Attached files
Exhibit
99.6
FINANCIAL
STATEMENTS AND NOTES FOR NFR ENERGY LLC.
CONSOLIDATED
FINANCIAL STATEMENTS
NFR
ENERGY LLC
Years Ended December 31, 2010, 2009 and 2008
1
INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS
3 | ||||
4 | ||||
Audited Consolidated Financial Statements
|
||||
5 | ||||
6 | ||||
7 | ||||
8 | ||||
9-27 | ||||
28-32 |
2
Report of
Independent Registered Public Accounting Firm
The Member of NFR Energy LLC
In our opinion, the accompanying consolidated balance sheets and
the related consolidated statement of operations, of member
capital, and of cash flows present fairly, in all material
respects, the financial position of NFR Energy LLC and its
subsidiaries (the Company) at December 31, 2010
and December 31, 2009 and the results of their operations
and their cash flows for each of the two years then ended in
conformity with accounting principles generally accepted in the
United States of America. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audit of these
statements in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles
used and significant estimates made by management, and
evaluating the overall financial statement presentation. We
believe that our audit provides a reasonable basis for our
opinion.
As discussed in Note 2 to the consolidated financial
statements, at December 31, 2009, the Company changed the
manner in which its oil and natural gas reserves are estimated
as well as the manner in which prices are determined to
calculate the ceiling limit on capitalized oil and natural gas
costs.
/s/ PricewaterhouseCoopers
LLP
Houston, Texas
February 24, 2011
3
Report of
Independent Auditors
The Members of NFR Energy LLC
We have audited the accompanying consolidated statement of
operations, changes in members capital, and cash flows of
NFR Energy LLC for the year ended December 31, 2008. These
financial statements are the responsibility of the
Companys management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards
generally accepted in the United States. Those standards require
that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. We were not engaged to perform an audit
of the Companys internal control over financial reporting.
Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures
that are appropriate in the circumstances, but not for the
purpose of expressing an opinion on the effectiveness of the
Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the consolidated
results of operations and cash flows of NFR Energy LLC for the
year ended December 31, 2008, in conformity with
U.S. generally accepted accounting principles.
/s/ Ernst &
Young LLP
Houston, Texas
March 27, 2009
4
CONSOLIDATED
FINANCIAL STATEMENTS
NFR ENERGY LLC
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2010 AND 2009
NFR ENERGY LLC
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2010 AND 2009
December 31, |
December 31, |
|||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
ASSETS
|
||||||||
Current assets:
|
||||||||
Cash and cash equivalents
|
$ | 4,437 | $ | 2,489 | ||||
Accounts receivable, net
|
16,016 | 21,321 | ||||||
Prepaid expenses and other current assets
|
11,010 | 28,181 | ||||||
Derivative instruments
|
40,749 | 32,288 | ||||||
Total current assets
|
72,212 | 84,279 | ||||||
Property, plant and equipment:
|
||||||||
Oil and gas properties (full cost method)
|
||||||||
Proved
|
1,506,565 | 1,177,439 | ||||||
Unproved
|
218,172 | 178,625 | ||||||
Gas gathering and processing equipment
|
40,195 | 39,949 | ||||||
Office furniture and fixtures
|
6,325 | 5,900 | ||||||
1,771,257 | 1,401,913 | |||||||
Accumulated depletion, depreciation and amortization
|
(934,682 | ) | (882,192 | ) | ||||
Total property, plant and equipment, net
|
836,575 | 519,721 | ||||||
Other assets:
|
||||||||
Derivative instruments
|
68,272 | 28,683 | ||||||
Deferred financing costs
|
13,024 | 3,666 | ||||||
Total other assets
|
81,296 | 32,349 | ||||||
Total assets
|
$ | 990,083 | $ | 636,349 | ||||
LIABILITIES AND MEMBERS CAPITAL
|
||||||||
Current liabilities:
|
||||||||
Accounts payable trade
|
$ | 4,160 | $ | 13,916 | ||||
Accounts payable related party
|
16,058 | 1,572 | ||||||
Royalties payable
|
4,904 | 7,850 | ||||||
Accrued interest payable
|
13,078 | 1,399 | ||||||
Accrued exploration and development
|
48,112 | 36,647 | ||||||
Accrued operating expenses and other
|
17,776 | 13,789 | ||||||
Derivative instruments
|
| 198 | ||||||
Total current liabilities
|
104,088 | 75,371 | ||||||
Long term liabilities:
|
||||||||
Revolving credit facility
|
94,000 | 214,500 | ||||||
Second lien term loan
|
| 50,000 | ||||||
Senior notes
|
346,153 | | ||||||
Asset retirement obligation
|
9,213 | 8,155 | ||||||
Derivative instruments
|
| 509 | ||||||
Other long term obligations
|
891 | 1,212 | ||||||
Total long term liabilities
|
450,257 | 274,376 | ||||||
Commitments and contingencies
|
||||||||
Members capital:
|
||||||||
Members capital
|
1,065,176 | 1,005,600 | ||||||
Amounts receivable from member(s)
|
(143 | ) | (351 | ) | ||||
Accumulated deficit
|
(738,052 | ) | (776,821 | ) | ||||
Accumulated other comprehensive income
|
105,722 | 55,399 | ||||||
Total controlling interests members capital
|
432,703 | 283,827 | ||||||
Noncontrolling interests
|
3,035 | 2,775 | ||||||
Total members capital
|
435,738 | 286,602 | ||||||
Total liabilities and members capital
|
$ | 990,083 | $ | 636,349 | ||||
The accompanying notes are an integral part of these
consolidated financial statements.
5
CONSOLIDATED
FINANCIAL STATEMENTS
NFR ENERGY LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
NFR ENERGY LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
For the Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenues
|
||||||||||||
Oil and natural gas sales
|
$ | 130,123 | $ | 81,937 | $ | 96,015 | ||||||
Gain (loss) on derivative instruments
|
51,104 | 60,686 | (2,266 | ) | ||||||||
Other revenue
|
1,390 | 957 | 592 | |||||||||
Total revenues
|
182,617 | 143,580 | 94,341 | |||||||||
Operating expenses
|
||||||||||||
Lease operating expenses
|
18,982 | 18,520 | 13,537 | |||||||||
Workover expenses
|
848 | 482 | 843 | |||||||||
Marketing, gathering, transportation and other
|
11,792 | 6,031 | 3,107 | |||||||||
Production and ad valorem taxes
|
5,483 | 4,228 | 5,364 | |||||||||
General and administrative expenses
|
20,259 | 17,395 | 14,501 | |||||||||
Depletion, depreciation and amortization
|
52,490 | 44,813 | 34,299 | |||||||||
Accretion expense
|
493 | 407 | 215 | |||||||||
Bad debt expense
|
18 | 93 | | |||||||||
Impairments
|
1,711 | 407,294 | 415,843 | |||||||||
Total operating expenses
|
112,076 | 499,263 | 487,709 | |||||||||
Other income (expenses)
|
||||||||||||
Interest expense
|
(33,468 | ) | (9,392 | ) | (7,115 | ) | ||||||
Gain (loss) on derivative instruments
|
2,547 | 3,793 | (1,355 | ) | ||||||||
Gain on bargain purchase
|
372 | | | |||||||||
Other income (loss)
|
(963 | ) | (8,478 | ) | 349 | |||||||
Total other expenses
|
(31,512 | ) | (14,077 | ) | (8,121 | ) | ||||||
Net income (loss) including noncontrolling interests
|
39,029 | (369,760 | ) | (401,489 | ) | |||||||
Less: Net income applicable to noncontrolling interests
|
(260 | ) | (516 | ) | (191 | ) | ||||||
Net income (loss) applicable to controlling interests
|
$ | 38,769 | $ | (370,276 | ) | $ | (401,680 | ) | ||||
The accompanying notes are an integral part of these
consolidated financial statements.
