UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form 10-Q
|
x
|
QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
|
For
the Quarterly Period Ended June 30, 2008
OR
|
¨
|
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: 000-51719
LINN
ENERGY, LLC
(Exact name of registrant as
specified in its charter)
|
Delaware
|
65-1177591
|
|
(State
or other jurisdiction of incorporation or organization)
|
(IRS
Employer
Identification
No.)
|
|
600
Travis, Suite 5100
Houston,
Texas
|
77002
|
|
(Address
of principal executive offices)
|
(Zip
Code)
|
|
(281) 840-4000
(Registrant’s
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 x No ¨
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.
(Check one).
|
Large
accelerated filer x Accelerated
filer ¨ Non-accelerated
filer ¨ Smaller
reporting company ¨
|
(Do not check if a smaller reporting
company)
Indicate
by check mark whether registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes ¨ No x
As of
July 31, 2008, there were 115,170,758 units outstanding.
|
Page
|
|||
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 40 | |
| Item 3. | Defaults Upon Senior Securities | 40 | |
| Item 4. | Submission of Matters to a Vote of Security Holders | 40 | |
As
commonly used in the oil and gas industry and as used in this Quarterly Report
on Form 10-Q, the following terms have the following meanings:
Bbl. One stock
tank barrel or 42 United States gallons liquid volume.
Bcfe. One billion
cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of
oil, condensate or natural gas liquids.
MBbls. One
thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand
cubic feet.
Mcfe. One thousand
cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl
of oil, condensate or natural gas liquids.
Mid-Continent
I. February 2007 acquisition of oil and gas properties in the
Texas Panhandle from Cavallo Energy LP, acting through its general partner,
Stallion Energy LLC, for a contract price of $415.0 million.
Mid-Continent II. June 2007
acquisition of oil and gas properties in the Texas Panhandle for a contract
price of $90.5 million.
Mid-Continent III. August 2007
acquisition of oil and gas properties in Oklahoma, Kansas and the Texas
Panhandle from Dominion Resources, Inc. for a contract price of $2.05
billion.
Mid-Continent IV. January 2008
acquisition of oil and gas properties in Oklahoma from Lamamco Drilling Company
for a contract price of $552.2 million.
MMBtu. One million
British thermal units.
MMcf. One million
cubic feet.
MMcfe. One million
cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of
oil, condensate or natural gas liquids.
MMcfe/d. One MMcfe per
day.
MMMBtu. One
billion British thermal units.
NYMEX. The New
York Mercantile Exchange.
Tcfe. One trillion
cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl
of oil, condensate or natural gas liquids.
ii
CONDENSED
CONSOLIDATED BALANCE SHEETS
|
June 30,
|
December 31,
|
|||||||
|
2008
|
2007
|
|||||||
|
(Unaudited)
|
||||||||
|
(in
thousands,
except
unit amounts)
|
||||||||
|
Assets
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 9,612 | $ | 1,441 | ||||
|
Accounts
receivable – trade, net
|
274,645 | 149,850 | ||||||
|
Derivative
instruments
|
— | 26,100 | ||||||
|
Other
current assets
|
11,891 | 5,768 | ||||||
|
Total
current assets
|
296,148 | 183,159 | ||||||
|
Noncurrent
assets:
|
||||||||
|
Oil
and gas properties and equipment (successful efforts
method)
|
3,770,466 | 3,618,741 | ||||||
|
Less
accumulated depreciation, depletion and amortization
|
(154,558 | ) | (127,265 | ) | ||||
| 3,615,908 | 3,491,476 | |||||||
|
Other
property and equipment
|
20,628 | 37,407 | ||||||
|
Less
accumulated depreciation
|
(2,817 | ) | (5,383 | ) | ||||
| 17,811 | 32,024 | |||||||
|
Goodwill
|
69,674 | 64,419 | ||||||
|
Other
noncurrent assets, net
|
17,414 | 36,625 | ||||||
|
Noncurrent
assets held for sale
|
557,472 | — | ||||||
| 644,560 | 101,044 | |||||||
|
Total
assets
|
$ | 4,574,427 | $ | 3,807,703 | ||||
|
Liabilities
and Unitholders’ Capital
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable and accrued expenses
|
$ | 197,786 | $ | 223,636 | ||||
|
Derivative
instruments
|
354,765 | 6,148 | ||||||
|
Other
current liabilities
|
73,890 | 12,943 | ||||||
|
Total
current liabilities
|
626,441 | 242,727 | ||||||
|
Noncurrent
liabilities:
|
||||||||
|
Credit
facility
|
1,826,000 | 1,443,000 | ||||||
|
Term
loan
|
156,398 | — | ||||||
|
Senior
notes, net
|
250,000 | — | ||||||
|
Derivative
instruments
|
738,127 | 63,813 | ||||||
|
Other
noncurrent liabilities
|
29,363 | 31,522 | ||||||
|
Noncurrent
liabilities associated with assets held for sale
|
8,020 | — | ||||||
|
Total
noncurrent liabilities
|
3,007,908 | 1,538,335 | ||||||
|
Unitholders’
capital:
|
||||||||
|
115,202,391
units and 113,815,914 units issued and outstanding at June 30, 2008
and December 31, 2007, respectively
|
2,259,598 | 2,374,660 | ||||||
|
Accumulated
loss
|
(1,319,520 | ) | (348,019 | ) | ||||
| 940,078 | 2,026,641 | |||||||
|
Total
liabilities and unitholders’ capital
|
$ | 4,574,427 | $ | 3,807,703 | ||||
The accompanying notes are an integral
part of these condensed consolidated financial statements.
|
Three
Months Ended
June 30,
|
Six
Months Ended
June 30,
|
|||||||||||||||
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil,
gas and natural gas liquid sales
|
$ | 255,586 | $ | 32,495 | $ | 431,458 | $ | 56,062 | ||||||||
|
Loss
on oil and gas derivatives
|
(870,804 | ) | (17,707 | ) | (1,139,598 | ) | (78,148 | ) | ||||||||
|
Natural
gas marketing revenues
|
3,593 | 2,740 | 6,409 | 4,661 | ||||||||||||
|
Other
revenues
|
642 | 487 | 1,121 | 1,132 | ||||||||||||
| (610,983 | ) | 18,015 | (700,610 | ) | (16,293 | ) | ||||||||||
|
Expenses:
|
||||||||||||||||
|
Operating
expenses
|
46,641 | 9,743 | 82,762 | 17,609 | ||||||||||||
|
Natural
gas marketing expenses
|
3,260 | 2,323 | 5,677 | 3,975 | ||||||||||||
|
General
and administrative expenses
|
18,171 | 11,887 | 37,398 | 22,193 | ||||||||||||
|
Data
license expenses
|
47 | — | 2,475 | — | ||||||||||||
|
Depreciation,
depletion and amortization
|
50,402 | 6,736 | 94,483 | 12,470 | ||||||||||||
| 118,521 | 30,689 | 222,795 | 56,247 | |||||||||||||
| (729,504 | ) | (12,674 | ) | (923,405 | ) | (72,540 | ) | |||||||||
|
Other
income and (expenses):
|
||||||||||||||||
|
Interest
expense, net of amounts capitalized
|
(23,332 | ) | (4,621 | ) | (48,625 | ) | (8,590 | ) | ||||||||
|
Gain
(loss) on interest rate swaps
|
31,604 | 274 | (7,789 | ) | 197 | |||||||||||
|
Other,
net
|
(4,313 | ) | 136 | (4,476 | ) | (522 | ) | |||||||||
| 3,959 | (4,211 | ) | (60,890 | ) | (8,915 | ) | ||||||||||
|
Loss
from continuing operations before income
taxes
|
(725,545 | ) | (16,885 | ) | (984,295 | ) | (81,455 | ) | ||||||||
|
Income
tax benefit (provision)
|
164 | (179 | ) | (45 | ) | (4,030 | ) | |||||||||
|
Loss
from continuing operations
|
(725,381 | ) | (17,064 | ) | (984,340 | ) | (85,485 | ) | ||||||||
|
Income
(loss) from discontinued operations, net
of taxes
|
13,239 | (62 | ) | 12,839 | 512 | |||||||||||
|
Net
loss
|
$ | (712,142 | ) | $ | (17,126 | ) | $ | (971,501 | ) | $ | (84,973 | ) | ||||
|
Net
income (loss) per unit:
|
||||||||||||||||
|
Loss
from continuing operations – basic
|
$ | (6.35 | ) | $ | (0.29 | ) | $ | (8.63 | ) | $ | (1.63 | ) | ||||
|
Loss
from continuing operations – diluted
|
$ | (6.35 | ) | $ | (0.29 | ) | $ | (8.63 | ) | $ | (1.63 | ) | ||||
|
Income
(loss) from discontinued operations, net of taxes – basic
|
$ | 0.12 | $ | — | $ | 0.11 | $ | 0.01 | ||||||||
|
Income
(loss) from discontinued operations, net of taxes –
diluted
|
$ | 0.12 | $ | — | $ | 0.11 | $ | 0.01 | ||||||||
|
Net
loss – basic
|
$ | (6.23 | ) | $ | (0.29 | ) | $ | (8.52 | ) | $ | (1.62 | ) | ||||
|
Net
loss – diluted
|
$ | (6.23 | ) | $ | (0.29 | ) | $ | (8.52 | ) | $ | (1.62 | ) | ||||
|
Weighted
average units outstanding:
|
||||||||||||||||
|
Units
– basic
|
114,252 | 59,293 | 114,005 | 52,413 | ||||||||||||
|
Units
– diluted
|
114,252 | 59,293 | 114,005 | 52,413 | ||||||||||||
|
Distributions
declared per unit
|
$ | 0.63 | $ | 0.52 | $ | 1.26 | $ | 1.04 | ||||||||
The accompanying notes are an integral
part of these condensed consolidated financial statements.
2
|
Six
Months Ended
June 30,
2008
|
||||||||
|
Units
|
Dollars
|
|||||||
|
(in
thousands)
|
||||||||
|
Unitholders’
capital:
|
||||||||
|
Balance,
beginning of year
|
113,816 | $ | 2,374,660 | |||||
|
Issuance
of units
|
1,467 | 23,483 | ||||||
|
Purchase
of units
|
(81 | ) | (1,642 | ) | ||||
|
Distributions
to unitholders
|
(144,755 | ) | ||||||
|
Unit-based
compensation expenses
|
7,852 | |||||||
|
Balance,
end of period
|
115,202 | 2,259,598 | ||||||
|
Treasury
units (at cost):
|
||||||||
|
Balance,
beginning of period
|
— | — | ||||||
|
Purchase
of units
|
(81 | ) | (1,642 | ) | ||||
|
Cancellation
of units
|
81 | 1,642 | ||||||
|
Balance,
end of period
|
— | — | ||||||
|
Accumulated
loss:
|
||||||||
|
Balance,
beginning of period
|
(348,019 | ) | ||||||
|
Net
loss
|
(971,501 | ) | ||||||
|
Balance,
end of period
|
(1,319,520 | ) | ||||||
|
Total
unitholders’ capital
|
$ | 940,078 | ||||||
The accompanying notes are an integral
part of these condensed consolidated financial
statements.
|
Six
Months Ended June 30,
|
||||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Cash
flow from operating activities:
|
||||||||
|
Net
loss
|
$ | (971,501 | ) | $ | (84,973 | ) | ||
|
Adjustments
to reconcile net loss to net cash provided by (used in) operating
activities:
|
||||||||
|
Depreciation,
depletion and amortization
|
100,872 | 24,789 | ||||||
|
Amortization
and write-off of deferred financing fees and other
|
8,924 | 353 | ||||||
|
Unit-based
compensation and unit warrant expenses
|
7,852 | 7,691 | ||||||
|
Deferred
income tax
|
— | 3,360 | ||||||
|
Mark-to-market
on derivatives:
|
||||||||
|
Total
losses
|
1,147,387 | 77,951 | ||||||
|
Cash
settlements
|
(28,550 | ) | 13,504 | |||||
|
Cash
settlements on canceled derivatives
|
(68,197 | ) | — | |||||
|
Premiums
paid for derivatives
|
(1,278 | ) | (52,992 | ) | ||||
|
Changes
in assets and liabilities:
|
||||||||
|
Increase
in accounts receivable
|
(125,286 | ) | (21,654 | ) | ||||
|
(Increase)
decrease in other assets
|
(4,967 | ) | 4,294 | |||||
|
Increase
(decrease) in accounts payable and accrued expenses
|
(4,550 | ) | 6,800 | |||||
|
Increase
(decrease) in other liabilities
|
(123 | ) | 1,490 | |||||
|
Net
cash provided by (used in) operating activities
|
60,583 | (19,387 | ) | |||||
|
Cash
flow from investing activities:
|
||||||||
|
Acquisition
of oil and gas properties
|
(573,030 | ) | (539,304 | ) | ||||
|
Additions
to oil and gas properties
|
(172,994 | ) | (43,478 | ) | ||||
|
Purchases
of other property and equipment
|
(3,419 | ) | (7,486 | ) | ||||
|
Proceeds
from pending sales of oil and gas properties
|
69,250 | — | ||||||
|
Proceeds
from sales of other property and equipment
|
7,310 | 2,934 | ||||||
|
Net
cash used in investing activities
|
(672,883 | ) | (587,334 | ) | ||||
|
Cash
flow from financing activities:
|
||||||||
|
Proceeds
from sale and issuance of units
|
— | 620,000 | ||||||
|
Purchase
of units
|
(1,642 | ) | (7,399 | ) | ||||
|
Proceeds
from issuance of debt
|
1,173,000 | 308,000 | ||||||
|
Principal
payments on debt
|
(384,916 | ) | (258,192 | ) | ||||
|
Distributions
to unitholders
|
(144,755 | ) | (52,746 | ) | ||||
|
Financing
fees and other, net
|
(21,216 | ) | (8,579 | ) | ||||
|
Net
cash provided by financing activities
|
620,471 | 601,084 | ||||||
|
Net
increase (decrease) in cash and cash equivalents
|
8,171 | (5,637 | ) | |||||
|
Cash
and cash equivalents:
|
||||||||
|
Beginning
|
1,441 | 6,595 | ||||||
|
Ending
|
$ | 9,612 | $ | 958 | ||||
The
accompanying notes are an integral part of these condensed consolidated
financial statements.
4
|
(1)
|
Basis
of Presentation
|
Linn
Energy, LLC (“Linn Energy” or the “Company”) is an independent oil and gas
company focused on the development and acquisition of long life properties which
complement its asset profile in producing basins within the United
States.
The
condensed consolidated financial statements at June 30, 2008, and for the
three and six months ended June 30, 2008 and 2007, are unaudited, but in
the opinion of management include all adjustments (consisting only of normal
recurring adjustments) necessary for a fair presentation of the results for the
interim periods. Certain information and note disclosures normally
included in annual financial statements prepared in accordance with United
States generally accepted accounting principles (“GAAP”) have been condensed or
omitted under Securities and Exchange Commission (“SEC”) rules and regulations,
and as such this report should be read in conjunction with the financial
statements and notes in the Company’s Annual Report on Form 10-K for the
year ended December 31, 2007. The results reported in these
unaudited condensed consolidated financial statements should not necessarily be
taken as indicative of results that may be expected for the entire
year.
