Settlement Period | (MMBTU) | (Barrels) | Nymex | |||||||||
Crude Oil Puts |
||||||||||||
01/01/11 - 06/30/12 |
273,500 | $ | 65.00 | |||||||||
01/01/11 - 06/30/12 |
273,500 | $ | 65.00 |
The following table reflects commodity derivative contracts entered subsequent to September
30, 2010, the associated volumes and the corresponding weighted average NYMEX reference price.
Natural | Crude | Purchased | Written | |||||||||||||
Gas | Oil | Put | Call | |||||||||||||
Settlement Period | (MMBTU) | (Barrels) | Nymex | Nymex | ||||||||||||
Crude Oil Calls |
||||||||||||||||
01/01/11 - 06/30/11 |
90,500 | $ | 95.00 | |||||||||||||
01/01/11 -
06/30/11 |
90,500 | $ | 97.50 | |||||||||||||
Crude Oil Puts |
||||||||||||||||
07/01/11 - 06/30/12 |
91,500 | $ | 65.00 | |||||||||||||
07/01/11 - 06/30/12 |
91,500 | $ | 65.00 |
Additional Disclosures about Derivative Instruments and Hedging Activities
At September 30, 2010 and December 31, 2009, Brigham had derivative financial instruments
under FASB ASC 815 recorded on the consolidated balance sheet as set forth below:
Sept 30, 2010 | Dec 31, 2009 | |||||||||
Estimated | Estimated | |||||||||
Type of Contract | Balance Sheet Location | Fair Value | Fair Value | |||||||
(in thousands) | (in thousands) | |||||||||
Derivatives Not Designated as
Hedging Instruments |
||||||||||
Derivative Assets: |
||||||||||
Natural gas and crude oil contracts |
Other current assets | $ | 3,969 | $ | 1,152 | |||||
Natural gas and crude oil contracts |
Other non-current assets | 1,388 | 186 | |||||||
Total Derivative Assets |
$ | 5,357 | $ | 1,338 | ||||||
Derivative Liabilities: |
||||||||||
Natural gas and crude oil contracts |
Other current liabilities | $ | (2,496 | ) | $ | (2,404 | ) | |||
Natural gas and crude oil contracts |
Other non-current liabilities | (3,391 | ) | (909 | ) | |||||
Total Derivative Liabilities |
$ | (5,887 | ) | $ | (3,313 | ) |
8
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
For the three and nine months ended September 30, 2010 and 2009, the effect on income in the
consolidated statement of operations for derivative financial instruments under FASB ASC 815 was as
follows:
Three Months | Three Months | |||||||||
Ended | Ended | |||||||||
Sept 30, 2010 | Sept 30, 2009 | |||||||||
Statement of Operations | Amount of | Amount of | ||||||||
Type of Contract | Location of Gain (Loss) | Gain (Loss) | Gain (Loss) | |||||||
(in thousands) | (in thousands) | |||||||||
Derivatives Not Designated as Hedging Instruments |
||||||||||
Natural gas contracts |
Gain (loss) on derivatives, net | $ | 1,689 | $ | 374 | |||||
Crude oil contracts |
Gain (loss) on derivatives, net | (8,746 | ) | 740 | ||||||
Total Derivative Gain (loss) |
$ | (7,057 | ) | $ | 1,114 |
Nine Months | Nine Months | |||||||||
Ended | Ended | |||||||||
Sept 30, 2010 | Sept 30, 2009 | |||||||||
Statement of Operations | Amount of | Amount of | ||||||||
Type of Contract | Location of Gain (Loss) | Gain (Loss) | Gain (Loss) | |||||||
(in thousands) | (in thousands) | |||||||||
Derivatives Not Designated as Hedging Instruments |
||||||||||
Natural gas contracts |
Gain (loss) on derivatives, net | $ | 4,349 | $ | 5,770 | |||||
Crude oil contracts |
Gain (loss) on derivatives, net | (3,410 | ) | (2,740 | ) | |||||
Total Derivative Gain (loss) |
$ | 939 | $ | 3,030 |
The use of derivative transactions involves the risk that the counterparties will be unable to
meet the financial terms of such transactions. Brighams derivative contracts are with multiple
counterparties within its credit facility bank group to minimize its exposure to any individual
counterparty and Brigham has netting arrangements with all of its counterparties that provide for
offsetting payables against receivables from separate derivative instruments with that
counterparty.
7. Fair Values
Brigham adopted Financial Accounting Standards Board Accounting Standards Codification Topic
820 Fair Value Measurements and Disclosures (FASB ASC 820) on January 1, 2008, as it relates to
financial assets and liabilities. Brigham adopted FASB ASC 820 on January 1, 2009, as it relates
to nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that
prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy
defined by FASB ASC 820 are as follows:
| Level 1 Unadjusted quoted prices are available in active markets for identical assets or liabilities. |
| Level 2 Pricing inputs, other than quoted prices within Level 1, that are either directly or indirectly observable. |
| Level 3 Pricing inputs that are unobservable requiring the use of valuation methodologies that result in managements best estimate of fair value. |
9
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
As such, effective January 1, 2008, the fair values of Brighams derivative financial
instruments reflect Brighams estimate of the default risk of the parties in accordance with FASB
ASC 820. The fair value of Brighams derivative financial instruments is determined based on
counterparties valuation models that utilize market-corroborated inputs. The fair value of all
derivative contracts is reflected on the balance sheet as detailed in the following schedule (in
thousands). The current asset and liability amounts represent the fair values expected to be
included in the results of operations for the subsequent year.
Fair Value Measurements at September 30, 2010 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active Markets | Observable | Unobservable | ||||||||||||||
September 30, | for Identical Assets | Inputs | Inputs | |||||||||||||
Description | 2010 | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Other current liabilities |
$ | (2,496 | ) | $ | | $ | (2,496 | ) | $ | | ||||||
Other non-current liabilities |
(3,391 | ) | | (3,391 | ) | | ||||||||||
Other current assets |
3,969 | | 3,969 | | ||||||||||||
Other non-current assets |
1,388 | | 1,388 | | ||||||||||||
$ | (530 | ) | $ | | $ | (530 | ) | $ | | |||||||
Fair Value Measurements at December 31, 2009 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active Markets | Observable | Unobservable | ||||||||||||||
December 31, | for Identical Assets | Inputs | Inputs | |||||||||||||
Description | 2009 | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Other current liabilities |
$ | (2,404 | ) | $ | | $ | (2,404 | ) | $ | | ||||||
Other non-current liabilities |
(909 | ) | | (909 | ) | | ||||||||||
Current derivative assets |
1,152 | | 1,152 | | ||||||||||||
Other non-current assets |
186 | | 186 | | ||||||||||||
$ | (1,975 | ) | $ | | $ | (1,975 | ) | $ | | |||||||
Brighams assessment of the significance of a particular input to the fair value measurement
requires judgment and may effect the valuation on the nonfinancial assets and liabilities and their
placement in the fair value hierarchy levels. The fair value of Brighams asset retirement
obligations are determined using discounted cash flow methodologies based on inputs that are not
readily available in public markets. These inputs include salvage value, estimated life, working
interest, a factor for inflation, and a discount factor. The fair value of the asset retirement
obligations is reflected on the balance sheet as detailed below (in thousands).
Fair Value Measurements at September 30, 2010 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active Markets | Observable | Unobservable | ||||||||||||||
September 30, | for Identical Assets | Inputs | Inputs | |||||||||||||
Description | 2010 | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Other non-current liabilities |
(5,834 | ) | | | (5,834 | ) | ||||||||||
$ | (5,834 | ) | $ | | $ | | $ | (5,834 | ) | |||||||
Fair Value Measurements at December 31, 2009 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active Markets | Observable | Unobservable | ||||||||||||||
December 31, | for Identical Assets | Inputs | Inputs | |||||||||||||
Description | 2009 | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Other non-current liabilities |
(6,323 | ) | | | (6,323 | ) | ||||||||||
$ | (6,323 | ) | $ | | $ | | $ | (6,323 | ) | |||||||
See Note 13, Asset Retirement Obligations for a rollforward of the asset retirement
obligation.
10
Table of Contents
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Investments held by Brigham include certificates of deposit, corporate debt, and government
securities. The fair value of the investments is reflected on the balance sheet as detailed below
(in thousands).
Fair Value Measurements at September 30, 2010 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active Markets | Observable | Unobservable | ||||||||||||||
September 30, | for Identical Assets | Inputs | Inputs | |||||||||||||
Description | 2010 | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Investments |
189,267 | 189,267 | | | ||||||||||||
$ | 189,267 | $ | 189,267 | $ | | $ | | |||||||||
Fair Value Measurements at December 31, 2009 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active Markets | Observable | Unobservable | ||||||||||||||
December 31, | for Identical Assets | Inputs | Inputs | |||||||||||||
Description | 2009 | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Investments |
80,093 | 80,093 | | | ||||||||||||
$ | 80,093 | $ | 80,093 | $ | | $ | | |||||||||
The following table summarizes, by major security type, the fair value and any unrealized gain
(loss) of Brighams investments (in thousands). The unrealized gain (loss) is recorded on the
consolidated balance sheet as other comprehensive income (loss), a component of stockholders
equity.
Less Than 12 Months | 12 Months or Greater | Total | ||||||||||||||||||||||
Unrealized | Unrealized | Unrealized | ||||||||||||||||||||||
Fair | Gains | Fair | Gains | Fair | Gains | |||||||||||||||||||
Description of Securities | Value | (Losses) | Value | (Losses) | Value | (Losses) | ||||||||||||||||||
Certificates of deposit |
$ | 1,923 | $ | 1 | $ | | $ | | $ | 1,923 | $ | 1 | ||||||||||||
Corporate bonds and notes |
122,491 | (1,362 | ) | 19,450 | (262 | ) | 141,941 | (1,624 | ) | |||||||||||||||
Government securities |
30,403 | (443 | ) | 15,000 | | 45,403 | (443 | ) | ||||||||||||||||
Total |
$ | 154,817 | $ | (1,804 | ) | $ | 34,450 | $ | (262 | ) | $ | 189,267 | $ | (2,066 | ) | |||||||||
The cost basis of Brighams investments in certificates of deposit, corporate bonds and notes,
and government securities (in thousands) is $1,920, $142,517, and $45,567, respectively.
Brighams other financial instruments include cash and cash equivalents, accounts receivable,
accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value because of their immediate or short-term
maturities. The carrying value of Brighams Senior Credit Facility approximates its fair market
value since it bears interest at floating market interest rates. The following are estimated fair
values and carrying values of our other financial instruments at each of these dates:
September 30, 2010 | December 31, 2009 | |||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Amount | Value | Amount | Value | |||||||||||||
Senior Notes |
$ | 305,594 | $ | 305,895 | $ | 160,000 | $ | 160,000 | ||||||||
Series A Preferred Stock |
$ | | $ | | $ | 10,101 | $ | 10,166 |
The fair value of Brighams Senior Notes (as hereinafter defined) is based upon current market
quotes and is the estimated amount required to purchase the Senior Notes on the open market.
11
Table of Contents
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
8. Oil and Gas Properties
Brigham uses the full cost method of accounting for oil and gas properties. Under this method,
all acquisition, exploration and development costs, including certain payroll, asset retirement
costs, other internal costs, and interest incurred for the purpose of finding oil and natural gas
reserves, are capitalized. Internal costs and capitalized interest are directly attributable to
acquisition, exploration and development activities and do not include costs related to production,
general corporate overhead or similar activities.
Capitalized costs of oil and natural gas properties, net of accumulated amortization, are
limited to the present value (10% per annum discount rate) of estimated future net cash flow from
proved oil and natural gas reserves, based on the oil and natural gas prices in effect on the
balance sheet date including the impact of qualifying cash flow hedging instruments; plus the cost
of properties not being amortized, if any; plus the lower of cost or estimated fair value of
unproved properties included in the costs being amortized, if any; less related income tax effects.
If net capitalized costs of oil and gas properties exceed this ceiling amount, Brigham is subject
to a ceiling test write-down to the extent of such excess. A ceiling test write-down is a non-cash
charge to earnings. If required, it would reduce earnings and impact stockholders equity in the
period of occurrence and result in lower depreciation, depletion and amortization expense in future
periods.
The risk that Brigham will experience a ceiling test write-down increases when oil and gas
prices are depressed or if Brigham has substantial downward revisions in its estimated proved
reserves. Based on oil and gas prices in effect at the end of March 2009, the unamortized cost of
Brighams oil and gas properties exceeded the ceiling limit by $71.9 million, net of tax. As a
result, Brigham was required to record a write-down of the net capitalized costs of its oil and gas
properties in the amount of $114.8 million at March 31, 2009.
Based on the 12-month average oil and gas prices at September 30, 2010 ($4.41 per MMBtu for
Henry Hub natural gas and $77.54 per barrel for West Texas Intermediate oil, adjusted for
differentials), the unamortized cost of Brighams oil and gas properties did not exceed the ceiling
limit. Therefore, Brigham was not required to writedown the net capitalized costs of its oil and
gas properties at September 30, 2010.