6
CONSOLIDATED
FINANCIAL STATEMENTS
NFR ENERGY LLC
CONSOLIDATED STATEMENT OF MEMBERS CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
NFR ENERGY LLC
CONSOLIDATED STATEMENT OF MEMBERS CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
Accumulated |
||||||||||||||||||||||||||||||||
Amounts |
Other |
|||||||||||||||||||||||||||||||
Comprehensive |
Members Capital |
Receivable from |
Accumulated |
Comprehensive |
Noncontrolling |
Total Members |
||||||||||||||||||||||||||
Income | Units | Value | Member | Deficit | Income | Interests | Capital | |||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||
Balance as of December 31, 2007
|
487 | $ | 486,741 | $ | | $ | (4,865 | ) | $ | | $ | | $ | 481,876 | ||||||||||||||||||
Members contributions
|
368 | 368,017 | | | | | 368,017 | |||||||||||||||||||||||||
Amounts receivable from members
|
| | (272 | ) | | | | (272 | ) | |||||||||||||||||||||||
Acquisition of noncontrolling interests
|
| | | | | 2,543 | 2,543 | |||||||||||||||||||||||||
Distributions to members for state tax withholding
|
| (614 | ) | | | | | (614 | ) | |||||||||||||||||||||||
Comprehensive loss
|
||||||||||||||||||||||||||||||||
Net loss applicable to controlling interests
|
$ | (401,680 | ) | | | | (401,680 | ) | | | (401,680 | ) | ||||||||||||||||||||
Unrealized gain on derivative instruments
|
40,919 | | | | | 40,919 | | 40,919 | ||||||||||||||||||||||||
Comprehensive loss applicable to controlling interests
|
(360,761 | ) | ||||||||||||||||||||||||||||||
Net income applicable to noncontrolling interests
|
191 | | | | | | 191 | 191 | ||||||||||||||||||||||||
Comprehensive loss including noncontrolling interests
|
$ | (360,570 | ) | | ||||||||||||||||||||||||||||
Balance as of December 31, 2008
|
855 | $ | 854,144 | $ | (272 | ) | $ | (406,545 | ) | $ | 40,919 | $ | 2,734 | $ | 490,980 | |||||||||||||||||
Members contributions
|
152 | 151,831 | | | | | 151,831 | |||||||||||||||||||||||||
Amounts receivable from members
|
| | (79 | ) | | | | (79 | ) | |||||||||||||||||||||||
Distributions noncontrolling interests
|
| | | | | (475 | ) | (475 | ) | |||||||||||||||||||||||
Distributions to members for state tax withholding
|
| (375 | ) | | | | | (375 | ) | |||||||||||||||||||||||
Comprehensive loss
|
||||||||||||||||||||||||||||||||
Net loss applicable to controlling interests
|
$ | (370,276 | ) | | | | (370,276 | ) | | | (370,276 | ) | ||||||||||||||||||||
Unrealized gain on derivative instruments
|
14,480 | | | | | 14,480 | | 14,480 | ||||||||||||||||||||||||
Comprehensive loss applicable to controlling interests
|
(355,796 | ) | ||||||||||||||||||||||||||||||
Net income applicable to noncontrolling interests
|
516 | | | | | | 516 | 516 | ||||||||||||||||||||||||
Comprehensive loss including noncontrolling interests
|
$ | (355,280 | ) | |||||||||||||||||||||||||||||
Balance as of December 31, 2009
|
1,007 | $ | 1,005,600 | $ | (351 | ) | $ | (776,821 | ) | $ | 55,399 | $ | 2,775 | $ | 286,602 | |||||||||||||||||
Members contributions
|
60 | 60,000 | | | | | 60,000 | |||||||||||||||||||||||||
Amounts receivable from member
|
| | 208 | | | | 208 | |||||||||||||||||||||||||
Distributions to member for state tax withholding
|
| (424 | ) | | | | | (424 | ) | |||||||||||||||||||||||
Comprehensive income
|
||||||||||||||||||||||||||||||||
Net income applicable to controlling interests
|
$ | 38,769 | | | | 38,769 | | | 38,769 | |||||||||||||||||||||||
Unrealized gain on derivative instruments
|
50,323 | | | | | 50,323 | | 50,323 | ||||||||||||||||||||||||
Comprehensive income applicable to controlling interests
|
89,092 | |||||||||||||||||||||||||||||||
Net income applicable to noncontrolling interests
|
260 | | | | | | 260 | 260 | ||||||||||||||||||||||||
Comprehensive income including noncontrolling interests
|
$ | 89,352 | ||||||||||||||||||||||||||||||
Balance as of December 31, 2010
|
1,067 | $ | 1,065,176 | $ | (143 | ) | $ | (738,052 | ) | $ | 105,722 | $ | 3,035 | $ | 435,738 | |||||||||||||||||
The accompanying notes are an integral part of these
consolidated financial statements.
7
CONSOLIDATED
FINANCIAL STATEMENTS
NFR ENERGY LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
NFR ENERGY LLC
CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
For the Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Cash flows from operating activities:
|
||||||||||||
Net income (loss), including noncontrolling interest
|
$ | 39,029 | $ | (369,760 | ) | $ | (401,489 | ) | ||||
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
|
||||||||||||
Depletion, depreciation and amortization
|
52,490 | 44,813 | 34,299 | |||||||||
Impairments
|
1,711 | 407,294 | 415,843 | |||||||||
Loss on sale of asset
|
1,138 | 8,569 | | |||||||||
Bad debt expense
|
18 | 93 | | |||||||||
Accretion expense
|
493 | 407 | 215 | |||||||||
Accrued interest expense
|
11,953 | (142 | ) | | ||||||||
Rent expense and amortization of deferred rent
|
(321 | ) | 120 | | ||||||||
Amortization of deferred financing costs
|
4,325 | 1,083 | 346 | |||||||||
(Gain) loss on derivative instruments
|
(1,672 | ) | (3,793 | ) | 1,355 | |||||||
Amortization of option premium
|
3,239 | 3,918 | 4,197 | |||||||||
Amortization of prepaid expenses
|
1,762 | 2,374 | | |||||||||
Gain on bargain purchase
|
(372 | ) | | | ||||||||
Non cash distributions to member(s)
|
(424 | ) | (375 | ) | (614 | ) | ||||||
Changes in operating assets and liabilities:
|
||||||||||||
Decrease (increase) in accounts receivable
|
3,610 | 275 | (19,806 | ) | ||||||||
Increase in other assets
|
(5,393 | ) | (10,895 | ) | (65,369 | ) | ||||||
(Decrease) increase in accounts payable and accrued liabilities
|
(5,871 | ) | (1,277 | ) | 48,340 | |||||||
Net cash provided by operating activities
|
105,715 | 82,704 | 17,317 | |||||||||
Cash flows from investing activities:
|
||||||||||||
Oil and gas property additions
|
(335,073 | ) | (311,689 | ) | (448,473 | ) | ||||||
Cash received from insurance proceeds
|
2,343 | | | |||||||||
Gas processing equipment additions
|
(246 | ) | (366 | ) | (35,586 | ) | ||||||
Other asset additions
|
(425 | ) | (1,511 | ) | (3,021 | ) | ||||||
Cash received from sale of assets
|
8,012 | 5,584 | | |||||||||
Net cash used in investing activities
|
(325,389 | ) | (307,982 | ) | (487,080 | ) | ||||||
Cash flows from financing activities:
|
||||||||||||
Borrowings from revolving credit facility
|
176,500 | 243,500 | 269,250 | |||||||||
Proceeds from issuance of senior notes
|
345,597 | | | |||||||||
Debt repayments
|
(347,000 | ) | (167,500 | ) | (200,750 | ) | ||||||
Deferred financing costs
|
(13,683 | ) | (3,633 | ) | (1,179 | ) | ||||||
Capital contributions
|
60,208 | 151,752 | 367,745 | |||||||||
Distribution noncontrolling interests
|
| (475 | ) | | ||||||||
Net cash provided by financing activities
|
221,622 | 223,644 | 435,066 | |||||||||
Net increase (decrease) in cash and cash equivalents
|
1,948 | (1,634 | ) | (34,697 | ) | |||||||
Cash and cash equivalents, beginning of period
|
2,489 | 4,123 | 38,820 | |||||||||
Cash and cash equivalents, end of period
|
$ | 4,437 | $ | 2,489 | $ | 4,123 | ||||||
The accompanying notes are an integral part of these
consolidated financial statements.