Certain
amounts in the condensed consolidated financial statements and notes thereto
have been reclassified to conform to the 2008 financial statement
presentation. Such reclassifications include those related to the
presentation of discontinued operations (see Note 2) on the condensed
consolidated statements of operations.
The
condensed consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries. All significant intercompany
transactions and balances have been eliminated upon consolidation.
Management
of the Company has made a number of estimates and assumptions relating to the
reporting of assets and liabilities and revenues and expenses and the disclosure
of contingent assets and liabilities to prepare these condensed consolidated
financial statements in conformity with GAAP. Actual results could
differ from those estimates.
The
Company’s Appalachian Basin and Mid Atlantic Well Service (“Mid Atlantic”)
operations have been classified as discontinued operations on the condensed
consolidated statement of operations for all periods
presented. Unless otherwise indicated, information about the
statement of operations that is presented in the notes to condensed consolidated
financial statements relates only to Linn Energy’s continuing
operations.
|
(2)
|
Assets
Held for Sale and Discontinued
Operations
|
On
July 1, 2008, the Company completed the sale of its interests in oil and
gas properties located in the Appalachian Basin to XTO Energy, Inc. (“XTO”) for
a contract price of $600.0 million, subject to closing
adjustments. The Company received a cash down payment of $60.0
million in April 2008 which is included in “other current liabilities” on the
condensed consolidated balance sheet at June 30, 2008. The
Company used the net proceeds from the sale of approximately $560.0 million to
repay loans outstanding under its term loan agreement and reduce indebtedness
under its credit facility (see Note 8). The carrying value of
net assets sold was approximately $405.0 million, resulting in a gain on the
sale of approximately $155.0 million, which will be recorded in discontinued
operations during the third quarter of 2008. The gain is subject to
normal post-closing adjustments.
In
addition, in March 2008, the Company exited the drilling and service business in
the Appalachian Basin provided by its wholly owned subsidiary Mid Atlantic Well
Service (“Mid Atlantic”). At June 30, 2008, substantially all of
the property and equipment previously held by Mid Atlantic totaling
approximately $9.2 million had been sold. During the three and six
months ended June 30, 2008, the Company recorded a loss
5
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
on the
sale of the Mid Atlantic assets of approximately $1.0 million and $1.3 million,
respectively, which is recorded in “income (loss) from discontinued operations,
net of taxes” on the condensed consolidated statements of
operations.
In
addition, on June 3, 2008, the Company entered into an agreement to sell
certain of its assets in the Verden area in Oklahoma to Laredo Petroleum, Inc.
(“Laredo”) for a contract price of $185.0 million, subject to closing
adjustments. The Company received a cash down payment of $9.3 million
in May 2008 which is included in “other current liabilities” on the condensed
consolidated balance sheet at June 30, 2008. The Company plans
to use net proceeds from the sale to reduce indebtedness (see
Note 8). The Company anticipates closing in the third quarter of
2008, subject to closing conditions. There can be no assurance that
all of the conditions to closing will be satisfied. The carrying
value of net assets to be sold was approximately $143.0 million.
The
following summarizes the Appalachian Basin, Mid Atlantic and Verden assets and
liabilities classified as held for sale on the condensed consolidated balance
sheet.
|
June 30,
|
||||
|
2008
|
||||
|
(in
thousands)
|
||||
|
Noncurrent
assets:
|
||||
|
Oil
and gas properties and equipment, net
|
$ | 549,910 | ||
|
Other
property and equipment, net
|
7,562 | |||
|
Total
assets held for sale
|
$ | 557,472 | ||
|
Noncurrent
liabilities:
|
||||
|
Asset
retirement obligations
|
$ | 8,020 | ||
|
Total
liabilities associated with assets held for sale
|
$ | 8,020 | ||
The
following summarizes the Appalachian Basin and Mid Atlantic amounts included in
income from discontinued operations on the condensed consolidated statements of
operations.
|
Three
Months Ended
June 30,
|
Six
Months Ended
June 30,
|
|||||||||||||||
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||
|
(in
thousands)
|
||||||||||||||||
|
Total
revenues
|
$ | 28,828 | $ | 18,096 | $ | 49,989 | $ | 36,687 | ||||||||
|
Total
operating expenses
|
(9,086 | ) | (12,702 | ) | (23,556 | ) | (25,071 | ) | ||||||||
|
Interest
expense
|
(6,503 | ) | (5,605 | ) | (13,594 | ) | (11,472 | ) | ||||||||
|
Income
(loss) from discontinued operations
|
13,239 | (211 | ) | 12,839 | 144 | |||||||||||
|
Income
tax benefit
|
— | 149 | — | 368 | ||||||||||||
|
Income
(loss) from discontinued operations, net of taxes
|
$ | 13,239 | $ | (62 | ) | $ | 12,839 | $ | 512 | |||||||
The
Company computed interest expense related to discontinued operations in
accordance with Emerging Issues Task Force Issue No. 87-24, “Allocation of Interest to
Discontinued Operations” based on debt required to be repaid as a result
of the disposal transaction.
6
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
|
(3)
|
Acquisitions
|
The
Company accounts for its acquisitions using the purchase method of accounting as
prescribed in SFAS No. 141, “Business
Combinations.” On January 31, 2008, the Company completed
the acquisition of certain oil and gas properties located primarily in the
Mid-Continent region from Lamamco Drilling Company (“Lamamco”) for a contract
price of $552.2 million, subject to closing adjustments (“Mid-Continent
IV”). The acquisition was financed with a combination of borrowings
under the Company’s credit facility and proceeds from a term loan entered into
at closing (see Note 8).
The
following presents the preliminary purchase accounting for the
Mid-Continent IV acquisition, based on preliminary estimates of fair
value:
|
Mid-Continent
IV
|
||||
|
(in
thousands)
|
||||
|
Cash
|
$ | 532,826 | ||
|
Estimated
transaction costs
|
870 | |||
| 533,696 | ||||
|
Fair
value of liabilities assumed
|
4,029 | |||
|
Total
purchase price
|
$ | 537,725 | ||
The
following presents the preliminary allocation of the purchase price for the
Mid-Continent IV acquisition, based on preliminary estimates of fair
value:
|
Mid-Continent
IV
|
||||
|
(in
thousands)
|
||||
|
Current
assets
|
$ | 1,811 | ||
|
Oil
and gas properties
|
533,805 | |||
|
Other
property and equipment
|
2,109 | |||
| $ | 537,725 | |||
The
purchase price and purchase price allocation above are based on reserve reports,
published market prices and estimates by management. The most
significant assumptions are related to the estimated fair values assigned to
proved oil and gas properties. To estimate the fair values of these
properties, the Company utilized estimates of oil and gas
reserves. The Company estimated future prices to apply to the
estimated reserve quantities acquired, and estimated future operating and
development costs to arrive at estimates of future net revenues. The
Company also reviewed comparable purchases and sales of oil and gas properties
within the same regions. The purchase price and the allocation of the
purchase price are preliminary. Items pending completion include
final closing adjustments. The purchase price and purchase price
allocation will be finalized within one year of the acquisition
date.
The
following unaudited pro forma financial information presents a summary of Linn
Energy’s consolidated results of continuing operations for the three and six
months ended June 30, 2008 and 2007, assuming the Mid-Continent IV
acquisition had been completed as of January 1, 2007,
including
7
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
adjustments
to reflect the allocation of the purchase price to the acquired net
assets. The pro forma financial information also assumes that the
following 2007 acquisitions were completed as of January 1,
2007:
|
|
·
|
February 1,
2007, acquisition of certain oil and gas properties and related assets in
the Texas Panhandle for a contract price of $415.0 million
(“Mid-Continent I”)
|
|
|
·
|
June 12,
2007, acquisition of certain oil and gas properties in the Texas Panhandle
for a contract price of $90.5 million
(“Mid-Continent II”)
|
|
|
·
|
August 31,
2007, acquisition of certain oil and gas properties in the Mid-Continent,
in Oklahoma, Kansas and the Texas Panhandle for a contract price of
$2.05 billion
(“Mid-Continent III”)
|
The
revenues and expenses of the Mid-Continent I, Mid-Continent II and
Mid-Continent III assets are included in the consolidated results of the Company
as of February 1, 2007, June 12, 2007 and September 1, 2007,
respectively. The revenues and expenses of the Mid-Continent IV
assets are included in the consolidated results of the Company effective
February 1, 2008. The pro forma financial information is not
necessarily indicative of the results of operations if the acquisitions had been
effective as of these dates. All amounts reflect continuing
operations.
|
Three
Months Ended
June 30,
|
Six
Months Ended
June 30,
|
|||||||||||||||
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||
|
(in
thousands, except per unit amounts)
|
||||||||||||||||
|
Total
revenues
|
$ | (610,983 | ) | $ | 122,051 | $ | (691,337 | ) | $ | 184,575 | ||||||
|
Total
operating expenses
|
$ | 118,521 | $ | 89,830 | $ | 227,432 | $ | 170,924 | ||||||||
|
Income
(loss) from continuing operations
|
$ | (725,381 | ) | $ | 4,972 | $ | (983,334 | ) | $ | (44,994 | ) | |||||
|
Income
(loss) from continuing operations per unit:
|
||||||||||||||||
|
Units
– basic
|
$ | (6.35 | ) | $ | 0.08 | $ | (8.62 | ) | $ | (0.86 | ) | |||||
|
Units
– diluted
|
$ | (6.35 | ) | $ | 0.08 | $ | (8.62 | ) | $ | (0.86 | ) | |||||
8
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
|
(4)
|
Goodwill
|
The
entire goodwill balance of $69.7 million at June 30, 2008 and $64.4 million
at December 31, 2007 is related to the Mid-Continent III acquisition
in August 2007 (see Note 3).
The
following reflects the changes in the carrying amount of goodwill during the six
months ended June 30, 2008 and the year ended December 31, 2007, which
resulted from normal post-closing adjustments (in thousands):
|
Balance,
December 31, 2006
|
$ | — | ||
|
Mid-Continent
III acquisition
|
64,419 | |||
|
Balance,
December 31, 2007
|
64,419 | |||
|
Mid-Continent
III acquisition – purchase accounting adjustments
|
5,255 | |||
|
Balance,
June 30, 2008
|
$ | 69,674 |
|
(5)
|
Unitholders’
Capital
|
Issuance
of Units
During
the six months ended June 30, 2008, the Company issued 410,000 units in
connection with the termination of certain contractual obligations in the
Western region (equal to a fair value of approximately $8.7
million).
During
the six months ended June 30, 2008, the Company issued 600,000 units in
connection with the acquisition of certain gas properties in the Appalachian
Basin (equal to a fair value of approximately $14.7 million).
Cancellation
of Units
During
the six months ended June 30, 2008, the Company purchased 80,780 restricted
units from employees for approximately $1.6 million in conjunction with the
vesting of restricted unit awards. The proceeds were used to fund the
employees’ minimum payroll taxes on the awards, and the Company canceled the
units.
|
(6)
|
Oil
and Gas Capitalized Costs
|
Aggregate
capitalized costs related to oil and gas production activities with applicable
accumulated depreciation, depletion and amortization are presented
below:
|
June 30,
|
December 31,
|
|||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Proved
properties:
|
||||||||
|
Leasehold
acquisition
|
$ | 3,311,669 | $ | 3,095,400 | ||||
|
Development
|
271,374 | 254,251 | ||||||
|
Unproved
properties
|
100,994 | 156,908 | ||||||
|
Gas
compression plant and pipelines
|
86,429 | 112,182 | ||||||
| 3,770,466 | 3,618,741 | |||||||
|
Less
accumulated depletion, depreciation and amortization
|
(154,558 | ) | (127,265 | ) | ||||
| $ | 3,615,908 | $ | 3,491,476 | |||||
9
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
|
(7)
|
Business
and Credit Concentrations
|
For the
three and six months ended June 30, 2008, the Company’s four largest
customers represented approximately 20%, 11%, 10% and 10% and 20%, 11%, 11% and
10%, respectively, of the Company’s sales. For the three and six
months ended June 30, 2007, the Company’s four largest customers
represented approximately 40%, 24%, 13% and 12% and 34%, 23%, 14% and 12%,
respectively, of the Company’s sales.
At
June 30, 2008, two customers’ trade accounts receivable from oil, gas and
natural gas liquids (“NGL”) sales accounted for more than 10% of the Company’s
total trade accounts receivable. As of June 30, 2008, trade
accounts receivable from the Company’s two largest customers represented
approximately 16% and 11% of the Company’s receivables. At
December 31, 2007, three customers’ trade accounts receivable from oil, gas
and NGL sales accounted for more than 10% of the Company’s total trade accounts
receivable. As of December 31, 2007, trade accounts receivable
from the Company’s three largest customers represented approximately 22%, 13%
and 12% of the Company’s receivables.
|
(8)
|
Debt
|
At
June 30, 2008 and December 31, 2007, the Company had the following
debt outstanding:
|
June 30,
|
December 31,
|
|||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Credit
facility (1)
|
$ | 1,826,000 | $ | 1,443,000 | ||||
|
Term
loan (2)
|
156,398 | — | ||||||
|
Senior
notes, net (3)
|
250,000 | — | ||||||
|
Less
current maturities
|
— | — | ||||||
| $ | 2,232,398 | $ | 1,443,000 | |||||
|
|
(1)
|
Variable
rate of 4.21% at June 30, 2008 and 7.02% at December 31,
2007.
|
|
|
(2)
|
Variable
rate of 7.45% at June 30, 2008. This balance was repaid in
full on July 1, 2008.
|
|
|
(3)
|
Fixed
rate of 9.875%; net of unamortized discount of approximately $5.9 million
at June 30, 2008.
|
Credit
Facility
At
June 30, 2008, the Company had a $2.0 billion borrowing base under its
Third Amended and Restated Credit Agreement (“Credit Facility”) with a maturity
of August 2010. Effective July 1, 2008, in connection with the
sale of Appalachian Basin oil and gas properties, the borrowing base was
redetermined and decreased to $1.85 billion, all of which is
conforming.
The
borrowing base under the Credit Facility will be redetermined semi-annually by
the lenders in their sole discretion, based on, among other things, reserve
reports as prepared by reserve engineers taking into account the oil and gas
prices at such time. At the Company’s election, interest on
borrowings under the Credit Facility is determined by reference to either the
London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.00%
and 1.75% per annum or the alternate base rate (“ABR”) plus an applicable margin
between 0% and 0.25% per annum.
10
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
At
June 30, 2008, available borrowing under the Credit Facility was $170.3
million, which includes a $3.7 million reduction in availability for outstanding
letters of credit. On July 1, 2008, the Company repaid $357.6
million in indebtedness under its Credit Facility with a portion of the net
proceeds from the sale of properties in the Appalachian Basin (see
Note 2). Available borrowing under the Credit Facility was
$330.1 million at July 31, 2008 which includes a $6.5 million reduction in
availability for outstanding letters of credit.
Term
Loan
On
January 31, 2008, in order to fund a portion of the January 2008
acquisition of oil and gas properties in the Mid-Continent (see Note 3),
the Company entered into a $400.0 million Second Lien Term Loan Agreement (“Term
Loan”) maturing on July 31, 2009, secured by a second priority lien on all
oil and gas properties as well as a second priority pledge on all ownership
interests in its operating subsidiaries. Covenants under the Term
Loan are substantially similar to those under the Credit
Facility. Interest is determined by reference to LIBOR plus an
applicable margin of 5.0% for the first twelve months and 7.5% for the remaining
period until maturity or a domestic bank rate plus an applicable margin of 3.5%
for the first twelve months and 6.0% for the remaining period until
maturity.