During the second quarter 2010, Brigham sold a portion of its proved developed producing West
Texas assets for $14 million with an effective date of January 1, 2010. The proceeds for the sale
were applied to reduce the capitalized costs of oil and gas properties.
9. Common Stock Offerings
In May 2009, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 36,292,117 shares of its common stock at a price of $2.75 per
share and received net proceeds of $93.5 million after underwriting fees and offering expenses.
In October 2009, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 16,000,000 shares of its common stock at a price of $10.50
per share and received net proceeds of $159.9 million after underwriting fees and offering
expenses. In November 2009, the underwriters elected to exercise a portion of the over-allotment
option associated with this equity offering. Brigham issued 837,523 additional shares of common
stock and received net proceeds of $8.4 million after underwriting fees and offering expenses.
In April 2010, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 16,100,000 shares of its common stock at a price of $18.00
per share and received net proceeds of approximately $277.5 million after deducting underwriting
fees and offering expenses.
10. Senior Notes
In April 2006, Brigham issued $125 million of 9 5/8% Senior Notes due in 2014 (the 9 5/8%
Senior Notes). The 9 5/8% Senior Notes were priced at 98.629% of their face value to yield 9 7/8%
and were fully and unconditionally guaranteed by Brigham and its wholly-owned subsidiaries,
Brigham, Inc. and Brigham Oil & Gas, L.P. The guarantees were joint and several. Brigham does not
have any independent assets or operations.
12
Table of Contents
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
In April 2007, Brigham issued an additional $35 million of 9 5/8% Senior Notes as an add-on to
the existing $125 million of 9 5/8% Senior Notes under the indenture dated April 20, 2006. The
add-on 9 5/8% Senior Notes were priced at 99.50% of face value to yield 9.721%. Upon completion of
the add-on, Brigham had outstanding $160 million in 9 5/8% Senior Notes.
On September 27, 2010, Brigham issued $300 million of 8 3/4% Senior Notes due October 2018
(collectively the 8
3/4% Senior Notes). The notes were priced at 100% of their face value and are
fully and unconditionally guaranteed by Brigham and its wholly-owned subsidiaries, Brigham, Inc.
and Brigham Oil & Gas, L.P. Brigham does not have any independent assets or operations.
In
connection with the issuance of the 8 3/4% Senior Notes, Brigham tendered for and purchased
$154.4 million of the 9 5/8% Senior Notes on September 27, 2010. Brigham recorded a $10.9 million
loss upon the redemption of the 9 5/8% Senior Notes. The remaining $5.6 million in 9 5/8% Senior
Notes and outstanding at September 30, 2010, were called for redemption and successfully redeemed
on October 8, 2010. See Note 16, Subsequent Events for details regarding the redemption of the
remaining 9 5/8% Senior Notes.
The indenture governing the 8 3/4% Senior Notes contains customary events of default. Upon the
occurrence of certain events of default, the trustee or the holders
of the 8 3/4% Senior Notes may
declare all outstanding 8 3/4% Senior Notes to be due and payable immediately. The indenture also
contains customary restrictions and covenants which could potentially limit Brighams flexibility
to manage and fund its business. At September 30, 2010, Brigham was in compliance with all
covenants under the indenture.
11. Senior Credit Facility
In May 2009, in conjunction with Brighams regularly scheduled semi-annual redetermination and
Brighams common stock offering, the borrowing base was reset to $110 million. On July 24, 2009,
Brigham amended and restated the Senior Credit Facility to extend the maturity of the agreement
from June 2010 to July 2012. During October 2009, Brigham used a portion of the proceeds from the
October stock offering to repay borrowings under the Senior Credit Facility of $110 million.
Borrowings under the Senior Credit Facility bear interest, at Brighams election, at a base
rate (as the term is defined in the Senior Credit Facility) or Eurodollar rate, plus in each case
an applicable margin that is reset quarterly (2.5% at September 30, 2010). The applicable interest
rate margin varies from 1.5% to 2.5% in the case of borrowings based on the base rate (as the term
is defined in the Senior Credit Facility) and from 2.5% to 3.5% in the case of borrowings based on
the Eurodollar rate, depending on percentage of the available borrowing base utilized. In
addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base
(0.50% at September 30, 2010). Borrowings under the Senior Credit Facility are collateralized by
substantially all of Brighams oil and natural gas properties under first liens.
The Senior Credit Facility contains various covenants, including among other restrictions on
liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on
investments, and restrictions on hedging activity of a speculative nature or with counterparties
having credit ratings below specified levels. The Senior Credit Facility requires Brigham to
maintain a current ratio (as defined) of at least 1 to 1. The Senior Credit Facility also requires
Brigham to maintain an interest coverage ratio for the four most recent quarters as of September
30, 2010 of at least 2.5 to 1. The Senior Credit Facility also requires Brigham to maintain a net
leverage ratio for the quarter ending September 30, 2010 not greater than 4.5 to 1, for the
quarters ending December 31, 2010 and March 31, 2011 not greater than 4.25 to 1, and thereafter not
greater than 4.0 to 1. At September 30, 2010, Brigham was in compliance with all covenants under
the Senior Credit Facility.
12. Preferred Stock
In June 2010, Brigham exercised its option to redeem all of its Series A mandatorily
redeemable preferred stock at 101% of the stated value per share, which was held by DLJ Merchant
Banking Partners III, L.P. and affiliated funds, which are managed by affiliates of Credit Suisse
Securities (USA), LLC.
13
Table of Contents
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
13. Asset Retirement Obligations
Brigham has asset retirement obligations associated with the future plugging and abandonment
of proved properties and related facilities. Prior to the adoption of Financial Accounting
Standards Board Accounting Standards Codification Topic 410 Asset Retirement and Environmental
Obligations (FASB ASC 410), Brigham assumed salvage value approximated plugging and abandonment
costs. As such, estimated salvage value was not excluded from depletion and plugging and
abandonment costs were not accrued for over the life of the oil and gas properties. Under the
provisions of FASB ASC 410, the fair value of a liability for an asset retirement obligation is
recorded in the period in which it is incurred and a corresponding increase in the carrying amount
of the related long-lived asset. The liability is accreted to its present value each period, and
the capitalized cost is depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is recognized. Brigham has no
assets that are legally restricted for purposes of settling asset retirement obligations.
The following table summarizes Brighams asset retirement obligation transactions recorded in
accordance with the provisions of FASB ASC 410 during the nine months ended September 30, 2010 and
2009 (in thousands):
Nine Months Ended | ||||||||
September 30, | ||||||||
2010 | 2009 | |||||||
Beginning asset retirement obligations |
$ | 6,323 | $ | 5,592 | ||||
Liabilities incurred for new wells placed on production |
548 | 303 | ||||||
Liabilities settled |
(141 | ) | (15 | ) | ||||
Accretion of discount on asset retirement obligations |
312 | 313 | ||||||
Revisions to estimates due to sale of oil and gas properties |
(1,208 | ) | | |||||
$ | 5,834 | $ | 6,193 | |||||
14. Stock Based Compensation
Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic
718 Compensation Stock Compensation (FASB ASC 718) to account for stock based compensation.
The cost for all stock based awards is based on the grant date fair value estimated in accordance
with the provisions of FASB ASC 718 and is amortized on a straight-line basis over the requisite
service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ
from the estimates, additional adjustments to compensation expense may be required in future
periods. The maximum contractual life of stock based awards is ten years.
The estimated fair value of the options granted during the nine months ended September 30,
2010 and 2009 was calculated using a Black-Scholes Merton option pricing model (Black-Scholes).
The following table summarizes the weighted average assumptions used in the Black-Scholes model for
options granted during the nine months ended September 30, 2010 and 2009:
2010 | 2009 | |||||||
Risk-free interest rate |
2.47 | % | 2.65 | % | ||||
Expected life (in years) |
5.0 | 5.0 | ||||||
Expected volatility |
81 | % | 78 | % | ||||
Expected dividend yield |
| | ||||||
Weighted average fair value per share of stock compensation |
$ | 12.39 | $ | 3.14 |
The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free
rate of interest for periods within the contractual life of the option is based on a zero-coupon
U.S. government instrument over the contractual term of the equity instrument. Expected volatility
is based on the historical volatility of Brighams stock for an equal period of the expected term.
14
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Prior to the adoption of FASB ASC 718, Brigham presented all tax benefits of deductions
resulting from the exercise of stock options as operating cash flows in the Consolidated Statement
of Cash Flows. FASB ASC 718 requires the cash flow resulting from the tax deductions in excess of
the compensation cost recognized for those options (excess tax benefits) to be classified as
financing cash flows. Brigham did not record any excess tax benefits during the nine months ended
September 30, 2010 and 2009.
The following table summarizes the components of stock based compensation included in general
and administrative expense (in thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Pre-tax stock based compensation expense |
$ | 1,698 | $ | 1,060 | $ | 3,594 | $ | 2,526 | ||||||||
Capitalized stock based compensation |
(804 | ) | (497 | ) | (1,662 | ) | (1,166 | ) | ||||||||
Tax benefit |
(313 | ) | (197 | ) | (676 | ) | (476 | ) | ||||||||
Stock based compensation expense, net |
$ | 581 | $ | 366 | $ | 1,256 | $ | 884 | ||||||||
Stock Based Plan Descriptions and Share Information
Brigham provides an incentive plan for the issuance of stock options, stock appreciation
rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this
plan is to provide incentive and reward key employees whose performance may have a significant
impact on the success of Brigham. It is Brighams policy to use unissued shares of stock when
stock options are exercised. As of September 30, 2010, the number of shares authorized under the
plan was equal to the lesser of 9,966,033 or 12% of the total number of shares of common stock
outstanding. At September 30, 2010, approximately 1,749,815 shares remain available for grant
under the current incentive plan. The Compensation Committee of the Board of Directors determines
the type of awards made to each participant and the terms, conditions and limitations applicable to
each award. Except for one series of stock option grants, options granted subsequent to March 4,
1997 have an exercise price equal to the fair market value of Brighams common stock on the date of
grant, vest over five years and have a maximum contractual life of ten years.
Brigham also maintains a director stock option plan under which stock options are awarded to
non-employee directors. Options granted under this plan have an exercise price equal to the fair
market value of Brigham common stock on the date of grant and vest over five years. Stockholders
have authorized the issuance of 1,000,000 shares to non-employee directors and approximately
566,800 shares remain available for grant under the director stock option plan.
The following table summarizes option activity under the incentive plans for the nine months
ended September 30:
2010 | 2009 | |||||||||||||||
Weighted- | Weighted- | |||||||||||||||
Average | Average | |||||||||||||||
Exercise | Exercise | |||||||||||||||
Shares | Price | Shares | Price | |||||||||||||
Options outstanding at the beginning of the year |
4,170,137 | $ | 5.14 | 3,128,651 | $ | 7.00 | ||||||||||
Granted |
969,500 | $ | 18.88 | 2,686,975 | $ | 4.35 | ||||||||||
Forfeited or cancelled |
(16,800 | ) | $ | 3.92 | (1,549,675 | ) | $ | 8.30 | ||||||||
Exercised |
(487,107 | ) | $ | 5.03 | (99,800 | ) | $ | 4.73 | ||||||||
Options outstanding at the end of the quarter |
4,635,730 | $ | 8.03 | 4,166,151 | $ | 4.86 | ||||||||||
Options exercisable at the end of the quarter |
805,650 | $ | 5.65 | 694,876 | $ | 5.95 | ||||||||||
The weighted-average grant-date fair value of share options granted during the nine months
ended September 30, 2010 and 2009 was $12.39 and $3.14, respectively. The total intrinsic value of
options exercised during the nine months ended September 30, 2010 and 2009 was $1.2 million and
$477,000, respectively.