8
1. | Organization |
NFR Energy LLC (NFR or the Company) was established as a
Delaware limited liability company in July 2006. Ramshorn
Investments, Inc. (Ramshorn), a wholly owned subsidiary of
Nabors Industries Ltd. (Nabors), and First Reserve Corporation
(First Reserve) have formed NFR as a joint venture to invest in
oil and natural gas exploration opportunities within the onshore
U.S. market. Ramshorn and First Reserve each committed
$500 million in equity. Operations of the Company commenced
in 2007. Nabors is one of the largest land drilling contractors
in the world, conducting drilling operations and providing well
and other services in the U.S. and internationally. First
Reserve was founded in 1983 and is the oldest and largest
private equity firm specializing in the energy industry.
Additional equity commitments were made by certain members of
NFR management and the Companys board of representatives
(the Members).
The Company is operating in one segment and is pursuing
development and exploration projects in a variety of forms
including operated and non-operated working interests, joint
ventures, farm-outs, and acquisitions, including conventional
and unconventional resources. NFR is a holding company within
which it conducts its operations through, and its operating
assets are owned by its subsidiaries.
On November 5, 2010, the Company formed NFR Holdings LLC as
a Delaware limited liability company (NFR Holdings),
at which time NFR Holdings formed NFR Holdings II, LLC as a
Delaware limited liability company (NFR Holdings
II), and NFR Holdings II formed NFR Merger Sub LLC,
as a Delaware limited liability company (Merger
Sub). Effective November 5, 2010, Merger Sub merged
into the Company, with the Company being the surviving entity
(the Merger) and all of the membership interests of
the Company were converted into membership interests in NFR
Holdings. In addition to membership interests, all incentive
units are maintained and held by NFR Holdings. As a consequence
of the Merger, NFR Holdings II LLC is now the single member
owner of NFR Energy LLC. The change in legal structure will have
no direct impact on the financial statements of the Company,
except for the change in reference from Members Capital to
Members Capital, Amounts receivable from
members to Amounts receivable from member and
Non cash distributions to members to Non cash
distributions to member.
2. | Significant Accounting Policies |
Basis
of Presentation
The Company presents its consolidated financial statements in
accordance with U.S. generally accepted accounting
principles (GAAP). The accompanying consolidated financial
statements include NFR and its subsidiaries. All significant
intercompany transactions have been eliminated.
For comparative purposes, amounts in 2008 for noncontrolling
interests have been adjusted to reflect the retroactive
application of Accounting Standards Codification (ASC) 810 to
conform to the current periods presentation. Certain other
reclassifications have been made to prior periods to conform to
the current presentation.
Change
in Accounting Method
In January 2010 the Financial Accounting Standard Board (FASB)
issued Accounting Standards Update
2010-03 (ASU
2010-03),
Extractive Industries Oil and Gas, which
conforms the authoritative guidance to the requirements of the
new Securities Exchange Commission (SEC) rules released in
December 2008 Modernization of Oil and Gas Reporting
and are effective December 31, 2009. The principle
revisions under the new FASB and SEC authoritative guidance
include changing the manner in which oil and gas reserves are
estimated as well as the manner in which prices are determined
to calculate the ceiling limit on capitalized oil and gas costs.
These changes will result in future amounts of depreciation,
depletion and amortization (DD&A) being different from what
would have been recorded if the new rules had not been mandated.
This
9
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
change in accounting has been treated in these financial
statements as a change in accounting principle that is
inseparable from a change in accounting estimate. As noted
below, reserves and discounted cash flows prepared using the new
rules were used in the calculation of DD&A for the fourth
quarter of 2009 and the ceiling test at December 31, 2010
and 2009.
Cash
and Cash Equivalents
All highly liquid investments purchased with an initial maturity
of three months or less are considered to be cash equivalents.
Concentration
of Credit Risk
The Companys receivables are comprised of oil and natural
gas revenue receivables. The amounts are due from a limited
number of entities; therefore, the collectability is dependent
upon the general economic conditions of a few purchasers. The
Company regularly reviews collectability and establishes the
allowance for doubtful accounts as necessary using the specific
identification method. The receivables are not collateralized.
Inventory
Inventory, which is included in prepaid expenses and other,
consists principally of tubular goods, spare parts, and
equipment, that is used in our drilling operations. The
inventory balance, net of impairments, was $9.3 million and
$27.1 million for 2010 and 2009, respectively. Inventory is
stated at the lower of weighted-average cost or market. In 2009,
the Company revamped its drilling program and moved to a
horizontal program due to improved economics versus a vertical
program, leaving it with inventory not properly designed for its
horizontal drilling activities, in effect, rendering it
obsolete. As of December 31, 2010 and December 31,
2009, the total impairments relating to obsolete inventory was
$1.7 million and $21.3 million, included in
Impairments in the consolidated statements of
operations.
Oil
and Natural Gas Properties and Equipment
The Company uses the full cost method of accounting for its
investment in oil and natural gas properties. Under this method,
the Company capitalizes all acquisition, exploration, and
development costs incurred for the purpose of finding oil and
natural gas reserves, including salaries, benefits, and other
internal costs directly attributable to these activities. The
Company capitalized $3.5 million, $3.3 million and
$1.5 million of internal costs in 2010, 2009 and 2008,
respectively. Costs associated with production and general
corporate activities, however, are expensed in the period
incurred. The Company also includes the present value of its
dismantlement, restoration, and abandonment costs within the
capitalized oil and natural gas property balance (see
Asset Retirement Obligation below). Unless a
significant portion of the Companys proved reserve
quantities is sold (greater than 25%), proceeds from the sale of
oil and natural gas properties are accounted for as a reduction
to capitalized costs, and gains and losses are not recognized
unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves of
oil and natural gas.
Depletion of exploration and development costs and depreciation
of production equipment is computed using the
units-of-production
method based upon estimated proved oil and natural gas reserves.
The costs of unproved properties are withheld from the depletion
base until such time as they are either developed or abandoned.
The properties are reviewed on a quarterly basis for impairment,
and if impaired, are reclassified to proved property and
included in the ceiling test and depletion calculations.
Under the full cost method of accounting, a ceiling test is
performed on a quarterly basis. The full cost ceiling test is an
impairment test prescribed by SEC
Regulation S-X
Rule 4-10.
The ceiling test determines a limit on the book value of oil and
natural gas properties. The capitalized costs of proved oil and
natural gas
10
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
properties, net of accumulated DD&A, may not exceed the
estimated future net cash flows from proved oil and natural gas
reserves, excluding future cash outflows associated with
settling asset retirement obligations that have been accrued on
the balance sheets, using prices based on the prior twelve month
period for 2010 and 2009 and prices in effect at the end of the
period for periods ended before December 31, 2009, held
flat for the life of production, discounted at 10%, plus the
cost of unevaluated properties and major development projects
excluded from the costs being amortized. If capitalized costs
exceed this limit, the excess is charged to expense and
reflected as Accumulated depletion, depreciation and
amortization.
In December 2008, the SEC adopted major revisions to its rules
governing oil and natural gas company reporting requirements.