On
June 30, 2008, the Company repaid $243.6 million in indebtedness under the
Term Loan with net proceeds from the Senior Notes (see below). On
July 1, 2008, the Company repaid the balance of the term loan of $156.4
million. Deferred financing fees associated with the Term Loan of
approximately $2.8 million were written off during the six months ended
June 30, 2008. Additionally, approximately $1.9 million in fees
were written off in July 2008.
Senior
Notes
On
June 24, 2008, the Company entered into a purchase agreement with a group
of initial purchasers (“Initial Purchasers”) pursuant to which the Company
agreed to issue $255.9 million in aggregate principal amount of the Company’s
senior notes due 2018 (“Senior Notes”). The Senior Notes were offered
and sold to the Initial Purchasers and then resold to qualified institutional
buyers each in transactions exempt from the registration requirements under the
Securities Act of 1933, as amended (“Securities Act”). The Company
used the net proceeds (after deducting the Initial Purchasers’ discounts and
offering expense) of approximately $243.6 million to repay loans outstanding
under the Company’s Term Loan (see above). In connection with the
Senior Notes, the Company incurred financing fees of approximately $7.3 million,
which will be amortized over the life of the Senior Notes and recorded in
interest expense. The $5.9 million discount on the Senior Notes will
be amortized over the life of the Senior Notes and recorded in interest
expense.
The
Senior Notes were issued under an Indenture dated June 27, 2008
(“Indenture”), mature on July 1, 2018 and bear interest at
9.875%. Interest is payable semi-annually beginning January 1,
2009. The Senior Notes are general unsecured senior obligations of
the Company and are effectively junior in right of payment to any secured
indebtedness of the Company to the extent of the collateral securing such
indebtedness. Each of the Company’s material subsidiaries guaranteed
the Senior Notes on a senior unsecured basis. The Indenture provides
that the Company may redeem 1) on or prior to July 1, 2011, up to 35%
of the aggregate principal amount of the Senior Notes at a redemption price of
109.875% of the principal amount, plus accrued and unpaid interest,
2) prior to July 1, 2013, all or part of the Senior Notes at a
redemption price equal to the principal amount, plus a make whole premium (as
defined in the Indenture) and accrued and unpaid interest, and 3) on or
after July 1, 2013, all or part of the Senior Notes at redemption prices
equal to 104.938% in 2013, 103.292% in 2014, 101.646% in 2015 and 100% in 2016
and thereafter. The Indenture also provides that, if a change of
control (as defined in the Indenture) occurs, the holders have a right to
require the Company to repurchase all or part of the Senior Notes at a
redemption price equal to 101%, plus accrued and unpaid
interest.
11
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
The
Senior Notes’ Indenture contains covenants that, among other things, limit the
Company’s ability to: (i) pay distributions on, purchase or redeem the
Company’s units or redeem its subordinated debt; (ii) make investments;
(iii) incur or guarantee additional indebtedness or issue certain types of
equity securities; (iv) create certain liens; (v) sell assets;
(vi) consolidate, merge or transfer all or substantially all of the
Company’s assets; (vii) enter into agreements that restrict distributions
or other payments from the Company’s restricted subsidiaries to the Company;
(viii) engage in transactions with affiliates; and (ix) create
unrestricted subsidiaries.
In
connection with the issuance and sale of the Senior Notes, the Company entered
into a Registration Rights Agreement (“Registration Rights Agreement”) with the
Initial Purchasers. Under the Registration Rights Agreement, the
Company agreed to use its reasonable best efforts to file with the SEC and cause
to become effective a registration statement relating to an offer to issue new
notes having terms substantially identical to the Senior Notes in exchange for
outstanding Senior Notes. In certain circumstances, the Company may
be required to file a shelf registration statement to cover resales of the
Senior Notes. The Company will not be obligated to file the
registration statements described above if the restrictive legend on the Senior
Notes has been removed and the Senior Notes are freely tradable (in each case,
other than with respect to persons that are affiliates of the Company) pursuant
to Rule 144 under the Securities Act, as of the 366th day after the Senior
Notes were issued. If the Company fails to satisfy its obligations
under the Registration Rights Agreement, the Company may be required to pay
additional interest to holders of the Senior Notes under certain
circumstances.
|
(9)
|
Derivatives
|
Commodity
Derivatives
The
Company sells oil, gas and NGL in the normal course of its business and utilizes
derivative instruments to minimize the variability in cash flows due to price
movements in oil, gas and NGL. The Company enters into derivative
instruments such as swap contracts, collars and put options to hedge a portion
of its forecasted oil, gas and NGL sales. Oil puts are also used to
hedge NGL sales. See Note 10 for additional disclosures about
oil and gas commodity derivatives as required by Statement of Financial
Accounting Standards No. 157, “Fair Value Measurements”
(“SFAS 157”).
12
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
The
following table summarizes open positions as of June 30, 2008 and
represents, as of such date, derivatives in place through December 31,
2014, on annual production volumes:
|
Year
2008
|
Year
2009
|
Year
2010
|
Year
2011
|
Year
2012
|
Year
2013
|
Year
2014
|
||||||||||||||||||||||
|
Gas
Positions:
|
||||||||||||||||||||||||||||
|
Fixed
Price Swaps:
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MMMBtu)
|
21,313 | 42,166 | 42,086 | 33,485 | 31,162 | — | — | |||||||||||||||||||||
|
Average
Price ($/MMBtu)
|
$ | 8.65 | $ | 8.51 | $ | 8.14 | $ | 8.22 | $ | 8.46 | $ | — | $ | — | ||||||||||||||
|
Puts:
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MMMBtu)
|
3,532 | 6,960 | 6,960 | 6,960 | — | — | — | |||||||||||||||||||||
|
Average
Price ($/MMBtu)
|
$ | 8.07 | $ | 7.50 | $ | 7.50 | $ | 7.50 | $ | — | $ | — | $ | — | ||||||||||||||
|
PEPL
Puts: (1)
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MMMBtu)
|
1,927 | 5,334 | 10,634 | 13,259 | 5,934 | — | — | |||||||||||||||||||||
|
Average
Price ($/MMBtu)
|
$ | 7.85 | $ | 7.85 | $ | 7.85 | $ | 7.85 | $ | 7.85 | $ | — | $ | — | ||||||||||||||
|
Total:
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MMMBtu)
|
26,772 | 54,460 | 59,680 | 53,704 | 37,096 | — | — | |||||||||||||||||||||
|
Average
Price ($/MMBtu)
|
$ | 8.52 | $ | 8.32 | $ | 8.02 | $ | 8.03 | $ | 8.36 | $ | — | $ | — | ||||||||||||||
|
Oil
Positions:
|
||||||||||||||||||||||||||||
|
Fixed
Price Swaps:
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
1,376 | 2,437 | 2,150 | 2,073 | 2,025 | 900 | — | |||||||||||||||||||||
|
Average
Price ($/Bbl)
|
$ | 82.11 | $ | 78.07 | $ | 78.28 | $ | 79.65 | $ | 77.65 | $ | 72.22 | $ | — | ||||||||||||||
|
Puts:
(2)
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
934 | 1,843 | 2,250 | 2,352 | 500 | — | — | |||||||||||||||||||||
|
Average
Price ($/Bbl)
|
$ | 73.34 | $ | 72.13 | $ | 70.56 | $ | 69.11 | $ | 77.73 | $ | — | $ | — | ||||||||||||||
|
Collars:
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
— | 250 | 250 | 276 | 348 | 1,375 | 2,200 | |||||||||||||||||||||
|
Average
Floor Price ($/Bbl)
|
$ | — | $ | 90.00 | $ | 90.00 | $ | 90.00 | $ | 90.00 | $ | 110.00 | $ | 110.00 | ||||||||||||||
|
Average
Ceiling Price ($/Bbl)
|
$ | — | $ | 114.25 | $ | 112.00 | $ | 112.25 | $ | 112.35 | $ | 152.00 | $ | 152.00 | ||||||||||||||
|
Total:
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
2,310 | 4,530 | 4,650 | 4,701 | 2,873 | 2,275 | 2,200 | |||||||||||||||||||||
|
Average
Price ($/Bbl)
|
$ | 78.57 | $ | 76.31 | $ | 75.17 | $ | 74.98 | $ | 79.16 | $ | 95.05 | $ | 110.00 | ||||||||||||||
|
Gas
Basis Differential Positions:
|
||||||||||||||||||||||||||||
|
PEPL
Basis Swaps: (3)
|
||||||||||||||||||||||||||||
|
Hedged
Volume (MMMBtu)
|
18,073 | 34,666 | 29,366 | 26,741 | 34,066 | — | — | |||||||||||||||||||||
|
Hedged
Differential ($/MMBtu)
|
$ | (0.95 | ) | $ | (0.95 | ) | $ | (0.95 | ) | $ | (0.95 | ) | $ | (0.95 | ) | $ | — | $ | — | |||||||||
|
|
(1)
|
Settle
on the Panhandle Eastern Pipeline (“PEPL”) spot price of gas to hedge
basis differential associated with gas production in the Mid-Continent
region.
|
|
|
(2)
|
The
Company utilizes oil puts to hedge revenues associated with its NGL
production.
|
|
|
(3)
|
Represents
a swap of the basis between the New York Mercantile Exchange (“NYMEX”) and
the PEPL spot price of gas of $(0.95) per MMBtu for the volumes
hedged.
|
Settled
derivatives on gas production for the three and six months ended June 30,
2008 included a volume of 10,045 MMMBtu and 25,158 MMMBtu at an average contract
price of $8.52 and $8.44, respectively. Settled derivatives on oil
and NGL production for the three and six months ended June 30, 2008
included a volume of 1,155 MBbls and 2,137 MBbls at an average contract price of
$78.57 and $77.31, respectively. The gas derivatives are settled
based on the closing NYMEX future price of gas or on the published PEPL spot
price of gas on the settlement date, which occurs on the third day preceding the
production month.
13
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
The oil
transactions are settled based on the average month’s daily NYMEX price of light
oil and settlement occurs on the final day of the production month.
By using
derivative instruments to hedge exposures to changes in commodity prices, the
Company exposes itself to credit risk and market risk. Credit risk is
the failure of the counterparty to perform under the terms of the derivative
contract. When the fair value of a derivative contract is positive,
the counterparty owes the Company, which creates credit risk. The
Company minimizes the credit risk in derivative instruments by entering into
transactions with credit-worthy counterparties.
Interest
Rate Swaps
The
Company has entered into interest rate swap agreements based on LIBOR to
minimize the effect of fluctuations in interest rates. If LIBOR is
lower than the fixed rate in the contract, the Company is required to pay the
counterparties the difference, and conversely, the counterparties are required
to pay the Company if LIBOR is higher than the fixed rate in the
contract. The Company did not designate the interest rate swap
agreements as cash flow hedges under SFAS No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended, (“SFAS 133”);
therefore, the changes in fair value of these instruments are recorded in
current earnings. See Note 10 for additional disclosures about
interest rate swaps as required by SFAS 157.
The
following presents the settlement terms of the interest rate swaps:
|
Year
|
Year |
Year
|
Year
|
|||||||||||||
|
2008
|
2009
|
2010
|
2011 (1)
|
|||||||||||||
|
(dollars
in thousands)
|
||||||||||||||||
|
Notional
Amount
|
$ | 1,212,000 | $ | 1,212,000 | $ | 1,212,000 | $ | 1,212,000 | ||||||||
|
Fixed
Rate
|
4.20 | % | 5.06 | % | 5.06 | % | 5.06 | % | ||||||||
|
|
(1)
|
Represents
interest rate swaps that settle in January
2011.
|
Outstanding
Notional Amounts
The
following presents the outstanding notional amounts and maximum number of months
outstanding of derivative instruments:
|
June 30,
|
December 31,
|
|||||||
|
2008
|
2007
|
|||||||
|
Outstanding
notional amounts of gas contracts (MMMBtu)
|
231,712 | 275,769 | ||||||
|
Maximum
number of months gas contracts outstanding
|
54 | 59 | ||||||
|
Outstanding
notional amounts of oil contracts (MBbls)
|
23,539 | 16,214 | ||||||
|
Maximum
number of months oil contracts outstanding
|
78 | 72 | ||||||
|
Outstanding
notional amount of interest rate swaps (in thousands)
|
$ | 1,212,000 | $ | 1,212,000 | ||||
|
Maximum
number of months interest rate swaps outstanding
|
30 | 36 | ||||||
14
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
Balance
Sheet Presentation
The
Company’s commodity derivatives and interest rate swap derivatives are presented
on a net basis in “derivative instruments” on the condensed consolidated balance
sheets. The following summarizes the fair value of derivatives
outstanding on a gross basis:
|
June 30,
|
December 31,
|
|||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Assets:
|
||||||||
|
Commodity
derivatives
|
$ | 134,603 | $ | 246,124 | ||||
|
Interest
rate swaps
|
— | 2,548 | ||||||
| $ | 134,603 | $ | 248,672 | |||||
|
Liabilities:
|
||||||||
|
Commodity
derivatives
|
$ | 1,195,440 | $ | 260,058 | ||||
|
Interest
rate swaps
|
32,055 | 32,475 | ||||||
| $ | 1,227,495 | $ | 292,533 | |||||
The
Company’s counterparties are participants in its Credit Facility (see
Note 8) which is secured by the Company’s oil and gas reserves; therefore,
the Company is not required to post any collateral. The
counterparties are large, international financial services institutions and
therefore the Company does not require collateral from the
counterparties. The maximum amount of loss due to credit risk, based
on the gross fair value of financial instruments that the Company would incur if
its counterparties failed completely to perform according to the terms of the
contracts was approximately $15.4 million at June 30, 2008. In
accordance with the Company’s standard practice, its commodity and interest rate
swap derivatives are subject to counterparty netting under master netting
agreements and therefore the risk of such loss is substantially mitigated at
June 30, 2008.