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
The following table summarizes information about stock options outstanding and exercisable at
September 30, 2010:
Options Outstanding | Options Exercisable | |||||||||||||||||||
Number | Weighted- | Number | Weighted- | |||||||||||||||||
Outstanding at | Average | Weighted- | Exercisable at | Average | Weighted- | |||||||||||||||
September 30, | Remaining | Average | September 30, | Remaining | Average | |||||||||||||||
Exercise Price | 2010 | Contractual Life | Exercise Price | 2010 | Contractual Life | Exercise Price | ||||||||||||||
$2.20 to $3.11 |
1,132,000 | 8.5 years | $ | 2.24 | 180,000 | 8.5 years | $ | 2.25 | ||||||||||||
3.66 to 5.08 |
416,600 | 5.0 years | $ | 5.08 | 53,400 | 5.0 years | $ | 5.08 | ||||||||||||
5.96 to 6.46 |
1,736,780 | 8.1 years | $ | 5.98 | 424,400 | 6.7 years | $ | 6.03 | ||||||||||||
7.22 to 8.84 |
143,850 | 3.2 years | $ | 7.62 | 73,850 | 2.2 years | $ | 7.67 | ||||||||||||
8.93 to 13.86 |
237,000 | 6.7 years | $ | 11.66 | 74,000 | 3.8 years | $ | 10.15 | ||||||||||||
14.43 to 16.85 |
57,000 | 9.7 years | $ | 15.20 | | | $ | | ||||||||||||
18.36 to 19.12 |
912,500 | 9.6 years | $ | 19.11 | | | $ | | ||||||||||||
$2.20 to $19.12 |
4,635,730 | 8.0 years | $ | 8.03 | 805,650 | 6.1 years | $ | 5.65 | ||||||||||||
The aggregate intrinsic value of options outstanding and exercisable at September 30, 2010 was
$50 million and $10.6 million, respectively. The aggregate intrinsic value represents the total
pre-tax value (the difference between Brighams closing stock price on the last trading day of the
quarter and the exercise price, multiplied by the number of in-the-money options) that would have
been received by the option holders had all option holders exercised their options on September 30,
2010. The amount of aggregate intrinsic value will change based on the fair market value of
Brighams stock.
As of September 30, 2010, there was approximately $16.6 million of total unrecognized
compensation expense related to unvested stock based compensation plans. This compensation expense
is expected to be recognized, net of forfeitures, on a straight-line basis over the remaining
vesting period of approximately 4.9 years.
Restricted Stock
During the nine months ended September 30, 2010 and 2009, Brigham issued 105,363 and 247,074,
respectively, restricted shares of common stock as compensation to officers and employees of
Brigham. The restricted shares generally vest over five years or cliff-vest at the end of five
years. As of September 30, 2010, there was approximately $2.4 million of total unrecognized
compensation expense related to unvested restricted stock. This compensation expense is expected
to be recognized, net of forfeitures, over the remaining vesting period of approximately 4.3 years.
Brigham has assumed a 3% weighted average forfeiture rate for restricted stock. If actual
forfeitures differ from the estimates, additional adjustments to compensation expense may be
required in future periods.
The following table reflects the outstanding restricted stock awards and activity related
thereto for the nine months ended September 30:
2010 | 2009 | |||||||||||||||
Weighted- | Weighted- | |||||||||||||||
Average | Average | |||||||||||||||
Shares | Price | Shares | Price | |||||||||||||
Restricted shares outstanding at the beginning of the year |
556,990 | $ | 7.04 | 593,260 | $ | 7.58 | ||||||||||
Shares granted |
105,363 | $ | 14.45 | 247,074 | $ | 2.62 | ||||||||||
Shares forfeited |
(600 | ) | $ | 5.26 | (1,000 | ) | $ | 9.49 | ||||||||
Lapse of restrictions |
(119,760 | ) | $ | 7.31 | (226,008 | ) | $ | 4.27 | ||||||||
Shares outstanding at the end of the quarter |
541,993 | $ | 8.43 | 613,326 | $ | 6.80 | ||||||||||
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
15. Comprehensive Income
For the periods indicated, comprehensive income (loss) consisted of the following (in
thousands):
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
Net income (loss) |
$ | (676 | ) | $ | 491 | $ | 29,112 | $ | (125,540 | ) | ||||||
Unrealized gains (losses) on investments |
220 | | (1,861 | ) | | |||||||||||
Other comprehensive income (loss), net |
$ | (456 | ) | $ | 491 | $ | 27,251 | $ | (125,540 | ) | ||||||
16. Subsequent Events
On October 8, 2010, Brigham redeemed the remaining $5.6 million aggregate principal amount of
the 9 5/8% Senior Notes. The Company used the net proceeds from the previously reported issuance
and sale of $300 million aggregate principal amount of its 8 3/4% Senior Notes to pay the
redemption price of the remaining $5.6 million aggregate principal amount of the 9 5/8% Senior Notes.
17. Related Party Transactions
During the nine months ended September 30, 2010, Brigham incurred costs of approximately $7.2
million in fees for land acquisition services performed by Brigham Land Management, owned by a
brother of Brighams Chairman, President and Chief Executive Officer and its Executive Vice
President Land and Administration. Other participants in Brighams 3-D seismic projects
reimbursed Brigham for a portion of these amounts. At September 30, 2010, Brigham had a liability
recorded in accounts payable of approximately $546,000, related to services performed by this
company.
During the nine months ended September 30, 2010, Brigham incurred costs of $50,728 for design
and development services related to the Brigham North Dakota office and warehouse complex. The
services are being provided by Decker Design & Development PC. The owner is married to a sister of
Brighams Chairman, President and Chief Executive Officer and its Executive Vice President Land
and Administration.
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ITEM 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following updates information as to our financial condition provided in our 2009 Annual
Report on Form 10-K, and analyzes the changes in the results of operations between the three and
nine month periods ended September 30, 2010 and September 30, 2009. For definitions of commonly
used oil and gas terms as used in this Form 10-Q, please refer to the Glossary of Oil and Gas
Terms provided in our 2009 Annual Report on Form 10-K. Statements in the following discussion may
be forward-looking and involve risk and uncertainty. The following discussion should be read in
conjunction with our Consolidated Financial Statements and Notes hereto.
General Overview
We are an independent exploration, development and production company that utilizes advanced
exploration, drilling and completion technologies to systematically explore for, develop and
produce domestic onshore crude oil and natural gas reserves. We focus our activities in provinces
where we believe these technologies, including horizontal drilling, multi-stage isolated fracture
stimulations and 3-D seismic imaging, can be used to effectively maximize our return on invested
capital.
Commencing in late 2005 we began acquiring acreage within the Williston Basin in North Dakota
and Montana. As of September 30, 2010, we have approximately 368,400 net leasehold acres in the
Williston Basin. In late 2007, the majority of our drilling capital expenditures shifted from our
historically active areas in the Onshore Gulf Coast, the Anadarko Basin and West Texas to the
Williston Basin, where we are currently targeting the Bakken, Three Forks and Red River objectives.
Through the third quarter 2010, we had invested in excess of $500 million on drilling, land and
seismic in this region.
Our business strategy is to create value for our stockholders by growing reserves, production
volumes and cash flow through exploration and development drilling in areas where we can use
technology to generate high rates of return on our invested capital. Key elements of our business
strategy include:
| Focus on Core Provinces; |
| Leverage Our Engineering and Operational Expertise; |
| Capitalize on Internally Generated Exploration Successes Through Disciplined Development Activities; and |
| Enhance Returns Through Operational Control. |
Overview of Third Quarter 2010 Financial Results
In the third quarter 2010, the average sales price that we received for crude oil, excluding
realized and unrealized derivative hedging results, was $67.07 per barrel, which represents a 12%
per barrel increase from that in the third quarter 2009. In the third quarter 2010, the average
sales price that we received for natural gas, excluding realized and unrealized derivative hedging
results, was $4.98 per Mcf, which represents a 47% per Mcf increase from that in the third quarter
2009.
Our third quarter 2010 production volumes were 8,509 barrels of equivalent per day, which
represents a 64% increase from last years third quarter production volumes of 5,200 barrels of
equivalent per day and a 10% increase from our second quarter 2010 production volumes of 7,756
barrels of oil equivalent per day. Crude oil represented 75% of our production volumes in the
third quarter 2010 as compared to 50% of our production volumes in the third quarter 2009 and 72%
of our second quarter 2010 production volumes. Both the increase in our production volumes and the
increase in crude oil as a percent of total production volumes were as a result of our increased
level of drilling activity and the success of such activity in the Williston Basin targeting the
Bakken and Three Forks objectives.
Our third quarter 2010 production volumes include approximately 7,395 barrels of crude oil
added to inventory during the quarter. Adjusting our third quarter 2010 production volumes for our
increased level of inventory resulted in sales volumes of 8,427 barrels of equivalent per day in
the third quarter 2010 versus sales volumes of 5,200 barrels of equivalent per day in the third
quarter 2009.
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Table of Contents
Our third quarter 2010 crude oil revenue, including hedge settlements but excluding unrealized
hedging gains and losses, was up $24.4 million, or 181%, compared to the third quarter 2009. Crude
oil revenue increased $19.7 million due to higher sales volumes, $4.2 million due to higher crude
oil prices and $0.5 million due to higher hedge settlements.
Our third quarter 2010 natural gas revenue, including hedge settlements but excluding
unrealized hedging gains and losses, increased $1.0 million from the third quarter 2009. Natural
gas revenue increased $1.9 million due to higher natural gas prices, but was offset by lower sales
volumes, which lowered natural gas revenue by $0.8 million as compared to that in the third quarter 2009.
Third quarter 2010 operating income was $9.4 million versus $4.8 million in the third quarter
last year. The increase in operating income was primarily attributable to increases in crude oil
sales volumes, crude oil and natural gas sales prices and higher hedge settlements. These
increases to operating income were partially offset by higher unrealized hedging losses, lower
natural gas sales volumes and higher operating costs, including higher depletion, production taxes,
lease operating expenses, and general and administrative expenses.
As of September 30, 2010, we had $315.3 million in cash, cash equivalents and short term
investments and $1.02 billion in total assets.
Short term investments totaling $189.3 million in government
sponsored entity and investment grade corporate bonds, notes and
commercial paper are held at UBS Financial Services, Inc. Maturity
dates are staggered to meet anticipated funding needs, and we expect
to hold these investments to maturity. All of our investments are
subject to market risks if sold prior to maturity and the credit
risks of the issuers. Our UBS portfolio at September 30, 2010
also includes approximately $52.4 million in cash equivalents.
Our cash is held in commercial bank accounts. See Note 7 for a discussion
of the fair value of these
investments and instruments.
Overview of Third Quarter 2010 and Recent Fourth Quarter 2010 Operational Results
Williston Basin
At the beginning of the third quarter 2010, we had five operated rigs running in the Williston
Basin and added our sixth operated rig in October 2010. After adding our sixth rig, four of the
operated rigs were primarily drilling wells in our Rough Rider project area in Williams and
McKenzie Counties, North Dakota. The two remaining operated rigs were drilling wells in our Ross
project area in Mountrail County, North Dakota. In September 2010, we added additional
fracture stimulation crew capacity, which should allow us to fracture stimulate and bring on line to
production up to six operated wells per month. The following table summarizes our completions in
the Williston Basin since the end of the second quarter 2010.
Frac | IP | 30 Day | ||||||||||||||||||
Well Name | County | Objective | ~WI% | Stages | (Boe/d) | Average (Boe/d)** | ||||||||||||||
Brad Olson 9-16 #2H |
Williams | Bakken | 56 | %* | 32 | 2,717 | NA | |||||||||||||
Smith Farms 23-14 #1H |
Williams | Bakken | 82 | % | 32 | 2,417 | NA | |||||||||||||
Abelmann 23-14 #1H |
McKenzie | Bakken | 53 | % | 33 | 4,169 | NA | |||||||||||||
Clifford Bakke 26-35 #1H |
Mountrail | Bakken | 43 | % | 38 | 5,061 | NA | |||||||||||||
Boots 13-24 #1H |
Williams | Bakken | 74 | % | 31 | 1,946 | 662 | |||||||||||||
Larsen 3-10 #1H |
Williams | Bakken | 72 | % | 31 | 3,090 | 1,034 | |||||||||||||
Domaskin 30-31 #1H |
Mountrail | Bakken | 65 | % | 38 | 4,675 | NA | |||||||||||||
State 36-1 #2H |
Williams | Three Forks | 30 | %* | 31 | 2,356 | NA | |||||||||||||
Sukut 28-33 #1H |
Williams | Bakken | 42 | %* | 32 | 1,959 | 801 | |||||||||||||
Abe Owan 21-16 #1H |
Williams | Bakken | 57 | % | 37 | 2,213 | 796 | |||||||||||||
Weisz 11-14 #1H |
Williams | Bakken | 52 | % | 37 | 2,278 | 1,014 | |||||||||||||
Wright 4-33 #1H |
Mountrail | Bakken | 88 | % | 38 | 3,660 | 1,322 | |||||||||||||
Michael Owan 26-35 #1H |
Williams | Bakken | 87 | % | 33 | 2,931 | 889 | |||||||||||||
Sedlacek Trust 33-4 #1H |
McKenzie | Bakken | 48 | %* | 30 | 2,695 | 826 | |||||||||||||
Rogney 17-8 #1H |
Roosevelt | Bakken | 100 | % | 30 | 909 | 355 | |||||||||||||
Averages |
2,872 | 855 |
* | Rough Rider drilling participation agreement well where our working interest is anticipated to increase upon payout. | |
** | Excludes any days well was down for remediation. |
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Table of Contents
Results for the Three and Nine Months Ended September 30, 2010
Comparison of the three month and nine month periods ended September 30, 2010 and 2009.