The new rules include provisions that permit the use of new
technologies to determine proved reserves, and allow companies
to disclose their probable and possible reserves to investors in
SEC documents outside of the financial statements. The previous
rules limited disclosure to only proved reserves. The new rules
also require companies that have an audit performed on their
reserves to report the independence and qualifications of the
reserve auditor, and file the reserve engineers reports
when a third party reserve engineer is relied upon to prepare
reserve estimates. The new rules also require that oil and
natural gas reserves be reported and the full cost ceiling value
be calculated using an average price based upon the beginning of
the month for the prior twelve-month period. The new reporting
requirements are effective for reporting periods ending on or
after December 31, 2009. The FASB has issued ASU
2010-03
Extractive Industries Oil and Gas to
align its rules for oil and natural gas reserves estimation and
disclosure requirements with the SECs final rule. The
impact of these new rules is reflected below in the Supplemental
Oil and Gas Disclosure section.
The Company did not recognize any impairment charges relating to
oil and natural gas properties in 2010 as a result of an overall
increase in commodity prices in 2010. In first quarter of 2009,
the Company recognized an impairment of $155.9 million due
to a decrease in the period end price reserve estimates, as
required under the former SEC rules. In the fourth quarter of
2009, the Company recognized an impairment of
$230.1 million, as a result of the change in the reserve
estimates defined under the new SEC rules as noted above.
Gathering assets and related facilities, certain other property
and equipment, and furniture and fixtures are depreciated using
the straight-line method based on the estimated useful lives of
the respective assets, generally ranging from 3 to
30 years. Leasehold improvements are amortized over the
shorter of their economic lives or the lease term. Repairs and
maintenance costs are expensed in the period incurred.
The Companys DD&A expense on our oil and natural gas
properties is calculated each quarter utilizing period end
reserve quantities. The new SEC oil and gas reserves measurement
and disclosure rules that went into effect as of
December 31, 2009 impacted our DD&A expense for the
fourth quarter of 2009, increasing DD&A expense by
$1.7 million, or $0.11 per mcfe, for the quarter and year
ended December 31, 2009.
During 2010, the Company received insurance proceeds of
$2.3 million which were netted with the replacement costs
recognized in oil and gas properties.
Capitalized
Interest
The Company capitalizes interest costs to oil and natural gas
properties on expenditures made in connection with exploration
and development projects that are not subject to current
depletion. Interest is capitalized only for the period that
activities are in progress to bring these projects to their
intended use. The Company capitalized $5.9 million and
$3.7 million of interest during the years ended
December 31, 2010 and 2009, respectively.
11
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Leases
The Company accounts for leases with escalation clauses and rent
holidays on a straight-line basis in accordance with
ASC 840, Leases. The deferred rent expense liability
associated with future lease commitments was reported under the
caption Other long term obligations on our
consolidated balance sheet.
Derivative
Instruments and Hedging Activities
The Company uses derivative financial instruments to achieve a
more predictable cash flow from its oil and natural gas
production by reducing its exposure to price fluctuations. Such
derivative instruments, which are placed with major financial
institutions who are participants in the Companys first
lien credit facility (the Credit Agreement) (see
Note 5) that the Company believes are minimal credit
risks, may take the form of forward contracts, futures
contracts, swaps, options, or basis swaps.
Substantially, with the exception of basis swaps, all of our
natural gas derivative contracts are settled based upon reported
New York Mercantile Exchange (NYMEX) prices. Our derivative
contracts are with multiple counterparties to minimize our
exposure to any individual counterparty and we have netting
arrangements with all of our counterparties that provide for
offsetting payables against receivables from separate hedging
arrangements with that counterparty. The oil and natural gas
reference prices, upon which the commodity derivative contracts
are based, reflect various market indices that have a generally
high degree of historical correlation with actual prices
received by the Company for its oil and natural gas production.
Our fixed-price swap, option, and collar agreements are used to
fix the sales price for our anticipated future oil and natural
gas production. Upon settlement, the Company receives a fixed
price for the hedged commodity and receives or pays our
counterparty a floating market price, as defined in each
instrument. The instruments are settled monthly. When the
floating price exceeds the fixed price for a contract month, the
Company pays our counterparty. When the fixed price exceeds the
floating price, our counterparty is required to make a payment
to the Company. The Company has designated these swap, option
and collar agreements as cash flow hedges.
The Company accounts for these activities pursuant to
ASC 815, Derivatives and Hedging (formerly
Statements of Financial Accounting Standards (SFAS) 133). This
statement establishes accounting and reporting standards
requiring that derivative instruments other than those that meet
the normal purchases and sales exception, be recorded on the
balance sheets as either an asset or liability measured at fair
value (which is generally based on information obtained from
independent parties). ASC 815 also requires that changes in fair
value be recognized currently in earnings unless specific hedge
accounting criteria are met. Hedge accounting treatment allows
unrealized gains and losses on cash flow hedges to be deferred
in accumulated other comprehensive income. Realized gains and
losses from the Companys oil and natural gas cash flow
hedges are generally recognized in gain (loss) on derivative
instruments located in operating income in the consolidated
statement of operations when the forecasted transaction occurs.
Gains and losses from the change in fair value of derivative
instruments that do not qualify for hedge accounting are
reported in current-period earnings as a gain (loss) on
derivative instruments located in other income in the
consolidated statement of operations. If at any time the
likelihood of occurrence of a hedged forecasted transaction
ceases to be probable, hedge accounting under
ASC 815 will cease on a prospective basis and all future
changes in the fair value of the derivative will be recognized
directly in earnings. Amounts recorded in accumulated other
comprehensive income prior to the change in the likelihood of
occurrence of the forecasted transaction will remain in
accumulated other comprehensive income until such time as the
forecasted transaction impacts earnings. If it becomes probable
that the original forecasted production will not occur, then the
derivative gain or loss would be reclassified from accumulated
other comprehensive income into earnings immediately. Hedge
effectiveness is measured at least quarterly based on the
relative changes in fair value between the derivative
instruments and the hedged item over time, and any
ineffectiveness is immediately reported as unrealized gain or
loss on derivative instruments in the consolidated statement of
operations.
12
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Deferred
Financing Costs
Deferred financing costs of approximately $13.6 million and
$3.6 million were incurred during 2010 and 2009,
respectively. Deferred financing costs in 2010 include costs
associated with the amendment of the Companys senior
secured revolving Credit Facility (the Credit
Facility) and the issuance of our 2017 Senior Notes.
Deferred financing costs in 2009 include costs to amend the
Credit Facility. Deferred financing costs are being amortized
over the life of the respective obligations.
Financial
Instruments
The Companys financial instruments including cash and cash
equivalents, accounts receivable, and accounts payable are
carried at cost, which approximates fair value due to the
short-term maturity of these instruments. Since considerable
judgment is required to develop estimates of fair value, the
estimates provided are not necessarily indicative of the amounts
the Company could realize upon the purchase or refinancing of
such instruments.
Asset
Retirement Obligation
The Company follows ASC 410, Asset Retirement and
Environmental Obligations. If a reasonable estimate of the
fair value of an obligation to perform site reclamation,
dismantle facilities or plug and abandon wells can be made, we
record a liability (an asset retirement obligation or ARO) on
our consolidated balance sheets and capitalize the present value
of the asset retirement cost in oil and natural gas properties
in the period in which the retirement obligation is incurred. In
general, the amount of an ARO and the costs capitalized will be
equal to the estimated future cost to satisfy the abandonment
obligation assuming the normal operation of the asset, using
current prices that are escalated by an assumed inflation factor
up to the estimated settlement date, which is then discounted
back to the date that the abandonment obligation was incurred
using an assumed cost of funds for our company. After recording
these amounts, the ARO is accreted to its future estimated value
using the same assumed cost of funds and the additional
capitalized costs are depreciated on a
unit-of-production
basis within the related full cost pool. The capitalized costs
associated with an ARO are included in the amortization base for
purposes of calculating the ceiling test.