Gain
(Loss) on Derivatives
Gains and
losses on derivatives are reported on the condensed consolidated statements of
operations in “loss on oil and gas derivatives” and “gain (loss) on interest
rate swaps” and include realized and unrealized gains
(losses). Realized gains (losses), excluding canceled commodity
derivatives, represent amounts related to the settlement of derivative
instruments, and for commodity derivatives, are aligned with the underlying
production. Unrealized gains (losses) represent the change in fair
value of the
15
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
derivative
instruments and are non-cash items. The following presents the
Company’s reported gains and losses on derivative instruments:
|
Three
Months Ended
June 30,
|
Six
Months Ended
June 30,
|
|||||||||||||||
|
2008
|
2007
|
2008
|
2007
|
|||||||||||||
|
(in
thousands)
|
||||||||||||||||
|
Realized
gains (losses):
|
||||||||||||||||
|
Commodity
derivatives
|
$ | (29,210 | ) | $ | 6,200 | $ | (34,019 | ) | $ | 13,893 | ||||||
|
Canceled
commodity derivatives
|
(68,197 | ) | — | (68,197 | ) | — | ||||||||||
|
Interest
rate swaps
|
(4,221 | ) | — | (5,662 | ) | 82 | ||||||||||
| $ | (101,628 | ) | $ | 6,200 | $ | (107,878 | ) | $ | 13,975 | |||||||
|
Unrealized
gains (losses):
|
||||||||||||||||
|
Commodity
derivatives
|
$ | (773,397 | ) | $ | (23,907 | ) | $ | (1,037,382 | ) | $ | (92,041 | ) | ||||
|
Interest
rate swaps
|
35,825 | 274 | (2,127 | ) | 115 | |||||||||||
| $ | (737,572 | ) | $ | (23,633 | ) | $ | (1,039,509 | ) | $ | (91,926 | ) | |||||
|
Total
gains (losses):
|
||||||||||||||||
|
Commodity
derivatives
|
$ | (870,804 | ) | $ | (17,707 | ) | $ | (1,139,598 | ) | $ | (78,148 | ) | ||||
|
Interest
rate swaps
|
31,604 | 274 | (7,789 | ) | 197 | |||||||||||
| $ | (839,200 | ) | $ | (17,433 | ) | $ | (1,147,387 | ) | $ | (77,951 | ) | |||||
During
the three months ended June 30, 2008, the Company canceled (before the
contract settlement date) derivative contracts on estimated future gas
production resulting in a realized loss of $68.2 million. The future
gas production under the canceled contracts primarily related to properties in
the Appalachian Basin (see Note 2).
See
Note 18 for detail about commodity derivative contracts canceled and
entered into subsequent to June 30, 2008.
|
(10)
|
Fair
Value of Financial Instruments
|
The
Company accounts for its oil and gas commodity derivatives and interest rate
swaps at fair value (see Note 9) on a recurring basis. Effective
January 1, 2008, the Company adopted SFAS 157 for these financial
instruments. SFAS 157 defines fair value, establishes a
framework for measuring fair value, establishes a fair value hierarchy based on
the quality of inputs used to measure fair value, and enhances disclosure
requirements for fair value measurements. The impact of the adoption
of SFAS 157 to the Company’s results of operations was a decrease to net
loss by approximately $78.4 million and $88.0 million, or $0.69 per unit and
$0.77 per unit, for the three and six months ended June 30, 2008,
respectively, resulting from an assumed credit risk adjustment.
The fair
value of derivative instruments is determined utilizing pricing models for
significantly similar instruments. The models use a variety of
techniques to arrive at fair value, including quotes and pricing
analysis. Inputs to the pricing models include publicly available
prices and forward curves generated from a compilation of data gathered from
third parties.
Fair
Value Hierarchy
In
accordance with SFAS 157, the Company has categorized its financial
instruments, based on the priority of inputs to the valuation technique, into a
three-level fair value hierarchy. The fair value hierarchy gives the
highest priority to quoted prices in active markets for identical assets or
liabilities (Level 1) and the lowest priority to unobservable inputs
(Level 3).
16
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
Financial
assets and liabilities recorded on the condensed consolidated balance sheets are
categorized based on the inputs to the valuation techniques as
follows:
|
|
Level 1
|
Financial
assets and liabilities for which values are based on unadjusted quoted
prices for identical assets or liabilities in an active market that
management has the ability to
access.
|
|
|
Level 2
|
Financial
assets and liabilities for which values are based on quoted prices in
markets that are not active or model inputs that are observable either
directly or indirectly for substantially the full term of the asset or
liability (commodity derivatives and interest rate
swaps).
|
|
|
Level 3
|
Financial
assets and liabilities for which values are based on prices or valuation
techniques that require inputs that are both unobservable and significant
to the overall fair value measurement. These inputs reflect
management’s own assumptions about the assumptions a market participant
would use in pricing the asset or
liability.
|
As
required by SFAS 157, when the inputs used to measure fair value fall
within different levels of the hierarchy, the level within which the fair value
measurement is categorized is based on the lowest level input that is
significant to the fair value measurement in its entirety. The
Company conducts a review of fair value hierarchy classifications on a quarterly
basis. Changes in the observability of valuation inputs may result in
a reclassification for certain financial assets or liabilities.
The
following presents the Company’s fair value hierarchy for assets and liabilities
measured at fair value on a recurring basis at June 30,
2008. These items are included in “derivative instruments” on the
condensed consolidated balance sheet.
|
Fair
Value Measurements on a Recurring Basis
June 30,
2008
|
||||||||||||
|
Level
2
|
Netting (1)
|
Total
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Assets:
|
||||||||||||
|
Commodity
derivatives
|
$ | 134,603 | $ | (134,603 | ) | $ | — | |||||
|
Liabilities:
|
||||||||||||
|
Commodity
derivatives
|
$ | 1,195,440 | $ | (134,603 | ) | $ | 1,060,837 | |||||
|
Interest
rate swaps
|
$ | 32,055 | $ | — | $ | 32,055 | ||||||
|
|
(1)
|
Represents
counterparty netting under master netting
agreements.
|
|
(11)
|
Commitments
and Contingencies
|
From time
to time the Company is a party to various legal proceedings or is subject to
industry rulings that could bring rise to claims in the ordinary course of
business. The Company is not currently a party to any litigation or
pending claims that it believes would have a material adverse effect on its
business, financial position, results of operations or liquidity.
17
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
|
(12)
|
Earnings
Per Unit
|
Basic and
diluted earnings per unit are presented on the condensed consolidated statements
of operations. Basic units outstanding excludes the effect of average
anti-dilutive common stock equivalents related to unit options and warrants and
unvested restricted units of 2.6 million and 2.5 million for the three and six
months ended June 30, 2008, respectively. Basic units
outstanding excludes the effect of average anti-dilutive common stock
equivalents related to unit options and warrants and unvested restricted units
of 1.9 million and 1.9 million for the three and six months ended June 30,
2007, respectively. All equivalent units were anti-dilutive for the
three and six months ended June 30, 2008 and 2007, as the Company reported
a net loss from operations.
|
(13)
|
Unit-Based
Compensation
|
Employee
Grants
During
the six months ended June 30, 2008, the Company granted an aggregate
576,970 restricted units and 691,000 unit options to employees, primarily as
part of its annual review of employee compensation, with an aggregate fair value
of approximately $14.2 million. The majority of these restricted
units and options vest ratably over three years. In addition, during
the six months ended June 30, 2008, the Company granted 15,784 phantom
units to independent members of its Board of Directors with a fair value of
approximately $0.4 million. The phantom units vest over one
year. For the three and six months ended June 30, 2008, the
Company recorded unit-based compensation expense in continuing operations of
approximately $3.9 million and $7.5 million, respectively, as a non-cash charge
against income before income taxes and it is included in “operating expenses” or
“general and administrative expenses” on the condensed consolidated statements
of operations. For the three and six months ended June 30, 2007,
the Company recorded unit-based compensation and unit warrant expense in
continuing operations of approximately $3.9 million and $7.5 million,
respectively.
|
(14)
|
Income
Taxes
|
The
Company is a limited liability company treated as a partnership for federal and
state income tax purposes with all income tax liabilities and/or benefits of the
Company being passed through to the unitholders, with the exception of the state
of Texas. As such, no recognition of federal income taxes for the
Company or its subsidiaries that are organized as limited liability companies
have been provided for in the accompanying financial
statements. Limited liability companies are subject to state income
taxes in Texas. In addition, certain of the Company’s subsidiaries
are Subchapter C-corporations subject to federal and state income
taxes.
|
(15)
|
Related
Party Transactions
|
Lehman
Brothers Holdings, Inc.
At
June 30, 2008, on an aggregate basis, a group of certain direct or indirect
wholly owned subsidiaries of Lehman Brothers Holdings, Inc. (“Lehman”) owned
over 10% of the Company’s outstanding units. As such, Lehman is
considered a related party under the provisions of SFAS No. 57 “Related Party Disclosures.”
Lehman subsidiaries provide certain services to the Company, including
participation in the Company’s Credit Facility, Term Loan, offering of Senior
Notes (see Note 8), sale of Appalachian Basin assets (see Note 2) and
sale of commodity derivative instruments (see Note 9), which were all
consummated on terms equivalent to those that prevail in arm’s-length
transactions.
During
the three and six months ended June 30, 2008, the Company paid Lehman
interest on borrowings of approximately $1.0 million and $2.2 million,
respectively, and financing fees of approximately $1.3 million and $1.8 million,
respectively. During the three and six months ended June 30,
2007, the Company paid
18
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
Lehman
interest on borrowings of approximately $0.4 million and $0.7 million,
respectively, and financing fees of zero and approximately $13,000,
respectively.
During
the three and six months ended June 30, 2007, in conjunction with its June
2007, $260.0 million and February 2007, $360.0 million private placements of
units, the Company paid Lehman underwriting fees of approximately $1.4 million
and $3.5 million, respectively. Lehman was a participant in the
private placements and the Company received $68.7 million and $118.7 million,
respectively, of proceeds from Lehman in relation to these transactions during
the three and six months ended June 30, 2007.
During
the three and six months ended June 30, 2008, the Company paid
distributions on units to Lehman of approximately $9.3 million and $18.5
million, respectively. During the three and six months ended
June 30, 2007, the Company paid distributions on units to Lehman of
approximately $2.2 million and $3.3 million, respectively. During the
three and six months ended June 30, 2008, the Company paid Lehman
approximately $18.0 million and $18.8 million, respectively, on settled
commodity derivative contracts. During the three and six months ended
June 30, 2007, Lehman paid the Company approximately $0.5 million and $1.0
million, respectively, on settled commodity derivative contracts. In
addition, during the six months ended June 30, 2008, the Company purchased
approximately $1.3 million of deal contingent oil swap contracts from
Lehman.
The
following sets forth the amounts due to or from Lehman as of the respective
balance sheet dates included in the accompanying condensed consolidated
financial statements:
|
June 30,
|
December 31,
|
|||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Assets:
|
||||||||
|
Current
oil and gas derivative assets
|
$ | — | $ | 14,226 | ||||
|
Liabilities:
|
||||||||
|
Accrued
interest payable
|
$ | 143 | $ | 162 | ||||
|
Current
oil and gas derivative liabilities
|
$ | 241,931 | $ | — | ||||
|
Other
current liabilities
|
$ | — | $ | 1,278 | ||||
|
Long-term
debt
|
$ | 57,000 | $ | 40,404 | ||||
|
Noncurrent
oil and gas derivative liabilities
|
$ | 421,753 | $ | 7,028 | ||||
Other
Eric P.
Linn, brother of the Company’s Chairman and Chief Executive Officer, served as
President of one of the Company’s wholly owned
subsidiaries. Effective March 31, 2008, Mr. Linn’s employment
with the Company terminated and he executed a Severance Agreement and
Release. Under the terms of that agreement, Mr. Linn will
receive $0.2 million in cash, six months of outplacement services, accelerated
vesting of certain unvested restricted units and unvested options, and payment
of COBRA coverage until December 31, 2008 or until obtainment of other
comparable health care benefits.
19
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
|
(16)
|
Supplemental
Disclosures to the Consolidated Statements of Cash
Flows
|
|
Six
Months Ended
June 30,
|
||||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Supplemental
disclosure of cash flow information:
|
||||||||
|
Cash
payments for interest
|
$ | 60,662 | $ | 19,656 | ||||
|
Supplemental
disclosure of non-cash investing activities:
|
||||||||
|
In
connection with the purchase of oil and gas properties,
liabilities were assumed as follows:
|
||||||||
|
Fair
value of assets acquired
|
$ | 581,780 | $ | 545,789 | ||||
|
Cash
paid
|
(573,030 | ) | (539,304 | ) | ||||
|
Liabilities
assumed, net
|
$ | 8,750 | $ | 6,485 | ||||
|
Supplemental
disclosure of non-cash financing activities:
|
||||||||
|
Units
issued in connection with the purchase of oil and gas
properties
|
$ | 23,455 | $ | — | ||||
For
purposes of the statement of cash flows, the Company considers all highly liquid
short-term investments with original maturities of three months or less to be
cash equivalents. Restricted cash of $0.9 million and $0.5 million is
included in “other noncurrent assets” on the condensed consolidated balance
sheets at June 30, 2008 and December 31, 2007, respectively, and
represents cash the Company has deposited into a separate account and designated
for asset retirement obligations in accordance with contractual
agreements.
The
Company manages its working capital and cash requirements to borrow only as
needed from its Credit Facility. At December 31, 2007, the
Company had approximately $5.2 million of outstanding checks, the balance of
which is included in “other current liabilities” on the condensed consolidated
balance sheet.
|
(17)
|
Recently
Issued Accounting Standards
|
In April
2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff
Position (“FSP”) FAS 142-3, “Determination of the Useful Life of
Intangible Assets,” which amends the factors that should be considered in
developing renewal or extension assumptions used to determine the useful life of
a recognized intangible asset. The intent of this FSP is to improve
the consistency between the useful life of a recognized intangible asset and the
period of expected cash flows used to measure the fair value of the
asset. This FSP is effective for financial statements issued for
fiscal years beginning after December 15, 2008. The Company is
currently evaluating the impact the provisions of this FSP will have on its
results of operations and financial position, but does not expect it will be
material.
In March
2008, the FASB issued Statement of Financial Accounting Standards No. 161,
“Disclosures about Derivative
Instruments and Hedging Activities - an Amendment of FASB Statement 133”
(“SFAS 161”). SFAS 161 requires
expanded disclosure regarding derivatives and hedging activities including
disclosure of the fair values of derivative instruments and their gains and
losses in tabular form. SFAS 161 is effective for fiscal years
and interim periods beginning after November 15, 2008, with early adoption
encouraged. The Company adopted SFAS 161 effective
January 1, 2008 (see Note 9). The adoption of the requirements
of SFAS 161, which solely expanded disclosures, had no effect on the
Company’s results of operations or financial position.
In
February 2008, the FASB issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement
No. 157,” which defers the effective date of SFAS 157 for one
year for certain nonfinancial assets and nonfinancial liabilities, except those
that are recognized or disclosed at fair value in the financial
statements
20
LINN
ENERGY, LLC
NOTES
TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Continued
(Unaudited)
on a
recurring basis. On January 1, 2008, the Company adopted the
provisions of SFAS 157 related to financial assets and liabilities and to
nonfinancial assets and liabilities measured at fair value on a recurring basis
(see Note 10). On January 1, 2009, the Company will adopt
the provisions for nonfinancial assets and nonfinancial liabilities that are not
required or permitted to be measured at fair value on a recurring basis, which
include those measured at fair value in goodwill impairment testing,
indefinite-lived intangible assets measured at fair value for impairment
assessment, nonfinancial long-lived assets measured at fair value for impairment
assessment, asset retirement obligations initially measured at fair value, and
those initially measured at fair value in a business combination. The
Company is currently evaluating the impact the provisions of SFAS 157
related to these items will have on its results of operations and financial
position.
|
(18)
|
Subsequent
Events
|
In the
third quarter of 2008, the Company canceled (before the contract settlement
date) swap contracts on estimated future gas production resulting in a realized
loss of $13.2 million. The swap contracts were canceled as a result
of the pending sale of the Verden assets (see Note 2).
In
addition, in the third quarter of 2008, the Company made several changes to its
commodity derivative portfolio, comprised of the following:
Oil
Swap Restructuring
The
Company took advantage of the relative strength of crude oil prices in 2013 and
2014 by reallocating swap value from those years and canceling in-the-money
collars to raise swap prices in years 2009 through 2012.