Production volumes
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
Crude oil (MBbls)(1) |
572 | 144 | % | 235 | 1,394 | 144 | % | 572 | ||||||||||||||||
Natural gas (MMcf) |
1,163 | (17 | %) | 1,401 | 3,344 | (29 | %) | 4,703 | ||||||||||||||||
Total (MBoe)(2) |
766 | 64 | % | 468 | 1,952 | 44 | % | 1,356 | ||||||||||||||||
Average daily production (Boe/d)(3) |
8,509 | 64 | % | 5,200 | 7,228 | 44 | % | 5,022 |
(1) | Includes approximately 7,395 barrels of crude oil produced in the Williston Basin during the third quarter 2010 and added to crude oil inventory during the third quarter 2010. Includes approximately 17,496 barrels of crude oil produced in the Williston Basin during the first nine months 2010. Ending inventory as of the first nine months 2009 was not material. | |
(2) | Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. | |
(3) | Average daily production is calculated using 30 days per calendar month. |
Crude oil represented 75% of our third quarter 2010 production volumes and 71% of our first
nine months 2010 production volumes, compared to 50% in the third quarter 2009 and 42% in the first
nine months 2009.
Sales Volumes (Production volumes less the Incremental Change in Inventory)
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
Crude oil (MBbls)(1) |
565 | 140 | % | 235 | 1,377 | 141 | % | 572 | ||||||||||||||||
Natural gas (MMcf) |
1,163 | (17 | %) | 1,401 | 3,344 | (29 | %) | 4,703 | ||||||||||||||||
Total (MBoe)(2) |
758 | 62 | % | 468 | 1,934 | 43 | % | 1,356 | ||||||||||||||||
Average daily production (Boe/d)(3) |
8,427 | 62 | % | 5,200 | 7,163 | 43 | % | 5,022 |
(1) | Excludes approximately 7,395 barrels of crude oil produced in the Williston Basin during the third quarter 2010 and added to crude oil inventory at the end of the third quarter 2010. Excludes approximately 17,496 barrels of crude oil produced in the Williston Basin during the first nine months 2010. Ending inventory as of the first nine months 2009 was not material. | |
(2) | Boe is defined as one barrel equivalent of crude oil, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. | |
(3) | Average daily production is calculated using 30 days per calendar month. |
Crude oil represented 75% of our third quarter 2010 sales volumes and 71% of our first nine
months 2010 sales volumes, compared to 50% in the third quarter 2009 and 42% in the first nine
months 2009.
20
Table of Contents
Revenues, Commodity Prices and Hedging
The following table sets forth our production volumes, the average prices we received before
hedging, the average prices we received including derivative settlement gains (losses) and the
average prices including derivative settlements and unrealized gains (losses).
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
Oil revenue: |
||||||||||||||||||||||||
Oil revenue |
$ | 37,868 | 170 | % | $ | 14,010 | $ | 95,161 | 239 | % | $ | 28,065 | ||||||||||||
Oil derivative settlement gains (losses) |
| (100 | %) | (538 | ) | (228 | ) | NM | 322 | |||||||||||||||
Oil revenue including derivative settlements |
$ | 37,868 | 181 | % | $ | 13,472 | $ | 94,933 | 234 | % | $ | 28,387 | ||||||||||||
Oil derivative unrealized gains (losses) |
(8,746 | ) | NM | 1,278 | (3,183 | ) | 4 | % | (3,063 | ) | ||||||||||||||
Oil revenue including derivative settlements and unrealized gains (losses) |
$ | 29,122 | 97 | % | $ | 14,750 | $ | 91,750 | 262 | % | $ | 25,324 | ||||||||||||
Natural gas revenue: |
||||||||||||||||||||||||
Natural gas revenue |
$ | 5,795 | 22 | % | $ | 4,737 | $ | 17,996 | 2 | % | $ | 17,700 | ||||||||||||
Natural gas derivative settlement gains (losses) |
757 | (5 | %) | 798 | 2,428 | (72 | %) | 8,745 | ||||||||||||||||
Natural gas revenue including derivative settlements |
$ | 6,552 | 18 | % | $ | 5,535 | $ | 20,424 | (23 | %) | $ | 26,445 | ||||||||||||
Natural gas derivative unrealized gains (losses) |
932 | NM | (424 | ) | 1,922 | NM | (2,974 | ) | ||||||||||||||||
Natural gas revenue including derivative settlements and unrealized gains
(losses) |
$ | 7,484 | 46 | % | $ | 5,111 | $ | 22,346 | (5 | %) | $ | 23,471 | ||||||||||||
Oil and natural gas revenue: |
||||||||||||||||||||||||
Oil and natural gas revenue |
$ | 43,663 | 133 | % | $ | 18,747 | $ | 113,157 | 147 | % | $ | 45,765 | ||||||||||||
Oil and natural gas derivative settlement gains (losses) |
757 | 191 | % | 260 | 2,200 | (76 | %) | 9,067 | ||||||||||||||||
Oil and natural gas revenue including derivative settlements |
44,420 | 134 | % | 19,007 | 115,357 | 110 | % | 54,832 | ||||||||||||||||
Oil and natural gas derivative unrealized gains (losses) |
(7,814 | ) | NM | 854 | (1,261 | ) | (79 | %) | (6,037 | ) | ||||||||||||||
Oil and natural gas revenue including derivative settlements and
unrealized gains (losses) |
36,606 | 84 | % | 19,861 | 114,096 | 134 | % | 48,795 | ||||||||||||||||
Other revenue |
4 | (33 | %) | 6 | 17 | (76 | %) | 72 | ||||||||||||||||
Total revenue |
$ | 36,610 | 84 | % | $ | 19,867 | $ | 114,113 | 134 | % | $ | 48,867 |
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Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
Average oil prices: |
||||||||||||||||||||||||
Oil price (per Bbl) |
$ | 67.07 | 12 | % | $ | 59.74 | $ | 69.12 | 41 | % | $ | 49.06 | ||||||||||||
Oil price including derivative settlement gains (losses) (per Bbl) |
67.07 | 17 | % | 57.45 | 68.97 | 39 | % | 49.62 | ||||||||||||||||
Oil price including derivative settlements and unrealized gains (losses)
(per Bbl) |
$ | 51.58 | (18 | %) | $ | 62.90 | $ | 66.64 | 51 | % | $ | 44.27 | ||||||||||||
Average natural gas prices: |
||||||||||||||||||||||||
Natural gas price (per Mcf) |
$ | 4.98 | 47 | % | $ | 3.38 | $ | 5.38 | 43 | % | $ | 3.76 | ||||||||||||
Natural gas price including derivative settlement gains (losses) (per Mcf) |
5.63 | 43 | % | 3.95 | 6.11 | 9 | % | 5.62 | ||||||||||||||||
Natural gas price including derivative settlements and unrealized gains
(losses) (per Mcf) |
$ | 6.44 | 76 | % | $ | 3.65 | $ | 6.68 | 34 | % | $ | 4.99 | ||||||||||||
Average oil equivalent prices: |
||||||||||||||||||||||||
Oil equivalent price (per Boe) |
$ | 57.57 | 44 | % | $ | 40.06 | $ | 58.51 | 73 | % | $ | 33.75 | ||||||||||||
Oil equivalent price including derivative settlement gains (losses) (per Boe) |
58.57 | 44 | % | 40.61 | 59.64 | 47 | % | 40.44 | ||||||||||||||||
Oil equivalent price including derivative settlements and unrealized gains
(losses) (per Boe) |
$ | 48.27 | 14 | % | $ | 42.44 | $ | 58.99 | 64 | % | $ | 35.98 |
For the three | For the nine | |||||||
month periods | month periods | |||||||
ended September 30, | ended September 30, | |||||||
2010 and 2009 | 2010 and 2009 | |||||||
Change in revenue from the sale of oil |
||||||||
Volume variance impact |
$ | 19,720 | $ | 39,477 | ||||
Price variance impact |
4,138 | 27,619 | ||||||
Cash settlement of hedging contracts |
538 | (550 | ) | |||||
Unrealized hedge gain or loss |
(10,024 | ) | (120 | ) | ||||
Total change |
$ | 14,372 | $ | 66,426 | ||||
Change in revenue from the sale of natural gas |
||||||||
Volume variance impact |
$ | (807 | ) | $ | (5,125 | ) | ||
Price variance impact |
1,865 | 5,421 | ||||||
Cash settlement of hedging contracts |
(41 | ) | (6,317 | ) | ||||
Unrealized hedge gain or loss |
1,356 | 4,896 | ||||||
Total change |
$ | 2,373 | $ | (1,125 | ) | |||
Change in revenue from the sale of oil and natural gas |
||||||||
Volume variance impact |
$ | 18,913 | $ | 34,353 | ||||
Price variance impact |
6,003 | 33,039 | ||||||
Cash settlement of hedging contracts |
497 | (6,867 | ) | |||||
Unrealized hedge gain or loss |
(8,668 | ) | 4,776 | |||||
Total change |
$ | 16,745 | $ | 65,301 | ||||
22
Table of Contents
Third quarter 2010 crude oil and natural gas revenues, including derivative cash settlements
and unrealized gains (losses), increased $16.7 million when compared to that in the third quarter
2009. The change in revenues was attributable to the following:
| an increase in crude oil production resulting from our drilling activities in the Williston Basin, which was partially offset by a decrease in our natural gas volumes due to the natural decline of our wells, drove a $18.9 million increase in crude oil and natural gas revenues; |
| a 44% increase in pre-hedge per Boe sales prices resulted in a $6.0 million increase in revenues; |
| a $0.8 million gain from the settlement of derivative contracts in the third quarter 2010 versus a $0.3 million gain from the settlement of derivative contracts in third quarter 2009 increased revenues by $0.5 million; and |
| a $7.8 million unrealized derivative loss in third quarter 2010 versus a $0.9 million unrealized derivative gain in third quarter 2009 decreased revenues by $8.7 million. |
First nine months 2010 crude oil and natural gas revenues, including derivative cash
settlements and unrealized gains (losses), increased $65.3 million when compared to that in the
first nine months 2009. The change in revenues was attributable to the following:
| an increase in crude oil production resulting from our drilling activities in the Williston Basin, which was partially offset by a decrease in our natural gas volumes due to the natural decline of our wells, drove a $34.4 million increase in crude oil and natural gas revenues; |
| a 73% increase in pre-hedge per Boe sales prices resulted in a $33.0 million increase in revenues; |
| a $1.2 million unrealized derivative loss in first nine months 2010 versus a $6.0 million unrealized derivative loss in first nine months 2009 increased revenues by $4.8 million; and |
| a $2.2 million gain from the settlement of derivative contracts in the first nine months 2010 versus a $9.1 million gain from the settlement of derivative contracts in first nine months 2009 decreased revenues by $6.9 million. |
Hedging. We utilize collars, three way costless collars, puts and swaps to (i) reduce the
effect of price volatility on the commodities that we produce and sell, (ii) reduce commodity price
risk and (iii) provide a base level of cash flow in order to assure we can execute at least a
portion of our capital spending plans.
The following table details derivative contracts that settled during the third quarter and
first nine months 2010 and 2009 and includes the type of derivative contract, the volume, the
weighted average NYMEX reference price for those volumes, and the associated gain (loss) upon
settlement.