The information below reconciles the value of the asset
retirement obligation:
For the Year Ended December 31, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Beginning Balance
|
$ | 8,155 | $ | 6,665 | ||||
Liabilities incurred
|
595 | 1,290 | ||||||
Liabilities settled
|
(32 | ) | (20 | ) | ||||
Change in estimate
|
| (187 | ) | |||||
Accretion expense
|
495 | 407 | ||||||
Ending Balance
|
$ | 9,213 | $ | 8,155 | ||||
Revenue
Recognition
The Company records revenues from the sales of natural gas and
crude oil when the production is produced and sold, and also
when collectability is ensured. The Company may have an interest
with other producers in certain properties, in which case the
Company uses the sales method to account for gas imbalances.
Under this method, revenue is recorded on the basis of natural
gas actually sold by the Company. The Company also reduces
revenue for other owners natural gas sold by the Company
that cannot be
13
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
volumetrically balanced in the future due to insufficient
remaining reserves. The Companys remaining over- and
under-produced gas balancing positions are considered in the
Companys proved oil and natural gas reserves. The Company
did not have any gas imbalances at December 31, 2010, 2009
or 2008.
Use of
Estimates
The preparation of the consolidated financial statements for the
Company in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from these estimates.
The Companys consolidated financial statements are based
on a number of significant estimates, including oil and natural
gas reserve quantities that are the basis for the calculation of
DD&A and impairment of oil and natural gas properties, and
timing and costs associated with its retirement obligations.
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 member. As
such, no recognition of federal or state income taxes for the
Company or its subsidiaries that are organized as limited
liability companies have been provided for in the accompanying
consolidated financial statements. Any uncertain tax position
taken by the member is not an uncertain position of the Company.
In accordance with the operating agreement of NFR, to the extent
possible without impairing the Companys ability to
continue to conduct its business and activities, and in order to
permit its member to pay taxes on the taxable income of the
Company, NFR would be required to make distributions to the
member in the amount equal to the estimated tax liability of
each member computed as if the member paid income tax at the
highest marginal federal and state rate applicable to an
individual resident of New York, New York, in the event that
taxable income is generated for the member. There was no taxable
income and therefore no distributions to the member in 2010,
2009 or 2008.
Recent
Accounting Pronouncements
In December 2010, the FASB issued Accounting Standards Update
2010-29,
Business Combinations: Disclosure of Supplementary Pro
Forma Information for Business Combinations (ASU
2010-29).
ASU 2010-29
clarifies that when presenting comparative pro forma financial
statements in conjunction with business combination disclosures,
revenue and earnings of the combined entity should be presented
as though the business combination that occurred during the
current year had occurred as of the beginning of the comparable
prior annual reporting period. In addition, the update requires
a description of the nature and amount of material, nonrecurring
pro forma adjustments included in pro forma revenue and earnings
that are directly attributable to the business combination. This
update is effective prospectively for business combinations that
occur on or after the beginning of the first annual reporting
period after December 15, 2010. As ASU
2010-29
relates to disclosure requirements, there will be no impact on
the Companys financial condition or results of operations.
In December 2010, the FASB issued Accounting Standards Update
2010-28,
Intangibles Goodwill and Other: When to
Perform Step 2 of the Goodwill Impairment Test for Reporting
Units with Zero or Negative Carrying Amounts (ASU
2010-28).
ASU 2010-28
requires step two of the goodwill impairment test to be
performed when the carrying value of a reporting unit is zero or
negative, if it is more likely than
14
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
not that a goodwill impairment exists. The requirements of this
update are effective for fiscal years beginning after
December 15, 2010. The Company does not currently have
goodwill.
In February 2010, the FASB issued ASU
No. 2010-09,
Amendments to Certain Recognition and Disclosure Requirements.
This update amends Subtopic
855-10 and
gives a definition to SEC filers, and requires SEC filers to
assess for subsequent events through the issuance date of the
financial statements. This amendment states that an SEC filer is
not required to disclose the date through which subsequent
events have been evaluated for a reporting period. The Company
adopted the provisions of ASU
2010-09 in
the period ended March 31, 2010.
In January 2010, the FASB issued ASU
No. 2010-03,
Oil and Gas Reserve Estimation and Disclosures, which aligns the
FASBs oil and gas reserve estimation and disclosure
requirements with the requirements in the Securities and
Exchange Commissions final rule, Modernization of the Oil
and Gas Reporting Requirements, which was issued on
December 31, 2008 and became effective for the year ended
December 31, 2009. We adopted the final rule and ASU
2010-03
effective December 31, 2009, as a change in accounting
principle that is inseparable from a change in accounting
estimate. Such a change is accounted for prospectively under the
authoritative accounting guidance. Comparative disclosures
applying the new rules for periods before the adoption of ASU
2010-03 and
the final rule are not required.
In January 2010, the FASB issued additional disclosure
requirements related to fair value measurements. The guidance
requires disclosure of transfers of assets and liabilities
between Level 1 and Level 2 in the fair value
measurement hierarchy, including the reasons for the transfers
and disclosure of major purchases, sales, issuances, and
settlements on a gross basis in the reconciliation of the assets
and liabilities measured under Level 3 of the fair value
measurement hierarchy. The guidance is effective in interim and
annual periods beginning after December 15, 2009, except
for the Level 3 reconciliation disclosures which are
effective for interim and annual periods beginning after
December 15, 2010. We adopted the provisions for the
quarter ending March 31, 2010, except for the Level 3
reconciliation disclosures included in Note 9, which we
will adopt in the quarter ending March 31, 2011. Adopting
the disclosure requirements for the quarter ending
March 31, 2010 did not have an impact on our financial
position or results of operations. We do not expect adoption of
the Level 3 reconciliation disclosures in 2011 to have any
impact on our financial position or results of operations.
In December 2008, the SEC issued a final rule, Modernization
of Oil and Gas Reporting, which is effective January 1,
2010 for reporting 2009 oil and gas reserve information. We
adopted the guidance as of December 31, 2009. In January
2010, the FASB issued ASU
2010-03
Extractive Industries Oil and Gas to
align its rules for oil and natural gas reserves estimation and
disclosure requirements with the SECs final rule.
3. | Significant Customers |
During the year ended December 31, 2010, purchases by two
companies exceeded 10% of the total oil and natural gas sales of
the Company. Purchases by Enbridge Pipeline (East Texas) LP and
PVR Midstream LLC accounted for approximately 22% and 23% of oil
and natural gas sales, respectively. During the year ended
December 31, 2009, purchases by one company exceeded 10% of
the total oil and natural gas sales of the Company. Purchases by
Enbridge Pipeline (East Texas) LP accounted for approximately
28% of total oil and natural gas sales. During the year ended
December 31, 2008, purchases by three companies exceeded
10% of the total oil and natural gas revenues of the Company.
Purchases by Enbridge Pipeline (East Texas) LP accounted for
approximately 33% of total oil and natural gas sales, purchases
by Riverbend Gas Gathering Company, LLC, accounted for
approximately 11% of total oil and natural gas sales, and
purchases by Woodlawn Pipeline Company, Inc., accounted for
approximately 10% of total oil and natural gas sales. The
15
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Company believes that the loss of any of the purchasers above
would not result in a material adverse effect on its ability to
market future oil and natural gas production.
4. | Property Acquisitions |
On October 7, 2010, NFR entered into an agreement to
purchase working interests in developed and undeveloped acreage
for an adjusted purchase price of $64.5 million. The
acquisition qualified as a business combination pursuant to
ASC 805. NFR recorded a fair value of $64.9, which resulted
in a bargain purchase gain of $0.4 million that was
recorded in the current periods earnings. The unaudited
pro forma results presented below have been prepared to give
effect to the acquisition on our results of operations as if it
had been consummated at the beginning of the comparable period
for the year ended December 31, 2009. The unaudited pro
forma results do not purport to represent what our actual
results of operations would have been if this acquisition had
been completed on such date or to project our results of
operations for any future date or period.