Oil
Put Strike Increase
The
Company also took advantage of the increase in crude oil prices by locking in
these gains in the form of put strike increases. The Company
increased the weighted average put strike price from $72.13 to $120.00 per
barrel in 2009 and from $70.56 to $110.00 per barrel in 2010 for a total cost of
$60.6 million.
21
The
following discussion and analysis should be read in conjunction with the
financial statements and related notes included elsewhere in this Quarterly
Report on Form 10-Q. A reference to a “Note” herein refers to
the accompanying Notes to Condensed Consolidated Financial Statements contained
in Item 1. “Financial Statements.”
Executive
Summary
Linn
Energy is an independent oil and gas company focused on the development and
acquisition of long life properties which complement its asset profile in
producing basins within the United States. From its initial public offering
in January 2006 through the date of this report (excluding the Appalachian Basin
properties sold in July 2008 discussed below), the Company has completed ten
acquisitions of working and royalty interests in oil and gas properties and
related gathering and pipeline assets. Total acquired proved reserves
were approximately 1.7 Tcfe at an acquisition cost of approximately $2.15 per
Mcfe. See Note 3 for details about the Company’s recent
acquisitions. The Company finances acquisitions with a combination of
proceeds from the issuance of its units, bank borrowings and cash flow from
operations.
On
July 1, 2008, the Company completed the sale of its interests in oil and
gas properties located in the Appalachian Basin to XTO for a contract price of
$600.0 million, subject to closing adjustments (see Note 2). The
Company received a cash down payment of $60.0 million in April 2008 which is
included in “other current liabilities” on the condensed consolidated balance
sheet at June 30, 2008. The Company used the net proceeds from
the sale of $560.0 million to repay loans outstanding under its Term Loan and
reduce indebtedness under its Credit Facility (see Note 8). The
assets include approximately 197 Bcfe of proved reserves at December 31,
2007. The carrying value of net assets sold was approximately $405.0
million, resulting in a gain on the sale of approximately $155.0 million, which
will be recorded in discontinued operations during the third quarter of
2008. The gain is subject to normal post-closing
adjustments.
In March
2008, the Company exited the drilling and service business in the Appalachian
Basin provided by its wholly owned subsidiary Mid Atlantic. At
June 30, 2008, substantially all of the property and equipment previously
held by Mid Atlantic totaling approximately $9.2 million had been
sold. During the six months ended June 30, 2008, the Company
recorded a loss on the sale of the Mid Atlantic assets of approximately $1.3
million, which is recorded in “income from discontinued operations, net of
taxes” on the condensed consolidated statement of operations.
The
results of the Company’s Appalachian Basin and Mid Atlantic operations are
classified as discontinued operations for all periods
presented. Unless otherwise indicated, results of operations
information presented herein relates only to Linn Energy’s continuing
operations.
Second
quarter 2008 results from continuing operations included the
following:
|
|
·
|
oil,
gas and NGL sales of approximately $255.6 million, compared to $32.5
million in the second quarter of
2007;
|
|
|
·
|
daily
production of 223.6 MMcfe/d, compared to 45.8 MMcfe/d in the second
quarter of 2007; and
|
|
|
·
|
lease
operating expenses of $1.44 per Mcfe, compared to $1.72 per Mcfe in the
second quarter of 2007.
|
In
addition, on June 3, 2008, the Company entered into an agreement to sell
certain of its assets in the Verden area in Oklahoma to Laredo for a contract
price of $185.0 million, subject to closing adjustments. The Company
plans to use net proceeds from the sale to reduce indebtedness. The
Company anticipates closing in the third quarter of 2008, subject to closing
conditions. There can be no assurance that all of the conditions to
closing will be satisfied. The assets include approximately 50,000
net acres and 45 Bcfe of proved reserves at December 31,
2007. The carrying value of net assets to be sold was approximately
$143.0 million. In the third quarter of 2008, the Company canceled
(before the contract settlement date) swap contracts on estimated future gas
production resulting in a realized loss of $13.2 million. The swap
contracts were canceled as a result of the pending sale of the Verden assets
(see Note 2).
22
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
In
addition, in the third quarter of 2008, the Company made several changes to its
commodity derivative portfolio, comprised of the following:
Oil
Swap Restructuring
The
Company took advantage of the relative strength of crude oil prices in 2013 and
2014 by reallocating swap value from those years and canceling in-the-money
collars to raise swap prices in years 2009 through 2012 as detailed in the table
below.
|
Year
2009
|
Year
2010
|
Year
2011
|
Year
2012
|
Year
2013
|
Year
2014
|
|||||||||||||||||||
|
Fixed
Price Oil Swaps:
|
||||||||||||||||||||||||
|
Before
Restructuring:
|
||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
2,437 | 2,150 | 2,073 | 2,025 | 900 | — | ||||||||||||||||||
|
Average
Price ($/Bbl)
|
$ | 78.07 | $ | 78.28 | $ | 79.65 | $ | 77.65 | $ | 72.22 | $ | — | ||||||||||||
|
After
Restructuring:
|
||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
2,437 | 2,150 | 2,073 | 2,025 | 2,275 | 2,200 | ||||||||||||||||||
|
Average
Price ($/Bbl)
|
$ | 90.00 | $ | 90.00 | $ | 84.22 | $ | 84.22 | $ | 84.22 | $ | 84.22 | ||||||||||||
|
Year
2013
|
Year
2014
|
|||||||||||||||||||||||
|
Oil
Collars:
|
||||||||||||||||||||||||
|
Before
Restructuring:
|
||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
1,375 | 2,200 | ||||||||||||||||||||||
|
Average
Floor Price ($/Bbl)
|
$ | 110.00 | $ | 110.00 | ||||||||||||||||||||
|
Average
Ceiling Price ($/Bbl)
|
$ | 152.00 | $ | 152.00 | ||||||||||||||||||||
|
After
Restructuring:
|
||||||||||||||||||||||||
|
Hedged
Volume (MBbls)
|
— | — | ||||||||||||||||||||||
|
Average
Floor Price ($/Bbl)
|
$ | — | $ | — | ||||||||||||||||||||
|
Average
Ceiling Price ($/Bbl)
|
$ | — | $ | — | ||||||||||||||||||||
Oil
Put Strike Increase
The
Company also took advantage of the increase in crude oil prices by locking in
these gains in the form of put strike increases. The Company
increased the weighted average put strike price from $72.13 to $120.00 per
barrel in 2009 and from $70.56 to $110.00 per barrel in 2010 for a total cost of
$60.6 million.
23
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Results
of Operations – Continuing Operations
Three
Months Ended June 30, 2008 Compared to Three Months Ended June 30,
2007
|
Three
Months Ended June 30,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues:
|
||||||||||||
|
Gas
sales
|
$ | 118,331 | $ | 9,232 | $ | 109,099 | ||||||
|
Oil
sales
|
97,745 | 12,824 | 84,921 | |||||||||
|
NGL
sales
|
39,510 | 10,439 | 29,071 | |||||||||
|
Total
oil, gas and NGL sales
|
255,586 | 32,495 | 223,091 | |||||||||
|
Loss
on oil and gas derivatives (1)
|
(870,804 | ) | (17,707 | ) | (853,097 | ) | ||||||
|
Natural
gas marketing revenues
|
3,593 | 2,740 | 853 | |||||||||
|
Other
revenues
|
642 | 487 | 155 | |||||||||
|
Total
revenues
|
$ | (610,983 | ) | $ | 18,015 | $ | (628,998 | ) | ||||
|
Expenses:
|
||||||||||||
|
Operating
expenses:
|
||||||||||||
|
Lease
operating and other
|
$ | 29,321 | $ | 7,156 | $ | 22,165 | ||||||
|
Production
and ad valorem taxes
|
17,320 | 2,587 | 14,733 | |||||||||
|
Natural
gas marketing expenses
|
3,260 | 2,323 | 937 | |||||||||
|
General
and administrative expenses (2)
|
18,171 | 11,887 | 6,284 | |||||||||
|
Data
license expenses
|
47 | — | 47 | |||||||||
|
Depreciation,
depletion and amortization
|
50,402 | 6,736 | 43,666 | |||||||||
|
Total
expenses
|
$ | 118,521 | $ | 30,689 | $ | 87,832 | ||||||
|
Other
income and (expenses)
|
$ | 3,959 | $ | (4,211 | ) | $ | 8,170 | |||||
Notes
to table:
|
(1)
|
During
the three months ended June 30, 2008, the Company canceled (before
the contract settlement date) derivative contracts on estimated future gas
production primarily associated with properties in the Appalachian Basin
(see Note 2) resulting in a realized loss of approximately $68.2
million.
|
|
(2)
|
The
measure for the three months ended June 30, 2008 and 2007 includes
approximately $3.8 million and $3.9 million, respectively, of non-cash
unit-based compensation and unit warrant
expenses.
|
24
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
|
Three
Months Ended June 30,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
Average daily production
– continuing
operations:
|
||||||||||||
|
Gas
(MMcf/d)
|
130.6 | 16.4 | 696.3 | % | ||||||||
|
Oil
(MBbls/d)
|
9.3 | 2.7 | 244.4 | % | ||||||||
|
NGL
(MBbls/d)
|
6.2 | 2.2 | 181.8 | % | ||||||||
|
Total
(MMcfe/d)
|
223.6 | 45.8 | 388.2 | % | ||||||||
|
Average daily production
– discontinued
operations:
|
||||||||||||
|
Total
(MMcfe/d)
|
24.0 | 22.8 | 5.3 | % | ||||||||
|
Weighted average prices
(hedged): (1)
|
||||||||||||
|
Gas
(Mcf)
|
$ | 9.92 | $ | 8.89 | 11.6 | % | ||||||
|
Oil
(Bbl)
|
$ | 81.10 | $ | 60.71 | 33.6 | % | ||||||
|
NGL
(Bbl)
|
$ | 70.55 | $ | 52.63 | 34.0 | % | ||||||
|
Weighted average prices
(unhedged): (2)
|
||||||||||||
|
Gas
(Mcf)
|
$ | 9.96 | $ | 6.16 | 61.7 | % | ||||||
|
Oil
(Bbl)
|
$ | 114.99 | $ | 52.99 | 117.0 | % | ||||||
|
NGL
(Bbl)
|
$ | 70.55 | $ | 51.42 | 37.2 | % | ||||||
|
Representative
NYMEX oil and gas prices:
|
||||||||||||
|
Gas
(MMBtu)
|
$ | 10.94 | $ | 7.55 | 44.9 | % | ||||||
|
Oil
(Bbl)
|
$ | 123.98 | $ | 65.03 | 90.7 | % | ||||||
|
Costs
per Mcfe of production:
|
||||||||||||
|
Operating
expenses:
|
||||||||||||
|
Lease
operating and other
|
$ | 1.44 | $ | 1.72 | (16.3 | )% | ||||||
|
Production
and ad valorem taxes
|
$ | 0.85 | $ | 0.62 | 37.1 | % | ||||||
|
General
and administrative expenses (3)
|
$ | 0.89 | $ | 2.85 | (68.8 | )% | ||||||
|
Depreciation,
depletion and amortization
|
$ | 2.48 | $ | 1.62 | 53.1 | % | ||||||
Notes
to table:
|
(1)
|
Includes
the effect of realized gains (losses) of $(29.2) million (excluding the
$68.2 million loss noted on the prior page) and $6.2 million on
derivatives for the three months ended June 30, 2008 and 2007,
respectively.
|
|
(2)
|
Does
not include the effect of realized gains (losses) on
derivatives.
|
|
(3)
|
The
measure for the three months ended June 30, 2008 and 2007 includes
approximately $3.8 million and $3.9 million, respectively, of non-cash
unit-based compensation and unit warrant expenses. Excluding
these amounts, general and administrative expenses for the three months
ended June 30, 2008 and 2007 were $0.70 per Mcfe and $1.93 per Mcfe,
respectively. This is a non-GAAP measure used by Company
management to analyze its
performance.
|
25
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Revenues
Gas, oil
and NGL sales increased by approximately $223.1 million, or 686%, to
approximately $255.6 million for the three months ended June 30, 2008, from
$32.5 million for the three months ended June 30, 2007.
The
increase in gas, oil and NGL revenues was primarily attributable to increased
production as a result of acquisitions and, to a lesser extent,
drilling. Total production increased to 223.6 MMcfe/d during the
three months ended June 30, 2008, from 45.8 MMcfe/d during the three months
ended June 30, 2007. The increase in production was due
primarily to production from the Mid-Continent III oil and gas properties
acquired in August 2007 (see Note 3). In addition, the Company
drilled 70 wells during the three months ended June 30, 2008, compared to
42 wells during the same period of 2007. (These well counts exclude
20 and 30 wells drilled in the Appalachian Basin during the three months ended
June 30, 2008 and 2007, respectively, as they were related to discontinued
operations.) Volume increases during the three months ended
June 30, 2008 increased total gas, oil and NGL revenues by $114.6 million
compared to the same period of 2007.
Gas
production increased to 130.6 MMcf/d during the three months ended June 30,
2008, from 16.4 MMcf/d during the three months ended June 30, 2007,
primarily due to the 2007 and 2008 acquisitions in the Mid-Continent region (see
Note 3). The increase in the weighted average price of gas for
the period, to $9.96 per Mcf, from $6.16 per Mcf, contributed approximately
$45.1 million to the increase in gas revenues.
Oil
production increased to 9.3 MBbls/d during the three months ended June 30,
2008, from 2.7 MBbls/d during the three months ended June 30, 2007, due to
acquisitions in the Mid-Continent region and the drilling of new wells in the
Company’s Western region. Acquisitions also increased NGL production
to 6.2 MBbls/d during the three months ended June 30, 2008, from 2.2
MBbls/d during the comparative period of the prior year. The increase
in the weighted average price of oil for the period, to $114.99 per Bbl, from
$52.99 per Bbl, contributed approximately $52.7 million to the increase in oil
revenues. The increase in the weighted average price of NGL for the
period, to $70.55 per Bbl, from $51.42 per Bbl, contributed approximately $10.7
million to the increase in NGL revenues.
Commodity
Derivative Activities
The
Company determines the fair value of its oil and gas derivatives using pricing
models that use a variety of techniques to arrive at fair value, including
quotes and pricing analysis. See Note 9 and Note 10 for
additional information. During the three months ended June 30,
2008, the Company had commodity derivative contracts for approximately 85% of
its gas production and 82% of its oil and NGL production, which resulted in
realized losses of $97.4 million (including realized losses on canceled
contracts of approximately $68.2 million). During the three months
ended June 30, 2008, the Company canceled (before the contract settlement
date) derivative contracts on estimated future gas production primarily
associated with properties in the Appalachian Basin (see Note
2). During the three months ended June 30, 2007, the Company
recorded realized gains of $6.2 million. Unrealized gains and losses
result from changes in market valuations of derivatives as future commodity
price expectations change compared to the contract prices on the
derivatives. During the second quarters of 2008 and 2007, expected
future oil and gas prices increased, which resulted in unrealized losses on
derivatives of $773.4 million and $23.9 million for the three months ended
June 30, 2008 and 2007, respectively. Such market value
adjustments, if realized in the future, would be offset by higher actual prices
for production. See Note 9 for details regarding derivatives in
place through December 31, 2014.