23
Table of Contents
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
Oil collars |
||||||||||||||||||||||||
Volumes (Bbls) |
322,000 | 250 | % | 92,000 | 678,000 | 381 | % | 141,000 | ||||||||||||||||
Average floor price ($ per Bo) |
$ | 63.92 | 13 | % | $ | 56.39 | $ | 61.88 | 0 | % | $ | 61.67 | ||||||||||||
Average ceiling price ($ per Bo) |
$ | 94.60 | 27 | % | $ | 74.78 | $ | 91.64 | 11 | % | $ | 82.49 | ||||||||||||
Gain (loss) upon settlement ($ in thousands) |
$ | | (100 | %) | $ | (11 | ) | $ | (228 | ) | NM | $ | 1,115 | |||||||||||
Oil swaps |
||||||||||||||||||||||||
Volumes (Bbls) |
| (100 | %) | 30,000 | | (100 | %) | 60,000 | ||||||||||||||||
Average swap price ($ per Bo) |
$ | | (100 | %) | $ | 50.75 | $ | | (100 | %) | $ | 50.75 | ||||||||||||
Gain (loss) upon settlement ($ in thousands) |
$ | | (100 | %) | $ | (527 | ) | $ | | (100 | %) | $ | (793 | ) | ||||||||||
Total oil |
||||||||||||||||||||||||
Gain (loss) upon settlement ($ in thousands) |
$ | | (100 | %) | $ | (538 | ) | $ | (228 | ) | NM | $ | 322 | |||||||||||
Natural gas collars |
||||||||||||||||||||||||
Volumes (MMbtu) |
690,000 | NM | | 1,800,000 | 80 | % | 1,000,000 | |||||||||||||||||
Average floor price ($ per MMbtu) |
$ | 5.51 | NM | $ | | $ | 5.50 | (30 | %) | $ | 7.81 | |||||||||||||
Average ceiling price ($ per MMbtu) |
$ | 7.02 | NM | $ | | $ | 7.02 | (25 | %) | $ | 9.32 | |||||||||||||
Gain (loss) upon settlement ($ in thousands) |
$ | 757 | NM | $ | | $ | 1,855 | (69 | %) | $ | 5,936 | |||||||||||||
Natural gas three ways |
||||||||||||||||||||||||
Volumes (MMbtu) |
| 0 | % | | 390,000 | 77 | % | 220,000 | ||||||||||||||||
Average floor price ($ per MMbtu) |
$ | | 0 | % | $ | | $ | 6.96 | (6 | %) | $ | 7.44 | ||||||||||||
Average ceiling price ($ per MMbtu) |
$ | | 0 | % | $ | | $ | 8.62 | (13 | %) | $ | 9.86 | ||||||||||||
Average price written puts ($ per MMbtu) |
$ | | 0 | % | $ | | $ | 4.58 | 0 | % | $ | 4.58 | ||||||||||||
Gain (loss) upon settlement ($ in thousands) |
$ | | 0 | % | $ | | $ | 573 | (42 | %) | $ | 996 | ||||||||||||
Natural gas swaps |
||||||||||||||||||||||||
Volumes (MMbtu) |
| (100 | %) | 1,126,000 | | (100 | %) | 2,188,000 | ||||||||||||||||
Average swap price ($ per MMbtu) |
$ | | (100 | %) | $ | 4.138 | $ | | (100 | %) | $ | 4.349 | ||||||||||||
Gain (loss) upon settlement ($ in thousands) |
$ | | (100 | %) | $ | 798 | $ | | (100 | %) | $ | 1,813 | ||||||||||||
Total gas |
||||||||||||||||||||||||
Gain (loss) upon settlement ($ in thousands) |
$ | 757 | (5 | %) | $ | 798 | $ | 2,428 | (72 | %) | $ | 8,745 |
Other revenue. Other revenue relates to fees that we charge other parties who use our gas
gathering systems that we own to move their production from the wellhead to first party gas
pipeline systems.
Operating costs and expenses
Production costs. We believe that per unit of production measures are the best way to
evaluate our production costs. We use this information to internally evaluate our performance, as
well as to evaluate our performance relative to our peers.
Unit-of-Production | Amount | |||||||||||||||||||||||
(Per Boe) | (In thousands) | |||||||||||||||||||||||
Three months ended September 30, | Three months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
Production costs: |
||||||||||||||||||||||||
Operating & maintenance |
$ | 4.58 | (18 | %) | $ | 5.59 | $ | 3,470 | 33 | % | $ | 2,616 | ||||||||||||
Expensed workovers |
0.32 | (57 | %) | 0.75 | 244 | (30 | %) | 351 | ||||||||||||||||
Ad valorem taxes |
0.33 | (51 | %) | 0.67 | 250 | (20 | %) | 312 | ||||||||||||||||
Lease operating expenses |
$ | 5.23 | (25 | %) | $ | 7.01 | $ | 3,964 | 21 | % | $ | 3,279 | ||||||||||||
Production taxes |
5.61 | 69 | % | 3.31 | 4,250 | 174 | % | 1,551 | ||||||||||||||||
Production costs |
$ | 10.84 | 5 | % | $ | 10.32 | $ | 8,214 | 70 | % | $ | 4,830 |
24
Table of Contents
Third quarter 2010 per unit of production costs increased $0.52 per Boe, or 5%, when compared
to that in the third quarter last year, mainly due to the following:
| production taxes increased $2.30 per Boe, or 69%, due to higher commodity sales prices and higher crude oil sales volumes in North Dakota, which are subject to a 11.5% tax rate; |
| operating and maintenance expenses decreased $1.01 per Boe, or 18%, primarily due to higher production volumes; and |
| expensed workovers decreased $0.43 per Boe, or 57%, due to a lower number of workovers. |
Unit-of-Production | Amount | |||||||||||||||||||||||
(Per Boe) | (In thousands) | |||||||||||||||||||||||
Nine months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
Production costs: |
||||||||||||||||||||||||
Operating & maintenance |
$ | 4.61 | (25 | %) | $ | 6.13 | $ | 8,915 | 7 | % | $ | 8,313 | ||||||||||||
Expensed workovers |
1.56 | 43 | % | 1.09 | 3,019 | 105 | % | 1,476 | ||||||||||||||||
Ad valorem taxes |
0.39 | (38 | %) | 0.63 | 750 | (13 | %) | 862 | ||||||||||||||||
Lease operating expenses |
$ | 6.56 | (17 | %) | $ | 7.85 | $ | 12,684 | 19 | % | $ | 10,651 | ||||||||||||
Production taxes |
5.51 | 133 | % | 2.36 | 10,658 | 233 | % | 3,196 | ||||||||||||||||
Production costs |
$ | 12.07 | 18 | % | $ | 10.21 | $ | 23,342 | 69 | % | $ | 13,847 |
First nine months 2010 per unit of production costs increased $1.86 per Boe, or 18%, when
compared to the first nine months last year mainly due to the following:
| production taxes increased $3.15 per Boe, or 133%, due to higher commodity sales prices and higher crude oil sales volumes in North Dakota, which are subject to a 11.5% tax rate; |
| expensed workovers increased $0.47 per Boe, or 43%, with the majority of the increase due to several workovers of our conventional Gulf Coast and Anadarko Basin natural gas wells; and |
| operating and maintenance expenses decreased $1.52 per Boe, or 25%, primarily due to higher production volumes. |
General and administrative expenses. We capitalize a portion of our general and
administrative costs. Capitalized costs include the cost of technical employees who work directly
on capital projects and a portion of our associated technical organization costs such as
supervision, telephone and postage.
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
(In thousands, except per unit measurements) | ||||||||||||||||||||||||
General and administrative costs |
$ | 6,255 | 60 | % | $ | 3,901 | $ | 17,503 | 50 | % | $ | 11,660 | ||||||||||||
Capitalized general and administrative costs |
(3,000 | ) | 65 | % | (1,819 | ) | (8,451 | ) | 63 | % | (5,192 | ) | ||||||||||||
General and administrative expenses |
$ | 3,255 | 56 | % | $ | 2,082 | $ | 9,052 | 40 | % | $ | 6,468 | ||||||||||||
General and administrative expense ($ per Boe) |
$ | 4.29 | (4 | %) | $ | 4.45 | $ | 4.68 | (2 | %) | $ | 4.77 |
Our general and administrative costs prior to capitalization for the third quarter and the
first nine months of 2010 increased primarily because of an increase in employee compensation
costs, which is partially associated with increased levels of employee bonuses and bonus accruals
as we re-instated our performance bonus plan in 2010 after suspending the plan in 2009.
25
Table of Contents
Depletion of oil and natural gas properties. Our depletion expense is driven by many factors
including certain costs spent in the exploration for and development of producing reserves,
production levels, and estimates of proved reserve quantities and future developmental costs at the
end of the year.
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
(In thousands, except per unit measurements) | ||||||||||||||||||||||||
Depletion of oil and natural gas properties |
$ | 15,312 | 95 | % | $ | 7,835 | $ | 38,770 | 62 | % | $ | 23,901 | ||||||||||||
Depletion of oil and natural gas properties ($ per Boe) |
$ | 20.20 | 21 | % | $ | 16.74 | $ | 20.05 | 14 | % | $ | 17.63 |
Our depletion expense for the third quarter 2010 was $7.5 million higher than that in the
third quarter 2009. Our higher sales volumes increased depletion expense by $4.9 million and our
higher depletion rate increased depletion expense by $2.6 million.
Our depletion expense for the first nine months 2010 was $14.9 million higher than that in the
first nine months 2009. Our higher sales volumes increased depletion expense by $10.2 million and
our higher depletion rate increased depletion expense by $4.7 million.
Impairment of oil and natural gas properties. We use the full cost method of accounting for
crude oil and natural gas properties. Under this method, all acquisition, exploration and
development costs, including certain payroll, asset retirement costs, other internal costs, and
interest incurred for the purpose of finding crude oil and natural gas reserves, are capitalized.
Internal costs and capitalized interest are directly attributable to acquisition, exploration and
development activities and do not include costs related to production, general corporate overhead
or similar activities.
Capitalized costs of crude oil and natural gas properties, net of accumulated amortization,
are limited to the present value (10% per annum discount rate) of estimated future net cash flow
from proved crude oil and natural gas reserves, based on the crude oil and natural gas prices in
effect on the balance sheet date; plus the cost of properties not being amortized, if any; plus the
lower of cost or estimated fair value of unproved properties included in the costs being amortized,
if any; less related income tax effects. If net capitalized costs of crude oil and natural gas
properties exceed this ceiling amount, we are subject to a ceiling test write-down to the extent of
such excess. A ceiling test write-down is a non-cash charge to earnings and reduces stockholders
equity in the period of occurrence.
The downward trend in natural gas prices experienced in the second half of 2008 continued into
the first quarter of 2009. On December 31, 2008, the Henry Hub natural gas cash price was $5.71
per MMbtu and on March 31, 2009 the natural gas cash price was $3.63 per MMbtu. Lower natural gas
prices during the first quarter 2009 resulted in our capitalized costs, net of accumulated
depreciation, of our crude oil and natural gas properties exceeding the discounted present value of
our estimated proved reserves using a 10% discount rate. As such, we recorded a before tax ceiling
test write-down of $114.8 million during the first nine months of 2009.
Inventory Valuation. Our non-cash loss in the first nine months 2009 was attributable to the
$2.2 million lower of cost or market write-down of oil country tubular goods (OCTG). Market prices
of OCTG experienced a substantial reduction in 2009 associated with lower steel costs, oversupply
of OCTG and reduced levels of drilling activity.
Net interest expense. Interest on our 9 5/8% Senior Notes, and subsequent to the purchase and
redemption of our 9 5/8% Senior Notes, our 8 3/4% Senior Notes, and our Senior Credit Facility represents
the largest portion of our interest expense. Other costs include commitment fees that we pay on the
unused portion of the borrowing base for our Senior Credit Facility. In addition, we typically pay
loan and debt issuance costs when we enter into new lending agreements or amend or retire existing
agreements. When incurred, these costs are recorded as non-current assets and are then amortized
over the life of the loan. We capitalize interest costs on borrowings associated with our major
capital projects prior to their completion. Capitalized interest is added to the cost of the
underlying assets and is amortized over the lives of the assets.
26
Table of Contents
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Interest on Senior Notes |
$ | 3,977 | 3 | % | $ | 3,850 | $ | 11,677 | 1 | % | $ | 11,550 | ||||||||||||
Interest on Senior Credit Facility |
| (100 | %) | 1,063 | | (100 | %) | 3,089 | ||||||||||||||||
Commitment fees |
161 | 519 | % | 26 | 487 | 586 | % | 71 | ||||||||||||||||
Dividend on mandatorily redeemable preferred stock |
| (100 | %) | 153 | 269 | (41 | %) | 453 | ||||||||||||||||
Amortization of deferred loan and debt issuance cost |
435 | (8 | %) | 475 | 1,398 | 32 | % | 1,056 | ||||||||||||||||
Other general interest expense |
| (100 | %) | 14 | 101 | 237 | % | 30 | ||||||||||||||||
Capitalized interest expense |
(2,515 | ) | 137 | % | (1,060 | ) | (6,039 | ) | 80 | % | (3,350 | ) | ||||||||||||
Net interest expense |
$ | 2,058 | (54 | %) | $ | 4,521 | $ | 7,893 | (39 | %) | $ | 12,899 | ||||||||||||
Weighted average debt outstanding |
$ | 166,331 | (41 | %) | $ | 280,101 | $ | 168,091 | (44 | %) | $ | 298,819 | ||||||||||||
Average interest rate on outstanding indebtedness (a) |
9.9 | % | 7.2 | % | 10.0 | % | 6.8 | % |
a) | Calculated as the sum of the interest expense on our outstanding indebtedness, commitment fees that we pay on our unused borrowing capacity and the dividend on our mandatorily redeemable preferred stock divided by our weighted average debt and preferred stock outstanding for the period. |
Third quarter 2010 interest expense was $2.5 million lower than the corresponding period last
year due to a $1.0 million decrease in interest expense largely associated with lower levels of
debt outstanding on our Senior Credit Facility subsequent to its repayment in October 2009 in
conjunction with our common stock offering. Interest expense was also lower as our capitalized
interest expense increased $1.5 million associated with our higher level of activity in the
Williston Basin.
First nine months 2010 interest expense was $5.0 million lower than the corresponding period
last year primarily due to a $3.1 million decrease in interest expense associated with lower levels
of debt outstanding on our Senior Credit Facility subsequent to its repayment in October 2009 in
conjunction with our common stock offering. Interest expense was also lower as our capitalized
interest expense increased $2.7 million associated with our higher level of activity in the
Williston Basin. These decreases to interest expense were partially offset by a $0.3 million
increase in deferred loan and debt issuance costs associated with the July 2009 amendment of our
Senior Credit Facility and a $0.4 million increase in commitment fees as our Senior Credit Facility
was undrawn for the first nine months of 2010.