Year Ended |
Year Ended |
|||||||||||||||
December 31, 2010 | December 31, 2009 | |||||||||||||||
Actual | Pro Forma | Actual | Pro Forma | |||||||||||||
(In millions) | ||||||||||||||||
Pro Forma (unaudited )
|
||||||||||||||||
Total revenues
|
$ | 182.6 | $ | 192.1 | $ | 143.6 | $ | 156.0 | ||||||||
Total operating expenses
|
$ | 112.1 | $ | 116.9 | $ | 499.3 | $ | 498.4 | ||||||||
Net income (loss) applicable to controlling interests
|
$ | 38.8 | $ | 43.4 | $ | (370.3 | ) | $ | (357.0 | ) |
The following table summarizes the consideration paid and the
amounts of the assets acquired and liabilities assumed as of
December 31, 2010.
Year Ended |
||||
December 31, 2010 | ||||
(In millions) | ||||
Cash, net of accrued purchase price adjustments
|
$ | 64.5 | ||
Recognized amounts of identifiable assets acquired and
liabilities assumed:
|
||||
Proved developed and undeveloped properties
|
48.8 | |||
Unproved leasehold properties
|
16.4 | |||
Asset retirement obligation
|
(0.3 | ) | ||
Bargain purchase gain
|
(0.4 | ) | ||
Total identifiable net assets
|
$ | 64.5 | ||
In May 2010, NFR entered into an agreement to purchase working
interests in 16,339 net undeveloped acres that are
prospective for the Haynesville Shale formation in Harrison,
Panola and Rusk Counties, Texas, for $42.6 million. None of
the acreage was developed or proved at the time of acquisition.
In June 2009, NFR entered into an agreement to acquire the deep
rights (Haynesville Shale) with approximately 23,000 net
acres in East Texas for a cash purchase price of approximately
$60 million as adjusted in accordance with the purchase and
sale agreement. The acquisition closed on June 22, 2009.
None of the acreage was developed or proved at the time of
acquisition.
In August 2008, NFR entered into an agreement to acquire
interest in certain producing properties and undeveloped acreage
in the Bear Paw Basin, located in north central Montana for a
cash purchase price of approximately $221 million as
adjusted in accordance with the purchase and sale agreement. The
acquisition closed on October 3, 2008, and also included
membership interests in each of Lodge Creek Pipelines LLC,
16
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Willow Creek Gathering LLC, and Redrock Drilling LLC, which
collectively provide compression, transportation, gathering, and
drilling services to properties in the Bear Paw Basin acquired
by NFR.
In July 2008, NFR entered into an agreement and closed the
acquisition to acquire interests in certain producing properties
and oil, natural gas, and mineral leases and other mineral
rights in East Texas for a cash purchase price of approximately
$34 million.
In April 2008, NFR entered into a carry and earnings agreement
covering approximately 47,000 gross acres of oil, natural
gas, and mineral leases in East Texas. In accordance with the
carry and earnings agreement, NFR was committed to drill a
certain number of wells between April 1, 2008 and
December 31, 2012. The Company paid a disproportionate
share of drilling costs in exchange for earning an interest in
the respective acreage. In connection with the carry and
earnings agreement, NFR executed a $72 million performance
bond which was subsequently terminated upon the October 7,
2010 acquisition.
Additionally, during 2009 and 2008, NFR acquired leases for
acreage in the same areas as the acquisitions listed above for
the $6.3 million and $38.4 million for each of the
respective years.
Acquired properties that are considered to be business
combinations are recorded at their fair value. In determining
the fair value of the proved and unproved properties, the
Company prepares estimates of oil and natural gas reserves. The
Company estimates future prices to apply to the estimated
reserve quantities acquired and the estimated future operating
and development costs to arrive at the estimates of future net
revenues. For the fair value assigned to proved reserves, the
future net revenues are discounted using a market-based
weighted-average cost of capital rate determined appropriate at
the time of the acquisition. To compensate for inherent risks of
estimating and valuing unproved reserves, probable and possible
reserves are reduced by additional risk-weighting factors.
The results of each of the acquisitions are included in the
accompanying consolidated statement of operations since the
respective date of purchase.
Total costs incurred for property acquisitions for 2010 and 2009
were approximately $129.0 million and $69.0 million
respectively (excluding related asset retirement costs), of
which approximately $68.8 million and $62.7 million
related to unproved properties and $60.2 and $0 related to
proved property acquisitions. The Company incurred
$238.8 million and $252.8 million in development
costs, for 2010 and 2009 respectively. All development related
costs were included in proved properties. The Company incurred
exploration costs of $0.2 million and $2.3 million in
2010 and 2009, respectively.
The unproved costs associated with the Companys drilling
projects will be transferred to proved properties as the wells
are drilled or impaired.
5. | Long-Term Debt |
Senior
Notes
On February 12, 2010, we and our subsidiary NFR Energy
Finance Corporation co-issued $200 million in
9.75% senior unsecured notes due 2017 (the 2017
Notes) in a private placement to qualified institutional
buyers in accordance with Rule 144A under the Securities
Act of 1933 and to persons outside the United States in
compliance with Regulation S of the Securities Act of 1933.
The 2017 Notes bear interest at a rate of 9.75% per annum,
payable semi-annually on February 15 and August 15 each year
commencing August 15, 2010. The 2017 Notes were issued at
98.73% of par. In conjunction with the issuance of the 2017
Notes, the Company recorded a discount of $2.53 million to
be amortized over the remaining life of the 2017 Notes utilizing
the simple interest method. The remaining unamortized discount
was $2.21 million at December 31, 2010. The 2017 Notes
were issued under and are governed by an indenture dated
February 12, 2010 between
17
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the Company, NFR Energy Finance Corporation, the Bank of New
York Mellon Trust Company, N.A. as trustee, and the
Companys subsidiaries named therein as guarantors.
All of our domestic restricted subsidiaries that guarantee our
Credit Facility (other than NFR Energy Finance Corporation) have
guaranteed the 2017 Notes on a senior unsecured basis. We
utilized the net proceeds from the sale to repay in full our
second lien term loan facility, including the associated
prepayment premium, which had an outstanding balance of
$50.0 million, and to repay approximately
$138.0 million in outstanding borrowings under our Credit
Facility, which had a balance of approximately
$214.5 million as of December 31, 2009. The second
lien term loan was paid in full and extinguished on
February 12, 2010. The Company paid $3.1 million in
early termination fees associated with the repayment of the
second lien term loan facility. Additionally, the Company
expensed $1.8 million of accumulated deferred financing
costs associated with the second lien. Both the early
termination fee and the amortization of deferred financing costs
are included in Interest expense on the Statement of
Operations.
On April 14, 2010, the Company issued an additional
$150 million in senior notes at 9.75% due 2017. The
additional notes were issued at 98.75% of par and bear interest
at a rate of 9.75% per annum, payable semi-annually on February
15 and August 15 of each year commencing August 15, 2010.
The additional notes were issued under the same indenture as the
2017 Notes issued on February 12, 2010. The Company
recorded a discount of $1.87 million to be amortized over
the remaining life of the 2017 Notes utilizing the simple
interest method. The remaining unamortized discount was
$1.63 million at December 31, 2010. Proceeds were used
to repay the entire outstanding balance under our Credit
Facility, with the remainder applied to the balance of the
purchase price for the May 2010 acquisition in East Texas
(Note 4), and to provide working capital for general
corporate purposes.
We may redeem the 2017 Notes, in whole or in part, at any time
on or after February 15, 2014, at a redemption price
(expressed as a percentage of principal amount) set forth in the
following table plus accrued and unpaid interest, if any, to the
applicable redemption date, if redeemed during the twelve-month
period beginning on February 15 of the years indicated below:
Year | Percentage | |||
2014
|
104.875 | |||
2015
|
102.438 | |||
2016
|
100.000 |
At any time before February 15, 2013, we may redeem up to
35% of the aggregate principal amount of the 2017 Notes issued
under the indenture with the net cash proceeds of one or more
equity offerings at a redemption price equal to 109.750% of the
principal amount of the notes to be redeemed, plus accrued and
unpaid interest to the date of such redemption; provided that:
at least 50% of the aggregate principal amount of the notes
remains outstanding immediately after the occurrence of such
redemption; and such redemption occurs within 180 days of
the date of the closing of any such equity offering.