Expenses
Lease
operating and other expenses include expenses such as labor, field office,
vehicle, supervision, transportation, maintenance, tools and
supplies. As noted below, total lease operating expenses increased;
however, lease operating expenses per equivalent unit of production (excluding
production and ad valorem taxes) decreased to $1.44 per Mcfe for the three
months ended June 30, 2008, compared to $1.72 per Mcfe for the three months
ended June 30, 2007, due to acquired properties providing cost efficiencies
and economies of scale.
Lease
operating and other expenses increased by approximately $22.2 million, or 308%,
to $29.3 million for the three months ended June 30, 2008, from $7.2
million for the three months ended June 30, 2007. Operating
expenses increased primarily due to higher production and costs associated with
the 2007 and 2008 acquisitions in the Mid-Continent region, including expenses
associated with the addition of approximately 150 field and direct field support
employees in the third quarter of 2007.
26
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Production
and ad valorem taxes were approximately 7% and 8% of total sales for the three
months ended June 30, 2008 and 2007, respectively. Production
and ad valorem taxes increased by approximately $14.7 million, to $17.3 million
for the three months ended June 30, 2008, from $2.6 million for the three
months ended June 30, 2007. Production taxes, which are a
function of revenues generated from production, increased by approximately $13.2
million compared to the same period of 2007. Ad valorem taxes, which
are based on the value of reserves and production equipment and vary by
location, increased by approximately $1.5 million compared to the three months
ended June 30, 2007.
General
and administrative expenses are costs not directly associated with field
operations and include costs of employees and executive officers, related
benefits, office leases and professional fees. As noted below, total
general and administrative expenses increased; however, expenses per equivalent
unit of production decreased to $0.89 per Mcfe for the three months ended
June 30, 2008, compared to $2.85 per Mcfe for the three months ended
June 30, 2007, due to increases in production, cost efficiencies and
economies of scale provided by acquired properties.
General
and administrative expenses increased by approximately $6.3 million, or 53%, to
$18.2 million for the three months ended June 30, 2008, from $11.9 million
for the three months ended June 30, 2007. The increase in
general and administrative expenses over the second quarter of 2007 was
primarily due to costs incurred to support the Company’s increased size and
infrastructure growth, including the addition of a regional operating office in
Oklahoma. Salaries and benefits expense increased approximately $4.3
million during the three months ended June 30, 2008 and includes costs
associated with approximately 150 support employees added in the third quarter
of 2007. Information technology costs, such as software, data
administration and data conversion costs increased by approximately $1.3 million
compared to the same period of 2007.
Depreciation,
depletion and amortization increased by approximately $43.7 million, to $50.4
million for the three months ended June 30, 2008, from $6.7 million for the
three months ended June 30, 2007. Higher total production
levels, primarily due to the Company’s acquisitions in the Mid-Continent in 2008
and 2007, were the primary reason for the increase.
Other
income and (expenses) aggregated to income of approximately $4.0 million for the
three months ended June 30, 2008, compared to expense of $4.2 million for
the three months ended June 30, 2007, primarily due to an increase in total
gains on interest rate swaps of approximately $31.3 million over the prior
year. The Company’s interest rate swaps were not designated as cash
flow hedges under SFAS 133, even though they reduce exposure to changes in
interest rates (see Note 9). Therefore, the changes in fair
values of these instruments were recorded as unrealized gains of approximately
$35.8 million and $0.3 million for the three months ended June 30, 2008 and
2007, respectively. These amounts are non-cash items. The
increase in gains on interest rate swaps was partially offset by an increase in
interest expense of approximately $18.7 million related to increased debt levels
associated with borrowings to fund acquisitions and
drilling. Additionally, the Company wrote-off deferred financing fees
of approximately $3.4 million during the three months ended June 30, 2008
associated with its Term Loan (see Note 8).
Income
tax was a benefit of approximately $0.2 million and an expense of $0.2 million
for the three months ended June 30, 2008 and 2007,
respectively. The Company is a limited liability company treated as a
partnership for federal and state income tax purposes. Limited
liability companies are subject to state income taxes in
Texas. Certain of the Company’s subsidiaries are
Subchapter C-corporations subject to federal and state income
taxes.
27
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Results
of Operations – Continuing Operations
Six
Months Ended June 30, 2008 Compared to Six Months Ended June 30,
2007
|
Six
Months Ended
June 30,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Revenues:
|
||||||||||||
|
Gas
sales
|
$ | 203,759 | $ | 17,328 | $ | 186,431 | ||||||
|
Oil
sales
|
162,052 | 22,209 | 139,843 | |||||||||
|
NGL
sales
|
65,647 | 16,525 | 49,122 | |||||||||
|
Total
oil, gas and NGL sales
|
431,458 | 56,062 | 375,396 | |||||||||
|
Loss
on oil and gas derivatives (1)
|
(1,139,598 | ) | (78,148 | ) | (1,061,450 | ) | ||||||
|
Natural
gas marketing revenues
|
6,409 | 4,661 | 1,748 | |||||||||
|
Other
revenues
|
1,121 | 1,132 | (11 | ) | ||||||||
|
Total
revenues
|
$ | (700,610 | ) | $ | (16,293 | ) | $ | (684,317 | ) | |||
|
Expenses:
|
||||||||||||
|
Operating
expenses:
|
||||||||||||
|
Lease
operating and other
|
$ | 52,620 | $ | 13,304 | $ | 39,316 | ||||||
|
Production
and ad valorem taxes
|
30,142 | 4,305 | 25,837 | |||||||||
|
Natural
gas marketing expenses
|
5,677 | 3,975 | 1,702 | |||||||||
|
General
and administrative expenses (2)
|
37,398 | 22,193 | 15,205 | |||||||||
|
Data
license expenses
|
2,475 | — | 2,475 | |||||||||
|
Depreciation,
depletion and amortization
|
94,483 | 12,470 | 82,013 | |||||||||
|
Total
expenses
|
$ | 222,795 | $ | 56,247 | $ | 166,548 | ||||||
|
Other
income and (expenses)
|
$ | (60,890 | ) | $ | (8,915 | ) | $ | (51,975 | ) | |||
Notes
to table:
|
(1)
|
During
the six months ended June 30, 2008, the Company canceled (before the
contract settlement date) derivative contracts on estimated future gas
production primarily associated with properties in the Appalachian Basin
(see Note 2) resulting in a realized loss of approximately $68.2
million.
|
|
(2)
|
The
measure for the six months ended June 30, 2008 and 2007 includes
approximately $7.4 million and $7.5 million, respectively, of non-cash
unit-based compensation and unit warrant
expenses.
|
28
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
|
Six
Months Ended
June 30,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
Average daily production
– continuing
operations:
|
||||||||||||
|
Gas
(MMcf/d)
|
126.1 | 15.2 | 729.6 | % | ||||||||
|
Oil
(MBbls/d)
|
8.6 | 2.5 | 244.0 | % | ||||||||
|
NGL
(MBbls/d)
|
5.3 | 1.8 | 194.4 | % | ||||||||
|
Total
(MMcfe/d)
|
209.5 | 41.0 | 411.0 | % | ||||||||
|
Average daily production
– discontinued
operations:
|
||||||||||||
|
Total
(MMcfe/d)
|
24.4 | 23.4 | 4.3 | % | ||||||||
|
Weighted average prices
(hedged): (1)
|
||||||||||||
|
Gas
(Mcf)
|
$ | 9.10 | $ | 9.13 | (0.3 | )% | ||||||
|
Oil
(Bbl) (4)
|
$ | 78.37 | $ | 60.29 | 30.0 | % | ||||||
|
NGL
(Bbl)
|
$ | 68.60 | $ | 53.81 | 27.5 | % | ||||||
|
Weighted average prices
(unhedged): (2)
|
||||||||||||
|
Gas
(Mcf)
|
$ | 8.85 | $ | 6.33 | 39.8 | % | ||||||
|
Oil
(Bbl)
|
$ | 103.88 | $ | 49.24 | 111.0 | % | ||||||
|
NGL
(Bbl)
|
$ | 68.60 | $ | 50.08 | 37.0 | % | ||||||
|
Representative
NYMEX oil and gas prices:
|
||||||||||||
|
Gas
(MMBtu)
|
$ | 9.49 | $ | 7.16 | 32.5 | % | ||||||
|
Oil
(Bbl)
|
$ | 110.94 | $ | 61.65 | 80.0 | % | ||||||
|
Costs
per Mcfe of production:
|
||||||||||||
|
Operating
expenses:
|
||||||||||||
|
Lease
operating and other
|
$ | 1.38 | $ | 1.79 | (22.9 | )% | ||||||
|
Production
and ad valorem taxes
|
$ | 0.79 | $ | 0.58 | 36.2 | % | ||||||
|
General
and administrative expenses (3)
|
$ | 0.98 | $ | 2.99 | (67.2 | )% | ||||||
|
Depreciation,
depletion and amortization
|
$ | 2.48 | $ | 1.68 | 47.6 | % | ||||||
Notes
to table:
|
(1)
|
Includes
the effect of realized gains (losses) of $(34.0) million (excluding the
$68.2 million loss noted on the prior page) and $13.9 million on
derivatives for the six months ended June 30, 2008 and 2007,
respectively.
|
|
(2)
|
Does
not include the effect of realized gains (losses) on
derivatives.
|
|
(3)
|
The
measure for the six months ended June 30, 2008 and 2007 includes
approximately $7.4 million and $7.5 million, respectively, of non-cash
unit-based compensation and unit warrant expenses. Excluding
these amounts, general and administrative expenses for the six months
ended June 30, 2008 and 2007 were $0.79 per Mcfe and $1.98 per Mcfe,
respectively. This is a non-GAAP measure used by Company
management to analyze its
performance.
|
29
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Revenues
Gas, oil
and NGL sales increased by approximately $375.4 million, or 669%, to
approximately $431.5 million for the six months ended June 30, 2008, from
$56.1 million for the six months ended June 30, 2007.
The
increase in gas, oil and NGL revenues was primarily attributable to increased
production as a result of acquisitions and, to a lesser extent,
drilling. Total production increased to 209.5 MMcfe/d during the six
months ended June 30, 2008, from 41.0 MMcfe/d during the six months ended
June 30, 2007. The increase in production was due primarily to
production from the Mid-Continent III oil and gas properties acquired in
August 2007 (see Note 3). In addition, the Company drilled 146
wells during the six months ended June 30, 2008, compared to 58 wells
during the same period of 2007. (These well counts exclude 45 and 55
wells drilled in the Appalachian Basin during the six months ended June 30,
2008 and 2007, respectively, as they were related to discontinued
operations.) Volume increases during the six months ended
June 30, 2008 increased total gas, oil and NGL revenues by $214.5 million
compared to the same period of 2007.
Gas
production increased to 126.1 MMcf/d during the six months ended June 30,
2008, from 15.2 MMcf/d during the six months ended June 30, 2007, primarily
due to the 2007 and 2008 acquisitions in the Mid-Continent region (see
Note 3). The increase in the weighted average price of gas for
the period, to $8.85 per Mcf, from $6.33 per Mcf, contributed approximately
$58.0 million to the increase in gas revenues.
Oil
production increased to 8.6 MBbls/d during the six months ended June 30,
2008, from 2.5 MBbls/d during the six months ended June 30, 2007, due to
acquisitions in the Mid-Continent region and the drilling of new wells in the
Company’s Western region. Acquisitions also increased NGL production
to 5.3 MBbls/d during the six months ended June 30, 2008, from 1.8 MBbls/d
during the comparative period of the prior year. The increase in the
weighted average price of oil for the period, to $103.88 per Bbl, from $49.24
per Bbl, contributed approximately $85.2 million to the increase in oil
revenues. The increase in the weighted average price of NGL for the
period, to $68.60 per Bbl, from $50.08 per Bbl, contributed approximately $17.7
million to the increase in NGL revenues.
Commodity
Derivative Activities
The
Company determines the fair value of its oil and gas derivatives using pricing
models that use a variety of techniques to arrive at fair value, including
quotes and pricing analysis. See Note 9 and Note 10 for
additional information. During the six months ended June 30,
2008, the Company had commodity derivative contracts for approximately 109% of
its gas production and 85% of its oil and NGL production, which resulted in
realized losses of $102.2 million (including realized losses on canceled
contracts of approximately $68.2 million). During the six months
ended June 30, 2008, the Company canceled (before the contract settlement
date) derivative contracts on estimated future gas production primarily
associated with properties in the Appalachian Basin (see Note
2). During the six months ended June 30, 2007, the Company
recorded realized gains of $13.9 million. Unrealized gains and losses
result from changes in market valuations of derivatives as future commodity
price expectations change compared to the contract prices on the
derivatives. During the first two quarters of 2008 and 2007, expected
future oil and gas prices increased, which resulted in unrealized losses on
derivatives of $1.04 billion and $92.0 million for the six months ended
June 30, 2008 and 2007, respectively. Such market value
adjustments, if realized in the future, would be offset by higher actual prices
for production. See Note 9 for details regarding derivatives in
place through December 31, 2014.
Expenses
Lease
operating and other expenses include expenses such as labor, field office,
vehicle, supervision, transportation, maintenance, tools and
supplies. As noted below, total lease operating expenses increased;
however, lease operating expenses per equivalent unit of production (excluding
production and ad valorem taxes) decreased to $1.38 per Mcfe for the six months
ended June 30, 2008, compared to $1.79 per Mcfe for the six months ended
June 30, 2007, due to acquired properties providing cost efficiencies and
economies of scale.
30
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Lease
operating and other expenses increased by approximately $39.3 million, or 295%,
to $52.6 million for the six months ended June 30, 2008, from $13.3 million
for the six months ended June 30, 2007. Operating expenses
increased primarily due to higher production and costs associated with the 2007
and 2008 acquisitions in the Mid-Continent region, including expenses associated
with the addition of approximately 150 field and direct field support employees
in the third quarter of 2007.
Production
and ad valorem taxes were approximately 7% and 8% of total sales for the six
months ended June 30, 2008 and 2007, respectively. Production
and ad valorem taxes increased by approximately $25.8 million, to $30.1 million
for the six months ended June 30, 2008, from $4.3 million for the six
months ended June 30, 2007. Production taxes, which are a
function of revenues generated from production, increased by approximately $22.7
million compared to the same period of 2007. Ad valorem taxes, which
are based on the value of reserves and production equipment and vary by
location, increased by approximately $3.2 million compared to the six months
ended June 30, 2007.
General
and administrative expenses are costs not directly associated with field
operations and include costs of employees and executive officers, related
benefits, office leases and professional fees. As noted below, total
general and administrative expenses increased; however, expenses per equivalent
unit of production decreased to $0.98 per Mcfe for the six months ended
June 30, 2008, compared to $2.99 per Mcfe for the six months ended
June 30, 2007, due to increases in production, cost efficiencies and
economies of scale provided by acquired properties.
General
and administrative expenses increased by approximately $15.2 million, or 68%, to
$37.4 million for the six months ended June 30, 2008, from $22.2 million
for the six months ended June 30, 2007. The increase in general
and administrative expenses over the first six months of 2007 was primarily due
to costs incurred to support the Company’s increased size and infrastructure
growth, including the addition of a regional operating office in
Oklahoma. Salaries and benefits expense increased approximately $9.9
million during the six months ended June 30, 2008 and includes costs
associated with approximately 150 support employees added in the third quarter
of 2007. Information technology costs, such as software, data
administration and data conversion costs increased by approximately $3.3 million
compared to the same period of 2007.