Other income (expense).
Other income (expense) included:
Three months ended September 30, | Nine months ended September 30, | |||||||||||||||||||||||
2010 | % Change | 2009 | 2010 | % Change | 2009 | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Other income (expense): |
||||||||||||||||||||||||
Total other income |
$ | 1,250 | 213 | % | $ | 400 | $ | 3,116 | 546 | % | $ | 482 | ||||||||||||
Other income increased as a result of higher levels of drilling equipment rental income in the
Williston Basin. Third quarter 2009 other income (expense) includes a $0.3 million gain from the
sale of pipe inventory.
Income taxes. We recorded no federal or state income tax expense in the third
quarter of this year, compared to no federal income tax expense and $0.3 million in
deferred state income tax expense in the third quarter last year. We recorded no federal
or state income tax expense for the first nine months 2010, compared to no federal income
tax expense and $0.3 million in deferred state income tax expense for the first nine months 2009.
For the first nine months 2010, our effective tax rate on book net income was 0%. This was lower
than the statutory rate of 35% primarily due to the reversal of a portion of the valuation
allowance on our deferred tax asset.
27
Table of Contents
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we operate the
majority of our wells and we have no material long-term capital expenditure commitments.
Consequently, we have a significant degree of flexibility to adjust the level of our capital
expenditures as circumstances warrant. Our capital expenditure program includes the following:
| cost of acquiring and maintaining our lease acreage position and our seismic resources; |
| cost of drilling and completing new crude oil and natural gas wells; |
| cost of installing new production infrastructure; |
| cost of maintaining, repairing and enhancing existing crude oil and natural gas wells; |
| cost related to plugging and abandoning unproductive or uneconomic wells; and |
| indirect costs related to our exploration activities, including payroll and other expenses attributable to our exploration professional staff. |
The capital that funds our drilling activities is allocated to individual prospects based on
the value potential of a prospect, as measured by a risked net present value analysis. We start
each year with a budget and re-evaluate this budget monthly. The primary factors that impact this
value creation measure include forecasted commodity prices, drilling and completion costs, and a
prospects risked reserve size and risked initial producing rate. Other factors that are also
monitored throughout the year that influence the amount and timing of our planned expenditures
include the level of production from our existing crude oil and natural gas properties, the
availability of drilling and completion services, and the success and resulting production of our
newly drilled wells. The outcome of our monthly analysis results in a reprioritization of our
exploration and development drilling schedule to ensure that we are optimizing our capital
expenditure plan.
The final determination with respect to our 2010 budgeted expenditures will depend on a number
of factors, including:
| commodity prices; |
| production from our existing producing wells; |
| the results of our current exploration and development drilling efforts; |
| economic conditions at the time of drilling; |
| industry conditions at the time of drilling, including the availability of drilling and completion equipment; |
| our liquidity and the availability of external sources of financing; and |
| the availability of more economically attractive prospects. |
There can be no assurance that the budgeted wells will, if drilled, encounter commercial
quantities of crude oil or natural gas.
In April 2010, as a result of our common stock offering and improved operational results, we
increased our activity level in the Williston Basin and concurrently increased our exploration and
development capital budget to $293.9 million, which included $229.1 million in drilling, $27.0
million in land and seismic and $37.8 million in field level infrastructure expenditures.
Largely as a result of acreage acquisitions announced in the third quarter 2010, we announced
a further increase in our exploration and development capital budget in August 2010 to
approximately $404.0 million. We further increased our
exploration and development capital budget in November 2010 to
$466.1 million, largely as a result of drilling seven additional net
wells in the Williston Basin.
Factors that could cause us to further increase our level of activity and capital budget in
2010 include a further reduction in service and material costs, the formation of joint ventures
with other exploration and production companies, the divestiture of non-strategic assets, and a
further improvement in commodity prices or well performance that exceeds our risked forecasts, all
of which would positively impact our operating cash flow.
Factors that would cause us to reduce our capital budget in 2010 include, but are not limited
to, increases in service and materials costs, reductions in commodity prices or underperformance of
wells relative to our risked forecasts, all of which would negatively impact our operating cash
flow.
28
Table of Contents
The table below summarizes our 2010 exploration and development capital budget revised in
November 2010, the amount spent through September 30, 2010 and the amount of our 2010 exploration and
development capital budget that remains to be spent.
Amount | ||||||||||||
November | Spent Through | |||||||||||
2010 | September 30, | Amount | ||||||||||
Budget | 2010 | Remaining (a) | ||||||||||
(In millions) | ||||||||||||
Drilling |
$ | 315.8 | $ | 198.0 | $ | 117.8 | ||||||
Field level infrastructure (b) |
36.0 | 16.3 | 19.7 | |||||||||
Land and seismic |
51.2 | 40.1 | 11.1 | |||||||||
Acreage acquisitions |
63.1 | 63.1 | | |||||||||
Exploration and development capital budget |
$ | 466.1 | $ | 317.5 | $ | 148.6 | ||||||
(a) | Calculated based on the November 2010 exploration and development capital budget less amounts spent through September 30, 2010. | |
(b) | Oil and natural gas pipeline capital expenditures are recorded on our balance sheet in oil and natural gas properties. Salt water disposal and fresh water pipelines are recorded on our balance sheet in other property and equipment. |
29
Table of Contents
Liquidity and Capital Resources
Sources of Capital
For the remainder of 2010, we intend to fund our capital expenditure program and contractual
commitments with cash, cash equivalents and short term investments on hand, cash flows from
operations, reimbursements of prior land and seismic costs by third parties who participate in our
projects, the sale of interests in projects and properties or alternative financing sources.
Senior Notes
As of September 30, 2010, we had $300 million of 8 3/4% Senior Notes outstanding and $5.6
million of 9 5/8% Senior Notes outstanding. On September 27, 2010, we issued $300 million in 8 3/4
Senior Notes that have an 8.75% interest rate and mature in October 2018. In connection with the
issuance of the 8 3/4% Senior Notes, we tendered for and purchased $154.4 million of our 9 5/8%
Senior Notes on September 27, 2010. The remaining $5.6 million in 9 5/8% Senior Notes outstanding
at the end of the third quarter 2010 were called for redemption and successfully redeemed on
October 8, 2010.
Our 8 3/4 % Senior Notes are fully and unconditionally guaranteed by us, and our wholly-owned
subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. Beginning April 2011, we will pay 8.75%
interest on the $300 million outstanding. Future interest payments are due semi-annually in
arrears in October and April of each year beginning April 2011.
The 8 3/4 Senior Notes are our unsecured senior obligations, and:
| rank equally in right of payment with all our existing and future senior indebtedness; |
| rank senior to all of our future subordinated indebtedness; and |
| are effectively junior in right of payment to all of our and the Guarantors existing and future secured indebtedness, including debt of our Senior Credit Facility. |
The Indenture governing the 8 3/4% Senior Notes contains customary events of default. Upon
the occurrence of certain events of default, the trustee or the holders of the 8 3/4% Senior Notes
may declare all outstanding 8 3/4% Senior Notes to be due and payable immediately.
Additionally, the Indenture governing the 8 3/4% Senior Notes contains customary restrictions
and covenants which could potentially limit our flexibility to manage and fund our business. We
were in compliance with all covenants associated with the 8 3/4% Senior Notes as of September 30,
2010.
Senior Credit Facility
Our Senior Credit Facility provides for revolving credit borrowings up to $200 million. Our
current borrowing base is $110 million. As of September 30, 2010 and as of the date of the filing
of this report, we had no amounts outstanding.
Covenants under our 8 3/4% Senior Notes preclude us from incurring additional debt under the
Senior Credit Facility to the extent our total debt under the Senior Credit Facility exceeds the
greater of (1) $200 million and (2) the sum of $100 million plus 30% of a calculated proved PV10
value based on SEC prices used in our year-end reserve report, as defined in our Indenture, which
is referred to as Adjusted Consolidated Net Tangible Assets.
Since the borrowing base for our Senior Credit Facility is redetermined at least
semi-annually, the amount of borrowing capacity available to us under our Senior Credit Facility
could fluctuate. In the event that the borrowing base is adjusted below the amount that we have
borrowed, our access to further borrowings will be reduced, and we may not have the resources
necessary to pay off the borrowing base deficiency and carry out our planned spending for
exploration and development activities.
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Borrowings under our Senior Credit Facility bear interest at a base rate or a Eurodollar rate,
at our election, plus in each case an applicable margin. These margins are reset quarterly and are
subject to increase if the total amount borrowed under our Senior Credit Facility reaches certain
percentages of the available borrowing base, as shown below:
Percent of | Eurodollar | |||||||
Borrowing Base | Rate | Base Rate | ||||||
Utilized | Advances | Advances(1) | ||||||
< 25% |
2.50% | 1.50% | ||||||
25% and < 50% |
2.75% | 1.75% | ||||||
50% and < 75% |
3.00% | 2.00% | ||||||
75% and < 90% |
3.25% | 2.25% | ||||||
≥ 90% |
3.50% | 2.50% |
(1) | Base rate is defined as for any day a fluctuating rate per annum equal to the highest of the following, in each case, to the extent determinable by the Administrative Agent: (a) the Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect to Interest Periods of one month determined as of approximately 11:00 a.m. (London time) on such day plus 1.50% and (c) the rate of interest in effect for such day as publicly announced from time to time by Bank of America as its prime rate. The prime rate is a rate set by Bank of America based upon various factors including Bank of Americas costs and desired return, general economic conditions and other factors, and is used as a reference point for pricing some loans, which may be priced at, above, or below such announced rate. Any change in such rate announced by Bank of America shall take effect at the opening of business on the day specified in the public announcement of such change. |
We are also required to pay a quarterly commitment fee on the average daily unused portion of the
borrowing base. The commitment fees we pay are reset quarterly and are subject to change as the
percentage of the available borrowing base that we utilize changes. The margins and commitment
fees that we pay are 0.5% at September 30, 2010.
Our
Senior Credit Facility also contains customary restrictions and covenants. Should we be
unable to comply with these or other covenants, our senior lenders may be unwilling to waive
compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our
Senior Credit Facility, our current ratio must be at least 1.0 to 1, our interest coverage ratio
for the four most recent quarters as of September 30, 2010 must
be at least 2.5 to 1 and our net
leverage ratio for the quarters ending through September 30,
2010 must not be greater than 4.5 to 1, for
the quarters ending December 31, 2010 through March 31,
2011 must not be greater than 4.25 to 1, and
thereafter must not be greater than 4.0 to 1. As of September 30, 2010, we were in compliance with all
covenant requirements in connection with our Senior Credit Facility.
Off Balance Sheet Arrangements
We currently have operating leases, which are considered off balance sheet arrangements. We
do not currently have any other off balance sheet arrangements or other such unrecorded
obligations, and we have not guaranteed the debt of any other party.
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Analysis of Changes in Cash and Cash Equivalents
The table below summarizes our sources and uses of cash during the periods indicated.
Nine months ended September 30, | ||||||||||||
2010 | %Change | 2009 | ||||||||||
(In thousands) | ||||||||||||
Net income (loss) |
$ | 29,112 | NM | $ | (125,540 | ) | ||||||
Non-cash items |
55,556 | (63 | %) | 148,399 | ||||||||
Changes in working capital and other items |
8,553 | 2 | % | 8,352 | ||||||||
Cash flows provided by operating activities |
$ | 93,221 | 199 | % | $ | 31,211 | ||||||
Cash flows used by investing activities |
(408,241 | ) | 478 | % | (70,592 | ) | ||||||
Cash flows provided by financing activities |
400,243 | 625 | % | 55,216 | ||||||||
Net increase in cash and cash equivalents |
$ | 85,223 | 438 | % | $ | 15,835 | ||||||
Analysis of net cash provided by operating activities
Net cash provided by operating activities is a function of the amount of crude oil and natural
gas that we produce, the prices that we receive from the sale of crude oil and natural gas, which
are inherently volatile and unpredictable, gains or losses related to the settlement of our
derivative contracts, operating costs and our cost of capital. Our asset base, as with other
extractive industries, is a depleting one in which each barrel of crude oil or Mcf of natural gas
produced must be replaced or our ability to generate cash flow, and thus sustain our exploration
and development activities, will diminish.
For the first nine months 2010, cash flows provided by operating activities increased by 199%
from the same period last year. The increase in operating cash flow is primarily attributable to
the increase in commodity prices, higher levels of crude oil sales volumes and cash provided by
working capital. These increases to operating cash flow were partially offset by lower natural gas
sales volumes and by higher production taxes, lease operating expense and general and
administrative expense.