In addition, we may redeem some or all of the 2017 Notes prior
to February 15, 2014 at a redemption price equal to 100% of
the principal amount thereof, plus accrued and unpaid interest
to the date of such redemption, plus a make-whole
premium equal to the greater of (1) 1% of the principal
amount of such note or (2) the excess of (a) the
present value at such time of (i) the redemption price of
such note at February 15, 2014, plus (ii) all required
interest payments due on the 2017 Notes through
February 15, 2014, computed using a discount rate equal to
the yield of United States Treasury securities with a constant
maturity most nearly equal to the period from the redemption
date to February 15, 2014 plus 50 basis points, over
(b) the principal amount of such note. Each holder of the
notes will also be entitled to require us to repurchase all or a
portion of its notes at a purchase price equal to 101% of the
principal amount thereof, plus accrued and unpaid interest to
the date of such repurchase upon a change of control.
18
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The indenture governing the 2017 Notes contains covenants that,
among other things, limit our ability and the ability of our
restricted subsidiaries to incur additional indebtedness unless
the ratio of our adjusted consolidated EBITDA to our adjusted
consolidated interest expense over the trailing four fiscal
quarters will be at least 2.0 to 1.0 (subject to exceptions for
borrowings within certain limits under our Credit Facility); pay
dividends or repurchase or redeem equity interests; limit
dividends or other payments by restricted subsidiaries that are
not guarantors to us or our other subsidiaries; make certain
investments; incur liens; enter into certain types of
transactions with our affiliates; and sell assets or consolidate
or merge with or into other companies. However, if and for as
long as the 2017 Notes have an investment grade rating from
Standard & Poors Ratings Group, Inc. and
Moodys Investors Service, Inc., and no default or event of
default exists under the indenture, we will not be subject to
certain of the foregoing covenants.
First
Lien Revolving Credit Facility
On November 30, 2007, the Company entered into a first lien
revolving Credit Facility with a syndicate of banks. BNP Paribas
is the Credit Facilitys administration agent. On
January 27, 2010, the Company amended and restated the
Credit Facility. The amendment extended the Credit
Facilitys maturity date from November 30, 2011 to
February 12, 2014. The amendment provided for a reduction
of the borrowing base upon the issuance of the 2017 Notes. The
amendment also changed the ratio of allowable debt to EBITDA
(leverage restriction) to 4.5 to 1.0 prior to
December 31, 2011. After December 31, 2011 but prior
to December 31 2012, the amendment reduces the ratio of total
debt to EBITDA to 4.25 to 1.0. After December 31, 2012 the
amendment limits the ratio to 4.0 to 1.0. On October 27,
2010, the Company again amended and restated the Credit
Facility. The amendment: (1) increased the commitments
under the facility from $400 million to $600 million,
(2) increased the borrowing base from $227.5 million
to $300 million, (3) eliminated the leverage
restriction, as described above, as a financial covenant, and
(4) eliminated the $100 million threshold on future
issuances by the Company of new senior unsecured and senior
subordinated debt securities, as a consequence of which, any
future issuance of new senior unsecured or senior subordinated
debt securities will reduce the borrowing base by 25 cents for
every dollar of such indebtedness.
Borrowings made under the Credit Facility are guaranteed by
first priority perfected liens and security interests on
substantially all assets of NFR and its wholly-owned domestic
subsidiaries and a pledge of 100% of NFRs ownership of
equity units of all non wholly owned domestic subsidiaries.
Interest on borrowings under the Credit Facility accrues at
variable interest rates at either a Eurodollar rate or an
alternate base rate (ABR). The Eurodollar rate is calculated as
London Interbank Offered Rate (LIBOR) plus an applicable margin
that varies from 2.25% (for periods in which NFR has utilized
less than 50% of the borrowing base) to 3.00% (for periods in
which NFR has utilized equal to or greater than 90% of the
borrowing base). The ABR is calculated as the greater of
(a) the Prime Rate, (b) the Federal Funds Effective
Rate plus 0.50%, or (c) Eurodollar rate on such day (or if
such day is not a business day, the immediately preceding
business day) plus 1.5%. The Company elects the basis of the
interest rate at the time of each borrowing. In addition, NFR
pays a commitment fee under the Credit Facility (quarterly in
arrears) for the amount that the aggregate commitments exceed
borrowings under the Credit Facility. The commitment fee varies
from 0.375% to 0.50% based on the percentage of the borrowing
base utilized.
Under the Credit Facility, the Company may request letters of
credit, provided that the borrowing base is not exceeded or will
not be exceeded as a result of issuance of the letter of credit.
There were no outstanding letters of credit on December 31,
2010 or December 31, 2009.
The Credit Facility requires the Company to comply with certain
financial covenants to maintain (a) a current ratio,
defined as a ratio of consolidated current assets (including the
unused amount of the total commitments under the Credit
Facility, but excluding noncash assets under ASC 815,
Derivatives and Hedging (formerly Statements of Financial
Accounting Standards (SFAS) 133), to consolidated current
liabilities
19
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(excluding noncash obligations under ASC 815 and the
current maturities under the Credit Facility, determined at the
end of each quarter), of not less than 1.0 to 1.0; (b) an
interest coverage ratio at the end of each quarter defined as a
ratio of EBITDA (as such terms are defined in the Credit
Facility) for the period of four fiscal quarters then ending to
interest expense for such period of not less than 2.5 to 1.0.
In addition, the Credit Facility contains covenants that
restrict, among other things, the Companys ability to
incur other indebtedness, create liens, or sell its assets;
merge with other entities; pay dividends; and make certain
investments.
At December 31, 2010 and December 31, 2009, NFR was in
compliance with its financial debt covenants under the Credit
Facility. At December 31, 2010, we were able to incur
approximately $206 million of secured indebtedness under
our Credit Facility, which amount represents the available
portion of our adjusted borrowing base of $300 million. At
December 31, 2009, we had available to us
$35.5 million remaining on our borrowing base of
$250 million.
In addition to the Credit Agreement, NFR entered into a second
lien term loan facility for $50 million on April 28,
2009. As of December 31, 2009, the outstanding balance
under our second lien term loan facility was $50 million,
with accrued interest at floating rates in accordance with the
Credit Agreement. The average annual interest rate for our term
loan borrowings for the twelve months ended December 31,
2009 was 4%, plus an applicable margin of 1,000 basis
points, or 14%.
As of December 31, 2010, the outstanding balance under our
Credit Facility was $94 million. Subsequent to the period
ended December 31, 2010 through the date of the report on
February 24, 2011, the Company has drawn an additional
$124 million and has repaid $40 million under our
Credit Facility.
6. | Members Capital |
The Company is authorized to issue one class of units to be
designated as Common Units. The Units are not
represented by certificates. All Common Units are issued at a
price equal to $1,000 per unit.
7. | Statement of Cash Flows |
During the year ended December 31, 2010, the Companys
noncash investing and financing activities consisted of the
following transactions:
| Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Companys oil and natural gas properties valued at $0.6 million. | |
| Additions to oil and natural gas properties of $23.4 million, included in accrued exploration and development. |
During the year ended December 31, 2009, the Companys
noncash investing and financing activities consisted of the
following transactions:
| Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Companys oil and natural gas properties valued at $1.1 million. | |
| Additions to oil and natural gas properties of $36.6 million, included in accrued exploration and development. |
During the year ended December 31, 2008, the Companys
noncash investing and financing activities consisted of the
following transactions:
| Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Companys oil and natural gas properties valued at $4.9 million. |
20
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| Additions to oil and natural gas properties of $21.1 million, included in accrued exploration and development. |
NFR paid $20.9 million, $11.8 million and
$5.5 million for interest during 2010, 2009 and 2008,
respectively.