The
Company incurred expenses of approximately $2.5 million for data license fees
during the six months ended June 30, 2008. These expenses
primarily represent payments for access to 3-D seismic and other data libraries
in the Mid-Continent for periods ranging from one to 50 years or more and enable
the Company to maximize drilling opportunities in that region.
Depreciation,
depletion and amortization increased by approximately $82.0 million, to $94.5
million for the six months ended June 30, 2008, from $12.5 million for the
six months ended June 30, 2007. Higher total production levels,
primarily due to the Company’s acquisitions in the Mid-Continent in 2008 and
2007, were the primary reason for the increase.
Other
income and (expenses) increased by approximately $52.0 million, to expense of
$60.9 million for the six months ended June 30, 2008, compared to expense
of $8.9 million for the six months ended June 30, 2007, primarily due to an
increase in interest expense of approximately $40.0 million related to higher
debt levels associated with borrowings to fund acquisitions and
drilling. In addition, total losses on interest rate swaps increased
by approximately $8.0 million over the prior year. The Company’s
interest rate swaps were not designated as cash flow hedges under SFAS 133,
even though they reduce exposure to changes in interest rates (see
Note 9). Therefore, the changes in fair values of these
instruments were recorded as an unrealized loss of approximately $2.1 million
and an unrealized gain of approximately $0.1 million for the six months ended
June 30, 2008 and 2007, respectively. These amounts are non-cash
items. Additionally, the Company wrote-off deferred financing fees of
approximately $3.4 million during the six months ended June 30, 2008, which
contributed to the increase in other income and (expenses) associated with its
Term Loan (see Note 8).
Income
tax expense was approximately $45,000 and $4.0 million for the six months ended
June 30, 2008 and 2007, respectively. The Company is a limited
liability company treated as a partnership for federal and state income tax
purposes. Limited liability companies are subject to state income
taxes in Texas. Certain of the Company’s
31
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
subsidiaries
are Subchapter C-corporations subject to federal and state income
taxes. Tax expense for the six months ended June 30, 2007
relates primarily to 2006 expense recovery. The Company’s taxable
subsidiaries generated net operating losses for the year ended December 31,
2006, which were subsequently recovered through an intercompany service charge,
resulting in tax expense for the six months ended June 30,
2007.
Results
of Operations – Discontinued Operations
The
following table presents comparative data for the Company’s discontinued
operations related to its Appalachian Basin assets. See Note 2
for additional details about discontinued operations.
|
Three
Months Ended
|
Six
Months Ended
|
|||||||||||||||||||||||
|
June 30,
|
June 30,
|
|||||||||||||||||||||||
|
2008
|
2007
|
Variance
|
2008
|
2007
|
Variance
|
|||||||||||||||||||
|
Average
daily production:
|
||||||||||||||||||||||||
|
Gas
(MMcf/d)
|
23.4 | 22.2 | 5.4 | % | 23.8 | 22.8 | 4.4 | % | ||||||||||||||||
|
Oil
(MBbls/d)
|
0.1 | 0.1 | — | 0.1 | 0.1 | — | ||||||||||||||||||
|
Total
(MMcfe/d)
|
24.0 | 22.8 | 5.3 | % | 24.4 | 23.4 | 4.3 | % | ||||||||||||||||
The sale
of properties in the Appalachian Basin (see Note 2) will produce taxable
gains or losses to unitholders. The amount of gain or loss will be
determined at unitholder level, based on each affected unitholder’s tax basis in
the disposed properties and allocated sale proceeds and in accordance with the
terms of the Company’s Second Amended and Restated Limited Liability Company
Agreement, as amended, and the applicable tax laws, and will be reflected in
unitholder K-1s to be provided in the spring of 2009.
Liquidity
and Capital Resources
The
Company has utilized public and private equity, proceeds from bank borrowings
and cash flow from operations for capital resources and liquidity. To
date, the primary use of capital has been for the acquisition and development of
oil and gas properties. The Company manages its working capital and
cash requirements to borrow only as needed. At June 30, 2008,
the Company’s total current liabilities exceeded current assets by approximately
$330.3 million due to $354.8 million of current liabilities for derivative
instruments and $69.3 million of current liabilities for cash down payments
received in connection with the July 2008 sale of properties in the Appalachian
Basin and the pending sale of properties in the Verden area (see Note
2). The latter amount will be included with the net proceeds from the
sales in the third quarter of 2008. The Company had $330.1 million in
available borrowing capacity at July 31, 2008.
As the
Company pursues growth, it continually monitors the capital resources available
to meet future financial obligations and planned capital
expenditures. The Company’s future success in growing reserves and
production will be highly dependent on the capital resources available and its
success in drilling for or acquiring additional reserves. The Company
actively reviews acquisition opportunities on an ongoing basis. If
the Company were to make significant additional acquisitions for cash, it would
need to borrow additional amounts, if available, or obtain additional debt or
equity financing. The Company’s Credit Facility and Senior Notes
impose certain restrictions on the Company’s ability to obtain additional debt
financing. Based upon current expectations, the Company believes
liquidity and capital resources will be sufficient for the conduct of its
business and operations.
During
the second quarter, the Company received general corporate ratings of B1 and B+
from Moody’s Investors Service (“Moody’s”) and Standard & Poor’s
(“S&P”), respectively. The Company also received credit ratings
of B3 and B- from Moody’s and S&P, respectively, for its Senior Notes
(see Note 8). Management believes its ratings and access to the
public debt market enhance its financial flexibility by providing an additional
source of capital. Changes in the Company’s ratings could affect its
costs and availability of financing.
32
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Cash
Flows
The
following presents comparative cash flow summary for the periods
reported.
|
Six
Months Ended
June 30,
|
||||||||||||
|
2008
|
2007
|
Variance
|
||||||||||
|
(in
thousands)
|
||||||||||||
|
Cash
flow statement information:
|
||||||||||||
|
Net
cash:
|
||||||||||||
|
Provided
by (used in) operating activities
|
$ | 60,583 | $ | (19,387 | ) | $ | 79,970 | |||||
|
Used
in investing activities
|
(672,883 | ) | (587,334 | ) | (85,549 | ) | ||||||
|
Provided
by financing activities
|
620,471 | 601,084 | 19,387 | |||||||||
|
Increase
in cash and cash equivalents
|
$ | 8,171 | $ | (5,637 | ) | $ | 13,808 | |||||
Operating
Activities
At
June 30, 2008, the Company had $9.6 million cash and cash equivalents
compared to $1.4 million at December 31, 2007. Cash provided by
operating activities for the six months ended June 30, 2008 was
approximately $60.6 million, compared to cash used by operating activities of
$19.4 million for the six months ended June 30, 2007. The
increase in cash provided by operating activities was primarily due to increased
production during the six months ended June 30, 2008. During the
six months ended June 30, 2008, the Company canceled (before the contract
settlement date) derivative contracts on estimated future gas production
primarily associated with properties in the Appalachian Basin (see Note 2)
resulting in a realized loss of approximately $68.2 million. In
addition, premiums paid for derivatives were approximately $1.3 million during
the six months ended June 30, 2008, compared to $53.0 million during the
six months ended June 30, 2007. The premiums paid were for
derivative contracts that hedge future production for up to five
years. These derivative contracts are expected to provide or
stabilize the Company’s future cash flow and were funded through the Company’s
Credit Facility. See Note 9 for additional details about
commodity derivatives. The amount of derivative contracts the Company
enters into in the future will be directly related to expected production from
future acquisitions and cannot be predicted at this time.
Investing
Activities
Cash used
in investing activities was approximately $672.9 million for the six months
ended June 30, 2008, compared to $587.3 million for the six months ended
June 30, 2007. The increase in cash used in investing activities
was due to an increase in acquisition and development activity during the six
months ended June 30, 2008, compared to the same period of the prior
year.
The total
cash used in investing activities for the six months ended June 30, 2008
includes $505.5 million for the January 2008 acquisition of properties in the
Mid-Continent (see Note 3). Other acquisitions, including
acquisitions of additional working interests in current wells, were
approximately $67.5 million and other property and equipment purchases were $3.4
million. The total for the six months ended June 30, 2008 also
includes approximately $173.0 million for the drilling and development of oil
and gas properties and pipeline costs, of which approximately $12.8 million
represents amounts spent on drilling in the Appalachian Basin. For
2008, the Company estimates its total drilling and development capital
expenditures will be approximately $300.0 million. This estimate is
under continuous review and is subject to on-going adjustment. During
the six months ended June 30, 2008, the Company also received proceeds,
including deposits from the sale of oil and gas properties to XTO and Laredo,
and other plant and equipment of approximately $76.6 million (see
Note 2).
33
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Financing
Activities
Cash
provided by financing activities was approximately $620.5 million for the six
months ended June 30, 2008, compared to $601.1 million for the six months
ended June 30, 2007. During the six months ended June 30,
2008, total proceeds from the issuance of debt were $1.17 billion and total
repayments of debt were $384.9 million. See additional discussion
about the Company’s Credit Facility, Term Loan and Senior Notes
below. In addition, see detail of distributions paid during the six
months ended June 30, 2008 below.
Distributions
Under the
limited liability company agreement, Company unitholders are entitled to receive
a quarterly distribution of available cash to the extent there is sufficient
cash from operations after establishment of cash reserves and payment of fees
and expenses. The following provides a summary of distributions paid
by the Company during the six months ended June 30, 2008:
|
Distributions
|
||||||||||
|
Date
Paid
|
Period
Covered by Distribution
|
Per
Unit
|
Total
|
|||||||
|
(in
millions)
|
||||||||||
|
May
2008
|
January
1 – March 31, 2008
|
$ | 0.63 | $ | 72.6 | |||||
|
February
2008
|
October 1
– December 31, 2007
|
$ | 0.63 | $ | 72.2 | |||||
In July
2008, the Company’s Board of Directors declared a cash distribution of $0.63 per
unit, or $2.52 per unit on an annualized basis, with respect to the second
quarter of 2008. The distribution totaling approximately $72.6
million will be paid on August 14, 2008 to unitholders of record as of the
close of business on August 7, 2008.
Credit
Facility
At
July 31, 2008, the Company had a $1.85 billion borrowing base under its
Credit Facility with a maturity of August 2010 (see Note 8). The
borrowing base under the Credit Facility will be redetermined semi-annually by
the lenders in their sole discretion, based on, among other things, reserve
reports as prepared by reserve engineers taking into account the oil and gas
prices at such time. At the Company’s election, interest on
borrowings under the Credit Facility is determined by reference to either LIBOR
plus an applicable margin between 1.00% and 1.75% per annum or the ABR plus an
applicable margin between 0% and 0.25% per annum. As noted above, the
Company depends on its Credit Facility for future capital needs. In
addition, the Company has drawn on the Credit Facility to fund or partially fund
quarterly cash distribution payments, since it uses operating cash flows for
investing activities and borrows as cash is needed. Absent such
borrowing, the Company would have at times experienced a shortfall in cash
available to pay the declared quarterly cash distribution amount. If
there is a default under the Credit Facility, the Company would be unable to
make borrowings to fund distributions.
On
July 1, 2008, the Company repaid $357.6 million in indebtedness under its
Credit Facility with a portion of the net proceeds from the sale of properties
in the Appalachian Basin (see Note 2). At July 31, 2008,
available borrowing under the Credit Facility was $330.1 million, which includes
a $6.5 million reduction in availability for outstanding letters of
credit.
34
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Term
Loan
On
January 31, 2008, in order to fund a portion of the January 2008
acquisition of oil and gas properties in the Mid-Continent (see Note 3),
the Company entered into a $400.0 million Term Loan maturing on July 31,
2009, secured by a second priority lien on all oil and gas properties as well as
a second priority pledge on all ownership interests in its operating
subsidiaries (see Note 8). On June 30, 2008, the Company
repaid $243.6 million in indebtedness under the Term Loan with net proceeds from
the Senior Notes (see below). On July 1, 2008, the Company
repaid the balance of the term loan of $156.4 million. Deferred
financing fees associated with the Term Loan of approximately $2.8 million were
written off during the six months ended June 30,
2008. Additionally, approximately $1.9 million in fees were written
off in July 2008.
Senior
Notes
On
June 24, 2008, the Company entered into a purchase agreement with a group
of Initial Purchasers pursuant to which the Company agreed to issue $255.9
million in aggregate principal amount of the Company’s Senior Notes due 2018
(see Note 8). The Senior Notes were offered and sold to the
Initial Purchasers and then resold to qualified institutional buyers each in
transactions exempt from the registration requirements under the Securities
Act. The Company used the net proceeds (after deducting the Initial
Purchasers’ discounts and offering expense) of approximately $243.6 million to
repay loans outstanding under the Company’s Term Loan (see above). In
connection with the Senior Notes, the Company incurred financing fees of
approximately $7.3 million, which will be amortized over the life of the Senior
Notes and recorded in interest expense. The $5.9 million discount on
the Senior Notes will be amortized over the life of the Senior Notes and
recorded in interest expense.
The
Senior Notes were issued under an Indenture dated June 27, 2008, mature on
July 1, 2018 and bear interest at 9.875%. Interest is payable
semi-annually beginning January 1, 2009. The Senior Notes are
general unsecured senior obligations of the Company and are effectively junior
in right of payment to any secured indebtedness of the Company to the extent of
the collateral securing such indebtedness. Each of the Company’s
material subsidiaries guaranteed the Senior Notes on a senior unsecured
basis. The Indenture provides that the Company may redeem 1) on
or prior to July 1, 2011, up to 35% of the aggregate principal amount of
the Senior Notes at a redemption price of 109.875% of the principal amount, plus
accrued and unpaid interest, 2) prior to July 1, 2013, all or part of
the Senior Notes at a redemption price equal to the principal amount, plus a
make whole premium (as defined in the Indenture) and accrued and unpaid
interest, and 3) on or after July 1, 2013, all or part of the Senior
Notes at redemption prices equal to 104.938% in 2013, 103.292% in 2014, 101.646%
in 2015 and 100% in 2016 and thereafter. The Indenture also provides
that, if a change of control (as defined in the Indenture) occurs, the holders
have a right to require the Company to repurchase all or part of the Senior
Notes at a redemption price equal to 101%, plus accrued and unpaid
interest.
The
Senior Notes’ Indenture contains covenants that, among other things, limit the
Company’s ability to: (i) pay distributions on, purchase or redeem the
Company’s units or redeem its subordinated debt; (ii) make investments;
(iii) incur or guarantee additional indebtedness or issue certain types of
equity securities; (iv) create certain liens; (v) sell assets;
(vi) consolidate, merge or transfer all or substantially all of the
Company’s assets; (vii) enter into agreements that restrict distributions
or other payments from the Company’s restricted subsidiaries to the Company;
(viii) engage in transactions with affiliates; and (ix) create
unrestricted subsidiaries.