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Analysis of changes in cash flows used in investing activities
Nine months ended September 30, | ||||||||||||
2010 | %Change | 2009 | ||||||||||
(In thousands) | ||||||||||||
Capital expenditures for oil and natural gas activities: |
||||||||||||
Drilling |
$ | 197,970 | 426 | % | $ | 37,610 | ||||||
Field level infrastructure (a) |
16,259 | NM | | |||||||||
Land and
seismic and acreage acquisitions |
103,172 | NM | (3,212 | ) | ||||||||
Capitalized cost |
14,489 | 70 | % | 8,543 | ||||||||
Capitalized asset retirement obligation |
547 | 81 | % | 302 | ||||||||
Total |
$ | 332,437 | 669 | % | $ | 43,243 | ||||||
Reconciling Items: |
||||||||||||
Asset sale proceeds including ARO liability reduction |
$ | (13,706 | ) | NM | $ | | ||||||
Change in accrued drilling costs |
$ | (41,605 | ) | NM | $ | 9,338 | ||||||
Change in drilling advances paid |
1,397 | NM | (171 | ) | ||||||||
Change in restricted cash |
| (100 | %) | 9,464 | ||||||||
Change in short term investments |
111,035 | 1,154 | % | 8,852 | ||||||||
Change in other property and equipment (b) |
4,500 | NM | | |||||||||
Change in inventory |
14,805 | NM | | |||||||||
Other |
(622 | ) | 364 | % | (134 | ) | ||||||
Total Reconciling Items |
75,804 | 177 | % | 27,349 | ||||||||
Net cash used in investing activities |
$ | 408,241 | 478 | % | $ | 70,592 |
(a) | Oil and natural gas pipeline capital expenditures are recorded on our balance sheet in oil and natural gas properties. Salt water disposal and fresh water pipelines are recorded on our balance sheet in other property and equipment. | |
(b) | Excludes approximately $9.3 million in salt water disposal and fresh water pipelines included in field level infrastructure. |
Net cash used by investing activities in the first nine months 2010 increased by $337.6
million, or 478%, over the same period in 2009. The following were the main reasons for the
change:
| drilling expenditures increased by $160.4 million; |
| field level infrastructure increased by $16.3 million; |
| land and seismic and acreage acquisition expenditures increased by $106.4 million; |
| capitalized costs increased by $5.9 million; |
| the sale of our West Texas assets reduced cash used in investing activities by $13.7 million; |
| the change in accrued drilling costs decreased cash used in investing activities by $50.9 million; |
| the change in short term investments increased cash used in investing activities by $102.2 million; |
| the change in other property and equipment increased cash used in investing activities by $4.5 million; and |
| the change in inventory increased cash used in investing activities by $14.8 million. |
Analysis of changes in cash flows from financing activities
Net cash provided by financing activities in the first nine months of 2010 was 625% greater
than the first nine months of 2009. During the first nine months 2010, we received net proceeds of
$277.5 million from our April 2010 common stock offering and $146.5 million from our September 2010
8 3/4% Senior Notes offering. During the first nine months 2009, we received net proceeds of $93.5
million related to our May 2009 common stock offering.
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Common Stock Transactions
The following is a list of common stock transactions that occurred in the nine months ended
September 30, 2010 and 2009.
Shares Issued | Net Proceeds | |||||||
(In thousands, except share data) | ||||||||
2010 common stock transactions: |
||||||||
Common stock offering (April) |
16,100,000 | $ | 277,547 | |||||
Exercise of employee stock options |
487,107 | $ | 2,484 | |||||
2009 common stock transactions: |
||||||||
Common stock offering (May) |
36,292,117 | $ | 93,523 | |||||
Exercise of employee stock options |
100,300 | $ | 474 |
Other Matters
Derivative Instruments
Our results of operations and operating cash flow are impacted by changes in market prices for
crude oil and natural gas. We believe the use of derivative instruments, although not free of
risk, allows us to reduce our exposure to crude oil and natural gas sales price fluctuations and
thereby achieve a more predictable cash flow. While the use of derivative instruments limits the
downside risk of adverse price movements, their use may also limit future revenues from favorable
price movements. Moreover, our derivative contracts generally do not apply to all of our
production and thus provide only partial price protection against declines in commodity prices. We
expect that the amount of our derivative contracts will vary from time to time.
Effects of Inflation and Changes in Prices
Our results of operations and cash flows are affected by changing crude oil and natural gas
prices. If the price of crude oil and natural gas increases (decreases), there could be a
corresponding increase (decrease) in revenues as well as the operating costs that we are required
to bear for operations.
Environmental and Other Regulatory Matters
Our business is subject to certain federal, state and local laws and regulations relating to
the exploration for and the development, production and marketing of crude oil and natural gas, as
well as environmental and safety matters. Many of these laws and regulations have become more
stringent in recent years, often imposing greater liability on a larger number of potentially
responsible parties. Although we believe that we are in substantial compliance with all applicable
laws and regulations, the requirements imposed by laws and regulations are frequently changed and
subject to interpretation, and we cannot predict the ultimate cost of compliance with these
requirements or their effect on our operations. Any suspensions, terminations or inability to meet
applicable bonding requirements could materially adversely affect our financial condition and
operations. Although significant expenditures may be required to comply with governmental laws and
regulations applicable to us, compliance has not had a material adverse effect on our earnings or
competitive position. Future regulations may add to the cost of, or significantly limit, drilling
activity.
Forward-looking Information
We or our representatives may make forward-looking statements, oral or written, including
statements in this report, press releases and filings with the SEC, regarding estimated future net
revenues from crude oil and natural gas reserves and the present value thereof, planned capital
expenditures (including the amount and nature thereof), increases in crude oil and natural gas
production, the number of wells we anticipate drilling during 2010 and our financial position,
business strategy and other plans and objectives for future operations. Although we believe that
the expectations reflected in these forward-looking statements are reasonable, there can be no
assurance that the actual results or developments anticipated by us will be realized or, even if
substantially realized, that they will have the expected effects on our business or operations.
Among the factors that could cause actual results to differ materially from our expectations are
general economic conditions, inherent uncertainties in interpreting engineering data, operating
hazards, delays or cancellations of drilling operations for a variety of reasons, competition,
fluctuations in crude oil and natural gas prices, availability of sufficient capital resources to
us or our project participants, government regulations and other factors set forth among the risk
factors noted in our Form 10-K report for the year ended
December 31, 2009 and our Form 10-Q reports for the quarters
ended March 31, 2010 and June 30, 2010, including, but not
limited to, the Risk Factors identified in Item 1A. of such reports. All subsequent oral and
written forward-looking statements attributable to us or persons acting on our behalf are expressly
qualified in their entirety by these factors. We assume no obligation to update any of these
statements.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Management Opinion Concerning Derivative Instruments
We use derivative instruments to manage exposure to commodity prices and interest rate risks.
Our objectives for holding derivatives are to achieve a consistent level of cash flow to support a
portion of our planned capital spending. Our use of derivative instruments for hedging activities
could materially affect our results of operations in particular quarterly or annual periods since
such instruments can limit our ability to benefit from favorable price movements. We do not enter
into derivative instruments for trading purposes. See Item 1. Condensed Consolidated Financial
Statements Notes 6 and 7 for more details.
Derivative Instruments and Hedging Activities
Our primary commodity market risk exposure is to changes in the prices that we receive for our
crude oil and natural gas production. The market prices for crude oil and natural gas have been
highly volatile and are likely to continue to be highly volatile in the future. As such, we employ
established policies and procedures to manage our exposure to fluctuations in the sales prices we
receive for our crude oil and natural gas production via derivative instruments.
While the use of derivative instruments limits the downside risk of adverse price movements,
their use may also limit future revenues from favorable price movements. Moreover, our derivative
contracts generally do not apply to all of our production and thus provide only partial price
protection against declines in commodity prices. We expect that the amount of our derivative
contracts will vary from time to time.
During
the first nine months of 2010 and 2009, we were party to crude oil costless collars,
crude oil swaps, crude oil puts, natural gas costless collars, natural gas three-way costless
collars and natural gas swaps.
We use costless collars to establish floor (purchased put option) and ceiling prices (written
call option) on our anticipated future crude oil and natural gas production. We do not pay or
receive net premiums when we enter into these option arrangements. These contracts are settled
monthly. When the settlement price for a period is above the ceiling price (written call option),
we pay our counterparty. When the settlement price for a period is below the floor price
(purchased put option), our counterparty is required to pay us.
A three-way costless collar consists of a costless collar (purchased put option and written
call option) plus a put (written put) sold by us with a price below the floor price (purchased put
option) of the costless collar. We receive no net premiums when we enter into these option
arrangements. These contracts are settled monthly. The written put requires us to make a payment
to our counterparty if the settlement price for a period is below the written put price. Combining
the costless collar (purchased put option and written call option) with the written put results in
us being entitled to a net payment equal to the difference between the floor price (purchased put
option) of the costless collar and the written put price if the settlement price is equal to or
less than the written put price. If the settlement price is greater than the written put price,
the result is the same as it would have been with a costless collar. This strategy enables us to
increase the floor and the ceiling price of the collar beyond the range of a traditional costless
collar while offsetting the associated cost with the sale of the written put.
We also use put options to establish floor prices (purchased put option) on our anticipated
future crude oil production. We pay an initial premium when we enter into these option
arrangements. These contracts are settled monthly. When the settlement price for a period is
below the floor price (purchased put option), our counterparty is required to pay us.
Natural gas derivative transactions are generally settled based upon the average reported
settlement prices on the NYMEX for the last three trading days of a particular contract month.
Crude oil derivative transactions are generally settled based on the average reported settlement
prices on the NYMEX for each trading day of a particular calendar month.
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The following tables reflect our open crude oil and natural gas contracts as of September 30,
2010, the associated volumes and the corresponding weighted average NYMEX floor and cap price.
Crude | Purchased | Written | ||||||||||
Oil | Put | Call | ||||||||||
Settlement Period | (Barrels) | (Nymex) | (Nymex) | |||||||||
Crude Oil Costless Collars |
||||||||||||
10/01/10 - 12/31/10 |
30,000 | $ | 48.70 | $ | 80.00 | |||||||
10/01/10 - 12/31/10 |
24,000 | $ | 57.50 | $ | 82.15 | |||||||
10/01/10 - 12/31/10 |
9,000 | $ | 60.00 | $ | 86.50 | |||||||
01/01/11 - 12/31/11 |
84,000 | $ | 65.00 | $ | 88.25 | |||||||
10/01/10 - 12/31/10 |
3,000 | $ | 70.00 | $ | 88.50 | |||||||
10/01/10 - 12/31/10 |
15,000 | $ | 60.00 | $ | 88.80 | |||||||
01/01/11 - 12/31/11 |
60,000 | $ | 60.00 | $ | 97.25 | |||||||
01/01/11 - 12/31/11 |
60,000 | $ | 65.00 | $ | 108.00 | |||||||
01/01/11 - 06/30/11 |
18,000 | $ | 65.00 | $ | 97.50 | |||||||
10/01/10 - 12/31/10 |
9,000 | $ | 60.00 | $ | 96.00 | |||||||
10/01/10 - 12/31/10 |
6,000 | $ | 60.00 | $ | 100.00 | |||||||
10/01/10 - 12/31/10 |
6,000 | $ | 65.00 | $ | 107.70 | |||||||
01/01/11 - 12/31/11 |
48,000 | $ | 70.00 | $ | 106.80 | |||||||
10/01/10 - 12/31/10 |
12,000 | $ | 70.00 | $ | 101.75 | |||||||
01/01/11 - 12/31/11 |
48,000 | $ | 75.00 | $ | 102.60 | |||||||
07/01/11 - 12/31/11 |
12,000 | $ | 75.00 | $ | 103.00 | |||||||
10/01/10 - 12/31/10 |
15,000 | $ | 65.00 | $ | 94.25 | |||||||
01/01/11 - 06/30/11 |
24,000 | $ | 70.00 | $ | 92.50 | |||||||
07/01/11 - 09/30/11 |
9,000 | $ | 70.00 | $ | 95.00 | |||||||
10/01/11 - 12/31/11 |
6,000 | $ | 70.00 | $ | 96.35 | |||||||
01/01/11 - 02/28/11 |
10,000 | $ | 70.00 | $ | 92.00 | |||||||
10/01/10 - 12/31/10 |
9,000 | $ | 70.00 | $ | 91.50 | |||||||
01/01/11 - 07/31/11 |
21,000 | $ | 70.00 | $ | 94.80 | |||||||
10/01/10 - 11/30/10 |
6,000 | $ | 70.00 | $ | 95.50 | |||||||
01/01/11 - 03/31/11 |
9,000 | $ | 75.00 | $ | 93.50 | |||||||
07/01/11 - 12/31/11 |
12,000 | $ | 75.00 | $ | 95.15 | |||||||
10/01/10 - 12/31/10 |
15,000 | $ | 75.00 | $ | 101.00 | |||||||
01/01/11 - 12/31/11 |
36,000 | $ | 75.00 | $ | 104.30 | |||||||
01/01/12 - 06/30/12 |
60,000 | $ | 75.00 | $ | 106.90 | |||||||
10/01/10 - 10/31/10 |
5,000 | $ | 75.00 | $ | 101.00 | |||||||
01/01/11 - 02/28/11 |
8,000 | $ | 75.00 | $ | 103.50 | |||||||
03/01/11 - 04/30/11 |
16,000 | $ | 75.00 | $ | 104.50 | |||||||
01/01/11 - 12/31/11 |
36,000 | $ | 65.00 | $ | 100.00 | |||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 97.20 | |||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 98.55 | |||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 100.00 | |||||||
10/01/10 - 07/31/12 |
335,000 | $ | 65.00 | $ | 100.40 | |||||||
03/01/11 - 08/31/11 |
46,000 | $ | 65.00 | $ | 94.80 | |||||||
09/01/11 - 12/31/11 |
61,000 | $ | 65.00 | $ | 97.40 | |||||||
01/01/12 - 06/30/12 |
182,000 | $ | 65.00 | $ | 99.25 | |||||||
09/01/11 - 12/31/11 |
61,000 | $ | 65.00 | $ | 99.00 | |||||||
03/01/11 - 08/31/11 |
46,000 | $ | 65.00 | $ | 96.75 | |||||||
01/01/12 - 06/30/12 |
91,000 | $ | 65.00 | $ | 101.00 | |||||||
01/01/12 - 06/30/12 |
182,000 | $ | 65.00 | $ | 100.75 | |||||||
01/01/12 - 06/30/12 |
91,000 | $ | 65.00 | $ | 102.75 | |||||||
07/01/12 - 07/31/12 |
62,000 | $ | 65.00 | $ | 102.25 | |||||||
05/01/11 - 12/31/11 |
122,500 | $ | 65.00 | $ | 100.00 | |||||||
07/01/12 - 07/31/12 |
31,000 | $ | 65.00 | $ | 105.25 | |||||||
05/01/11 - 12/31/11 |
122,500 | $ | 65.00 | $ | 106.50 | |||||||
11/01/10 - 02/28/11 |
60,000 | $ | 65.00 | $ | 98.75 | |||||||
01/01/11 - 12/31/11 |
182,500 | $ | 65.00 | $ | 100.00 | |||||||
01/01/12 - 06/30/12 |
136,500 | $ | 65.00 | $ | 107.25 | |||||||
07/01/12 - 09/30/12 |
92,000 | $ | 65.00 | $ | 109.40 | |||||||
08/01/12 - 09/30/12 |
61,000 | $ | 65.00 | $ | 110.25 | |||||||
08/01/12 -
09/30/12 |
61,000 | $ | 65.00 | $ | 112.00 | |||||||
10/01/12 - 10/31/12 |
62,000 | $ | 65.00 | $ | 112.65 | |||||||
01/01/12 - 07/31/12 |
106,500 | $ | 65.00 | $ | 110.00 |
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Crude | Purchased | |||||||
Oil | Put | |||||||
Settlement Period | (Barrels) | (Nymex) | ||||||
Crude Oil Floors |
||||||||
01/01/11 - 06/30/12 |
273,500 | $ | 65.00 | |||||
01/01/11 - 06/30/12 |
273,500 | $ | 65.00 |
Natural | Purchased | Written | ||||||||||
Gas | Put | Call | ||||||||||
Settlement Period | (MMbtu) | (Nymex) | (Nymex) | |||||||||
Natural Gas Costless Collars |
||||||||||||
10/01/10 - 03/31/11 |
240,000 | $ | 6.50 | $ | 8.25 | |||||||
10/01/10 - 12/31/10 |
210,000 | $ | 5.15 | $ | 7.00 | |||||||
10/01/10 - 03/31/11 |
420,000 | $ | 6.40 | $ | 7.80 | |||||||
01/01/11 - 12/31/11 |
360,000 | $ | 5.75 | $ | 7.65 | |||||||
01/01/11 - 12/31/11 |
480,000 | $ | 5.75 | $ | 7.40 | |||||||
04/01/11 - 12/31/11 |
360,000 | $ | 5.00 | $ | 6.55 |
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Table of Contents
The following table reflects commodity derivative contracts entered into subsequent to
September 30, 2010, the associated volumes and the corresponding weighted average NYMEX floor and
cap price.
Crude | Written | |||||||
Oil | Call | |||||||
Settlement Period | (Barrels) | (Nymex) | ||||||
Crude
Oil Calls* |
||||||||
01/01/11 - 06/30/11 |
90,500 | $ | 95.00 | |||||
01/01/11 - 06/30/11 |
90,500 | $ | 97.50 |
* | Written calls convert floors included within hedges outstanding as of September 30, 2010 to collars. |
Crude | Purchased | |||||||
Oil | Put | |||||||
Settlement Period | (Barrels) | (Nymex) | ||||||
Crude Oil Floors |
||||||||
07/01/11 - 06/30/12 |
91,500 | $ | 65.00 | |||||
07/01/11 - 06/30/12 |
91,500 | $ | 65.00 |
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Table of Contents
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of September 30, 2010, our management, including our principal executive officer and
principal financial officer, has evaluated the effectiveness of the design and operation of our
disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of
1934. There are inherent limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or overriding of the
controls and procedures. Accordingly, even effective disclosure controls and procedures can only
provide reasonable assurance of achieving their control objectives. Based upon and as of the date
of the evaluation, our principal executive officer and our principal financial officer concluded
that the design and operation of our disclosure controls and procedures were effective at a
reasonable assurance level.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting during the third
quarter of 2010 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
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Table of Contents
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
As discussed in Note 4 of Notes to the Consolidated Financial Statements included in Part I.
Financial Statements, we are party to various legal actions arising in the ordinary course of
business and does not expect these matters to have a material adverse effect on its consolidated
financial condition, results of operations or cash flows.
ITEM 1A. RISK FACTORS
There
have been no material changes to the risk factors disclosed in
Item 1.A. of our report on Form 10-K for the year ended
December 31, 2009 or our reports on Form 10-Q for the
quarters ended March 31, 2010 and June 30, 2010.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
In the third quarter 2010, we elected to allow employees to deliver shares of vested
restricted stock with a fair market value equal to their federal, state and local tax withholding
amounts on the date of issue in lieu of cash payment.
Total Number of | Average Price | |||||||
Period | Shares Purchased | Paid per Share | ||||||
September 2010 |
11,736 | $ | 16.955 | |||||
TOTAL |
11,736 | $ | 16.955 |
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. (REMOVED AND RESERVED)
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS
3.1 | Certificate of Incorporation (filed as Exhibit 3.1 to Brighams Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein by reference) |
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3.2 | Certificates of Amendment to Certificate of Incorporation (filed as Exhibit 3.1.1 to
Brighams Registration Statement on Form S-3 (Registration No. 333-37558), and incorporated
herein by reference) |
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3.3 | Bylaws, as amended through May 28, 2009 (incorporated by reference to Exhibit 3.5 to
Brighams Current Report on Form 8-K filed May 28, 2009) |
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3.4 | Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated
June 14, 2006 (filed as Exhibit 3.4 to Brighams Annual Report on Form 10-K for the year ended
December 31, 2008 and incorporated herein by reference) |
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3.5 | Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated
October 7, 2009 (filed as Exhibit 3.5 to Brighams Current Report on Form 8-K (dated October
13, 2009) and incorporated herein by reference) |
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4.1 | Form of Common Stock Certificate (filed as Exhibit 4.1 to Brighams Registration Statement on
Form S-1 (Registration No. 333-22491) and incorporated herein by reference) |
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4.2 | Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham
Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brighams Current Report
on Form 8-K, as amended (filed November 8, 2000) and incorporated herein by reference) |
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4.3 | Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par
Value $.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit
4.2.1 to Brighams Annual Report on Form 10-K for the year ended December 31, 2000 (filed
March 23, 2001) and incorporated herein by reference) |
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4.4 | Certificate of Elimination of Certificate of Designations of Series A Preferred Stock (Par
Value $.01 Per Share) of Brigham Exploration Company filed August 9, 2010 (filed as Exhibit
3.7 to Brighams Current Report on Form 8-K (filed August 10, 2010) and incorporated herein by
reference |
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4.5 | Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham
Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brighams Annual Report
on Form 10-K for the year ended December 31, 2002 (filed March 31, 2003) and incorporated
herein by reference) |
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4.6 | Certificate of Elimination of Certificate of Designations of Series B Preferred Stock of
Brigham Exploration Company, dated June 4, 2004, (filed as Exhibit 99.2 to Brighams Current
Report on Form 8-K (filed July 20, 2004) and incorporated herein by reference) |
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4.7 | Indenture, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named
therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.1 to Brighams Current
Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference) |
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4.8 | Notations of Guarantees, dated April 20, 2006, among Brigham Exploration Company, the
Guarantors named therein and Wells Fargo Bank, N.A., as trustee, (filed as Exhibit 4.2 to
Brighams Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by
reference) |
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4.9 | Rule 144A 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.3 to
Brighams Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by
reference) |
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4.10 | Reg S 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.4 to Brighams
Current Report on Form 8-K (filed April 24, 2006) and incorporated herein by reference) |
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4.11 | Notations of Guarantees dated as of April 9, 2007, among Brigham Exploration Company, the
Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.2 to
Brighams Current Report on Form 8-K (filed April 13, 2007) and incorporated in by reference) |
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4.12 | Rule 144A 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.3 to Brighams Current Report on
Form 8-K (filed April 13, 2007) and incorporated in by reference) |
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4.13 | Reg S 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.4 to Brighams Current Report on Form
8-K (filed April 13, 2007) and incorporated herein by reference) |
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4.14 | Rights Agreement, dated as of December 10, 2008, between Brigham Exploration Company and
American Stock Transfer & Trust Company, LLC, as Rights Agent (filed as Exhibit 4.1 to
Brighams Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by
reference) |
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4.15 | Certificate of Designations of Series C Junior Participating Preferred Stock of Brigham
Exploration Company effective as of December 10, 2008 (filed as Exhibit 3.1 to Brighams
Current Report on Form 8-K (filed December 11, 2008) and incorporated herein by reference) |
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4.16 | Certificate of Elimination of Certificate of Designations of Series C Junior Preferred Stock
of Brigham Exploration Company effective March 9, 2010 (filed as Exhibit 3.6 to Brighams
Current Report on Form 8-K (filed March 15, 2010) and incorporated herein by reference) |
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4.17 | First Supplemental Indenture, dated September 27, 2010, among the Company, the Guarantors and
Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.16 to Brighams Current
Report on Form 8-K (filed October 1, 2010) and incorporated herein by reference) |
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4.18 | Indenture, dated September 27, 2010, among the Company, the Guarantors and Wells Fargo Bank,
National Association, as Trustee (filed as Exhibit 4.17 to Brighams Current Report on Form
8-K (filed October 1, 2010) and incorporated herein by reference) |
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4.19 | Rule 144A 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.18 to
Brighams Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by
reference) |
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4.20 | Regulation S 8 3/4% Senior Note due 2018 and Notation of Guarantee (filed as Exhibit 4.19 to
Brighams Current Report on Form 8-K (filed October 1, 2010) and incorporated herein by
reference) |
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4.21 | Registration Rights Agreement, dated September 27, 2010, among the Company, the Guarantors
and the Initial Purchasers (filed as Exhibit 4.20 to Brighams Current Report on Form 8-K
(filed October 1, 2010) and incorporated herein by reference) |
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10.48 | Seventh Amendment and Consent to the Fourth Amended and Restated Credit Agreement dated as
of June 29, 2005 between the Company and the banks named therein (filed as Exhibit 10.48 to
Brighams Current Report on Form 8-K (filed September 13, 2010) and incorporated herein by
reference) |
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10.49 | Purchase Agreement dated September 16, 2010 among the Company, the Guarantors and the
Initial Purchasers. (filed as Exhibit 10.49 to Brighams Current Report on Form 8-K (filed
September 20, 2010) and incorporated herein by reference) |
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31.1 | Certification of Chief Executive Officer of the Company pursuant to Rule 13a-14(a) of the
Securities Exchange Act of 1934 |
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31.2 | Certification of Chief Financial Officer of the Company pursuant to Rule 13a-14(a) of the
Securities Exchange Act of 1934 |
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32.1 | Certification of Chief Executive Officer of the Company pursuant to 18 U.S.C. § 1350 |
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32.2 | Certification of Chief Financial Officer of the Company pursuant to 18 U.S.C. § 1350 |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized on
November 3, 2010.
BRIGHAM EXPLORATION COMPANY | ||||||
By: | /s/ BEN M. BRIGHAM | |||||
Chief Executive Officer, President and Chairman of the Board |
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By: | /s/ EUGENE B. SHEPHERD, JR. | |||||
Executive Vice President and Chief Financial Officer |
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