In
connection with the issuance and sale of the Senior Notes, the Company entered
into a Registration Rights Agreement with the Initial
Purchasers. Under the Registration Rights Agreement, the Company
agreed to use its reasonable best efforts to file with the SEC and cause to
become effective a registration statement relating to an offer to issue new
notes having terms substantially identical to the Senior Notes in exchange for
outstanding Senior Notes. In certain circumstances, the Company may
be required to file a shelf registration statement to cover resales of the
Senior Notes. The Company will not be obligated to file the
registration statements described above if the restrictive legend on the Senior
Notes has been removed and the Senior Notes are freely tradable (in each case,
other than with respect to persons that are affiliates of the Company) pursuant
to Rule 144 under the Securities Act, as of the 366th day after the Senior
Notes were issued. If the Company fails to satisfy its obligations
under the Registration Rights
35
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Agreement,
the Company may be required to pay additional interest to holders of the Senior
Notes under certain circumstances.
Off-Balance
Sheet Arrangements
At
June 30, 2008, the Company did not have any off-balance sheet arrangements
that have, or are reasonably likely to have, a material effect on its financial
position or results of operations.
Contingencies
During
the six months ended June 2008 and 2007, the Company made no significant
payments to settle any legal, environmental or tax proceedings. The
Company regularly analyzes current information and accrues for probable
liabilities on the disposition of certain matters, as
necessary. Liabilities for loss contingencies arising from claims,
assessments, litigation or other sources are recorded when it is probable that a
liability has been incurred and the amount can be reasonably
estimated.
Commitments
and Contractual Obligations
The
Company has contractual obligations for long-term debt, operating leases and
other long-term liabilities that were summarized in a table of contractual
obligations in the 2007 Annual Report on Form 10-K. With the
exception of a $400.0 million Term Loan (repaid in July 2008) and $255.9 million
of Senior Notes, as of June 30, 2008, there have been no significant
changes to the Company’s contractual obligations from December 31,
2007. See “Term Loan” and “Senior Notes” above for additional
details.
Critical
Accounting Policies and Estimates
The
discussion and analysis of the Company’s financial condition and results of
operations is based upon the consolidated financial statements, which have been
prepared in accordance with GAAP. The preparation of these financial
statements requires the Company to make estimates and assumptions that affect
the reported amounts of assets, liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities. Certain accounting
policies involve judgments and uncertainties to such an extent that there is
reasonable likelihood that materially different amounts could have been reported
under different conditions, or if different assumptions had been
used. The Company evaluates its estimates and assumptions on a
regular basis. The Company bases estimates on historical experience
and various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates and
assumptions used in the preparation of financial statements.
As of
June 30, 2008, there have been no significant changes with regard to the
critical accounting policies disclosed in the Company’s Annual Report on
Form 10-K for the year ended December 31, 2007. The
policies disclosed included the accounting for oil and gas properties, revenue
recognition, purchase accounting and derivative instruments.
New
Accounting Standards
See
Note 17 for detail regarding SFAS 157 implementation effective
January 1, 2008 and January 1, 2009, and also for detail regarding
SFAS 161 implementation effective January 1, 2008.
36
|
Item
2. Management’s
Discussion and Analysis of Financial Condition and Results of Operations -
Continued
|
Cautionary
Statement
This
Quarterly Report on Form 10-Q contains forward-looking statements that are
subject to a number of risks and uncertainties, many of which are beyond the
Company’s control. These statements may include statements about the
Company’s:
|
|
·
|
business
strategy;
|
|
|
·
|
acquisition
strategy;
|
|
|
·
|
financial
strategy;
|
|
|
·
|
drilling
locations;
|
|
|
·
|
oil,
gas and NGL reserves;
|
|
|
·
|
realized
oil, gas and NGL prices;
|
|
|
·
|
production
volumes;
|
|
|
·
|
lease
operating expenses, general and administrative expenses and finding and
development costs;
|
|
|
·
|
future
operating results; and
|
|
|
·
|
plans,
objectives, expectations and
intentions.
|
All of
these types of statements, other than statements of historical fact included in
this Quarterly Report on Form 10-Q, are forward looking
statements. These forward-looking statements may be found in
Item 2. In some cases, forward-looking statements can be
identified by terminology such as “may,” “will,” “could,” “should,” “expect,”
“plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,”
“potential,” “pursue,” “target,” “continue,” the negative of such terms or other
comparable terminology.
The
forward-looking statements contained in this Quarterly Report on Form 10-Q
are largely based on Company expectations, which reflect estimates and
assumptions made by Company management. These estimates and
assumptions reflect management’s best judgment based on currently known market
conditions and other factors. Although the Company believes such
estimates and assumptions to be reasonable, they are inherently uncertain and
involve a number of risks and uncertainties beyond its control. In
addition, management’s assumptions may prove to be inaccurate. The
Company cautions that the forward-looking statements contained in this Quarterly
Report on Form 10-Q are not guarantees of future performance, and it cannot
assure any reader that such statements will be realized or the forward-looking
statements or events will occur. Actual results may differ materially
from those anticipated or implied in forward-looking statements due to factors
listed in “Item 1A. Risk Factors” in the Company’s Annual Report on
Form 10-K for the year ended December 31, 2007 and herein, and
elsewhere in the Annual Report and also in the Company’s Quarterly Reports on
Form 10-Q. The forward-looking statements speak only as of the
date made, and other than as required by law, the Company undertakes no
obligation to publicly update or revise any forward-looking statement, whether
as a result of new information, future events or otherwise.
The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about potential exposure to market
risks. A reference to a “Note” herein refers to the accompanying
Notes to Condensed Consolidated Financial Statements contained in Item 1.
“Financial Statements.”
Commodity
Price Risk
The
Company enters into derivative contracts arrangements with respect to a portion
of its projected production through various transactions that provide an
economic hedge of the risk related to the future prices received. The
Company does not enter into derivative contracts for trading
purposes. See Note 9 for additional details. At
June 30, 2008, the fair value of contracts that settle during the next
twelve months was a liability of approximately $310.5 million for which the
Company will owe its counterparties. A 10% increase in the index oil
and gas prices above the June 30, 2008 prices for the next twelve months
would result in an increase in the liability of approximately $83.1 million;
conversely, a 10% decrease in the index oil and gas prices would result in a
decrease of approximately $85.4 million.
Interest
Rate Risk
At
June 30, 2008, the Company had long-term debt outstanding under its Credit
Facility of approximately $1.83 billion, which incurred interest at floating
rates. See Note 8 for additional details. As of
June 30, 2008, the interest rate based on LIBOR was approximately
4.21%. A 1% increase in LIBOR would result in an estimated $18.3
million increase in annual interest expense. The Company has entered
into interest rate swap agreements based on LIBOR to minimize the effect of
fluctuations in interest rates. See Note 9 for additional
details.
Evaluation
of Disclosure Controls and Procedures
The
Company maintains disclosure controls and procedures that are designed to ensure
that information required to be disclosed in the Company’s reports under the
Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded,
processed, summarized and reported within the time periods specified in the
SEC’s rules and forms, and that such information is accumulated and communicated
to management, including the Company’s Chief Executive Officer and Chief
Financial Officer, and the Company’s Audit Committee of the Board of Directors,
as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating the disclosure controls and
procedures, management recognizes that any controls and procedures, no matter
how well designed and operated, can provide only reasonable assurance of
achieving the desired control objectives, and management is required to apply
its judgment in evaluating the cost-benefit relationship of possible controls
and procedures.
The
Company carried out an evaluation under the supervision and with the
participation of its management, including its Chief Executive Officer and Chief
Financial Officer, of the effectiveness of its disclosure controls and
procedures as of the end of the period covered by this report. Based
on this evaluation, the Chief Executive Officer and Chief Financial Officer
concluded that the Company’s disclosure controls and procedures were effective
as of June 30, 2008.
Changes
in the Company’s Internal Control Over Financial Reporting
The
Company’s management is also responsible for establishing and maintaining
adequate internal controls over financial reporting, as defined in
Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The
Company’s internal controls were designed to provide reasonable assurance as to
the reliability of its financial reporting and the preparation and presentation
of the consolidated financial statements for external purposes in accordance
with accounting principles generally accepted in the United States.
There
were no changes in the Company’s internal controls over financial reporting
during the three months ended June 30, 2008 that materially affected, or
were reasonably likely to materially affect, the Company’s internal control over
financial reporting.
The
Company completed acquisitions of oil and gas properties in the Mid-Continent in
August 2007 and January 2008. Company management continues to
integrate internal controls and enhanced reporting related to the financial
performance of the acquired operations with the Company’s internal control over
financial reporting. This integration will lead to changes in these
controls in future fiscal periods, but management does not expect these changes
to materially affect the Company’s internal control over financial
reporting. Management will complete the integration process during
2008.
Not
applicable.
Part I,
Item 1A, “Risk Factors,” included in the Company’s Annual Report
Form 10-K for the year ended December 31, 2007 includes a detailed
discussion of the Company’s risk factors. The information presented
below updates, and should be read in conjunction with, the risk factors and
information disclosed in the Company’s 2007 Form 10-K.
Unitholders
may be subject to taxable gains upon dispositions of properties.
We may
dispose of properties in transactions that result in gains that will be
allocated to you, and such gains may be either ordinary or capital in character
to you. Even where we dispose of properties that are capital assets,
what otherwise would be capital gains in your hands may be recharacterized as
ordinary gains in order to “recapture” ordinary deductions that have previously
been allocated to you with respect to the properties. In addition,
such an allocation of ordinary or capital gains may increase your taxable
income, and, consequently, you may be required to pay federal income taxes and,
in some cases, state and local income taxes, even if we have not made a cash
distribution to you subsequent to the disposition of properties. Your
allocable share of the taxable gains also may be greater than your interest in
our profits. If you contributed property in exchange for our units,
or held our units at a time when we issued additional units to other unitholders
(resulting in a revaluation of our assets), your capital account would have been
credited with the fair market value of the property at the time (your “book”
basis), which may have exceeded your “tax” basis of property. Gains
are required to be allocated to you in order to eliminate this “book-tax
disparity.”
None.
None.
The
Company’s Annual Meeting of Unitholders was held on May 29,
2008. Set forth below are descriptions of the matters voted on at the
meeting and the results of the votes taken at the meeting.
|
|
1.
|
To
elect five directors to the Company’s Board of Directors to serve until
the 2009 Annual Meeting of
Unitholders.
|
|
Name
of Director
|
Votes
For
|
Votes
Against
or
Withheld
|
||||||
|
Michael
C. Linn
|
69,081,069 | 483,802 | ||||||
|
George
A. Alcorn
|
68,876,966 | 687,904 | ||||||
|
Terrence
S. Jacobs
|
68,936,768 | 628,102 | ||||||
|
Jeffrey
C. Swoveland
|
69,054,772 | 510,098 | ||||||
|
Joseph
P. McCoy
|
69,063,308 | 501,562 | ||||||
|
|
2.
|
To
ratify the appointment of KPMG LLP as independent auditor of the Company
for the fiscal year ending December 31,
2008.
|
|
Votes
For
|
Votes
Against
or
Withheld
|
Abstentions
|
||||||||||
| 69,108,337 | 338,766 | 117,767 | ||||||||||
|
|
3.
|
To
approve the Amended and Restated Linn Energy, LLC Long Term Incentive
Plan.
|
|
Votes
For
|
Votes
Against
or
Withheld
|
Abstentions
|
||||||||||
| 37,129,496 | 7,246,732 | 212,599 | ||||||||||
None.
|
Exhibit Number
|
Description
|
|||||
|
2
|
.1*†
|
—
|
First
Amended and Restated Asset Purchase and Sale Agreement, dated as of
June 9, 2008, between Linn Energy Holdings, LLC, Linn Operating,
Inc., Penn West Pipeline, LLC, as sellers, and XTO Energy Inc., as
buyer
|
|||
|
2
|
.2*†
|
—
|
First
Amendment, dated as of July 1, 2008, to First Amended and Restated
Asset Purchase and Sale Agreement between Linn Energy Holdings, LLC, Linn
Operating, Inc., Penn West Pipeline, LLC, as sellers, and XTO Energy Inc.,
as buyer
|
|||
|
2
|
.3*†
|
—
|
First
Amendment, dated as of July 1, 2008, to Limited Partnership Asset
Purchase and Sale Agreement between Linn Energy Holdings, LLC, Marathon
85-II Limited Partnership, Marathon 85-III Limited Partnership, as sellers
and XTO Energy Inc., as buyer
|
|||
|
2
|
.4*†
|
—
|
Asset
Purchase and Sale Agreement, dated as of May 30, 2008, between Linn Energy
Holdings, LLC, Linn Operating, Inc., Mid-Continent I, LLC, Mid-Continent
II, LLC and Linn Exploration Mid-Continent, LLC, as sellers, and Laredo
Petroleum, Inc., as buyer
|
|||
|
4
|
.1
|
—
|
Indenture,
dated as of June 27, 2008, among Linn Energy, LLC, Linn Energy
Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank
National Association, as Trustee (incorporated herein by reference to
Exhibit 4.1 to Current Report on Form 8-K filed on June 30,
2008)
|
|||
|
4
|
.2
|
—
|
Registration
Rights Agreement, dated June 27, 2008, among Linn Energy, LLC, Linn
Energy Finance Corp., the Subsidiary Guarantors named therein and the
representatives of the Initial Purchasers named therein (incorporated
herein by reference to Exhibit 4.2 to Current Report on Form 8-K filed on
June 30, 2008)
|
|||
|
10
|
.1†
|
—
|
Third
Amendment, dated as of June 16, 2008, to Third Amended and Restated
Credit Agreement among Linn Energy, LLC, as Borrower, BNP Paribas, as
Administrative Agent and the lenders and agents party
thereto
|
|||
|
10
|
.2†
|
—
|
Amended
and Restated Employment Agreement, dated June 4, 2008 between Linn
Operating, Inc. and David B. Rottino
|
|||
|
10
|
.3†
|
—
|
Separation
Agreement, dated effective June 11, 2008 between Linn Operating, Inc.
and Lisa D. Anderson
|
|||
|
10
|
.4†
|
—
|
Separation
Agreement, dated effective May 8, 2008 between Linn Operating, Inc.
and Thomas A. Lopus
|
|||
|
31
|
.1†
|
—
|
Section 302
Certification of Michael C. Linn, Chairman and Chief Executive
Officer of Linn Energy, LLC
|
|||
|
31
|
.2†
|
—
|
Section 302
Certification of Kolja Rockov, Executive Vice President and Chief
Financial Officer of Linn Energy, LLC
|
|||
|
32
|
.1†
|
—
|
Section 906
Certification of Michael C. Linn, Chairman and Chief Executive Officer of
Linn Energy, LLC
|
|||
|
32
|
.2†
|
—
|
Section 906
Certification of Kolja Rockov, Executive Vice President and Chief
Financial Officer of Linn Energy,
LLC
|
|||
|
†
|
Filed
herewith.
|
|
*
|
The
schedules to this agreement have been omitted from this filing pursuant to
Item 601(b)(2) of Regulation S-K. The Company will
furnish copies of such schedules to the Securities and Exchange Commission
upon request.
|
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.
|
LINN
ENERGY, LLC
|
|
|
(Registrant)
|
|
|
Date:
August 7, 2008
|
/s/ David
B. Rottino
|
|
David
B. Rottino
|
|
|
Senior
Vice President and Chief Accounting Officer
|
|
|
(As
Duly Authorized Officer and Chief Accounting
Officer)
|
43