8. | Derivative Financial Instruments |
The Company is exposed to risks associated with unfavorable
changes in the market price of natural gas as a result of the
forecasted sale of its production and uses derivative
instruments to hedge or reduce its exposure to certain of these
risks. During 2010, a portion of commodity derivative
instruments were designated as cash flow hedges and were subject
to cash flow hedge accounting under ASC 815. For the
remaining derivative instruments, the Company did not elect
hedge accounting for accounting purposes and, accordingly,
recorded the net change in the
mark-to-market
valuation of these derivative instruments in the consolidated
statement of operations.
The following swaps, basis swaps and costless collars were
outstanding with associated notional volumes and contracted
swap, floor, and ceiling prices that represent hedge weighted
average prices for the index specified as of December 31,
2010:
2011 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||
Swaps
|
||||||||||||||||||||
Volume (MMBTU)
|
9,932,456 | 8,317,098 | 10,338,731 | 10,413,793 | 5,217,687 | |||||||||||||||
Price
|
$ | 7.06 | $ | 7.22 | $ | 7.40 | $ | 7.34 | $ | 6.47 | ||||||||||
Collars
|
||||||||||||||||||||
Volume (MMBTU)
|
11,111,111 | 7,233,214 | | | | |||||||||||||||
Price (Floor/Ceiling)
|
$ | 6.00/$7.45 | $ | 6.00/$8.65 | | | |
2011 | 2012 | 2013 | 2014 | 2015 | ||||||||||||||||
Basis Swap, NYMEX East Texas (Houston Ship
Channel)
|
||||||||||||||||||||
Volume (MMBTU)
|
2,737,500 | 2,196,000 | 1,277,500 | | | |||||||||||||||
Contract differential(1)
|
$ | 0.10 - $0.15 | $ | 0.10 - $0.15 | $ | 0.11 - $0.15 | | | ||||||||||||
Basis Swap, NYMEX TEXOK (NGLP)
|
||||||||||||||||||||
Volume (MMBTU)
|
8,212,500 | 6,588,000 | 3,869,000 | | | |||||||||||||||
Contract differential(1)
|
$ | 0.21 - $0.26 | $ | 0.24 - $0.29 | $ | 0.21 - $0.25 | | |
(1) | Basis swaps settle based on NYMEX pricing minus a differential, which is then compared to Inside Federal Energy Regulatory Commission (FERC) for the index on which volumes are being hedged. |
For our energy commodity derivative instruments that were
designated as cash flow hedges, the portion of the change in the
value of derivative instruments that is effective in offsetting
changes in expected cash flows (the effective portion) is
reported as a component of accumulated other comprehensive
income, but only to the extent that they can later offset the
undesired changes in expected cash flows during the period in
which the hedged cash flows affect earnings. To the contrary,
the portion of the change in the value of derivative instruments
that is not effective in offsetting undesired changes in
expected cash flows (the ineffective portion), as well as any
component excluded from the assessment of the effectiveness of
the derivative instruments, is required to be recognized
currently in earnings. The Company excludes time value
associated with costless collars from the assessment of
effectiveness.
21
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company recorded a short term and a long term derivative
asset of $40.7 million and $68.3 million,
respectively, related to the fair value of the hedging
instruments prices on hedged volumes as of
December 31, 2010 after application of ASC 820,
Fair Value Measurements.
The table below provides data about the carrying values of
derivatives that are designated as cash flow hedge instruments
as of December 31, 2010.
Assets Derivatives | ||||||||||||
Derivatives Designated as Hedging Instruments | December 31, 2010 | December 31, 2009 | ||||||||||
(In thousands) | ||||||||||||
Fair Value | ||||||||||||
Current
|
Derivative Instruments | $ | 41,805 | $ | 30,719 | |||||||
Long term
|
Derivative Instruments | 69,309 | 28,683 | |||||||||
Total derivatives designated as hedging instruments
|
$ | 111,114 | $ | 59,402 | ||||||||
Assets Derivatives | ||||||||||||
Derivatives not Designated as Hedging Instruments | December 31, 2010 | December 31, 2009 | ||||||||||
(In thousands) | ||||||||||||
Fair Value | ||||||||||||
Current
|
Derivative Instruments | $ | | $ | 1,569 | |||||||
Long term
|
Derivative Instruments | 5 | | |||||||||
Total derivatives not designated as hedging instruments
|
$ | 5 | $ | 1,569 | ||||||||
Liabilities Derivatives | ||||||||||||
Derivatives not Designated as Hedging Instruments | December 31, 2010 | December 31, 2009 | ||||||||||
(In thousands) | ||||||||||||
Fair Value | ||||||||||||
Fair Value | ||||||||||||
Current
|
Derivative Instruments | $ | (1,056 | ) | $ | 198 | ||||||
Long term
|
Derivative Instruments | (1,042 | ) | 509 | ||||||||
Total derivatives not designated as hedging instruments
|
$ | (2,098 | ) | $ | 707 | |||||||
22
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the cash flow hedge gains and
losses and their locations on the Consolidated Balance Sheets as
of December 31, 2010 and 2009 and Consolidated Statement of
Operations for the year ended December 31, 2010 and 2009:
Amount of Loss |
||||||||||||||||
Amount of Gain |
Location of Gain |
Amount of Gain |
Recognized in Income |
|||||||||||||
Derivatives in Cash |
Recognized in |
Reclassified from |
Reclassified from |
Location of Loss in |
(Ineffective portion and |
|||||||||||
Flow Hedging |
Other Comprehensive |
Accumulated OCI |
Accumulated OCI into |
Other Income |
Amount Excluded from |
|||||||||||
Relationships | Income (OCI) | into Operating Income | Operating Income | Ineffective Hedges | Effectiveness Testing) | |||||||||||
(In thousands) | ||||||||||||||||
For the Year Ended December 31, 2010
|
||||||||||||||||
Derivative
Instruments |
$ | 105,629 |
Gain on derivative instruments |
$ | 55,305 |
Loss on derivative instruments |
$ | (533 | ) | |||||||
Total
|
$ | 105,629 | $ | 55,305 | $ | (533 | ) | |||||||||
For the Year Ended December 31, 2009
|
||||||||||||||||
Derivative
Instruments |
$ | 76,289 |
Gain on derivative instruments |
$ | 61,809 |
Loss on derivative instruments |
$ | (107 | ) | |||||||
Total
|
$ | 76,289 | $ | 61,809 | $ | (107 | ) | |||||||||
The following table summarizes the location in the Consolidated
Statement of Operations and amounts of gains and losses on
derivative instruments that do not qualify for hedge accounting
for the year ended December 31, 2010 and December 31,
2009:
Recognized in Other Income on |
||||||||||
Derivatives not Designated |
Location of Gain/(Loss) |
Derivatives for the Years Ended | ||||||||
as Hedging Instruments | Recognized in Other Income | December 31, 2010 | December 31, 2009 | |||||||
(In thousands) | ||||||||||
Derivative Instruments
|
Gain (loss) on Derivative Instruments |
$ | (1,121 | ) | $ | 187 | ||||
The consolidated accumulated other comprehensive income balance
was $105.7 million as of December 31, 2010, and
$55.4 million as of December 31, 2009. Approximately
$41.0 million of this total accumulated gain associated
with commodity price risk management activities as of
December 31, 2010, is expected to be reclassified into
earnings during the next twelve months (when the associated
forecasted sales and purchases are also expected to occur.)
See Note 13 Subsequent Events for
information regarding the restructuring of hedge positions
subsequent to December 31, 2010.
9. | Fair Value Measurements |
In September 2006, the FASB issued ASC 820, Fair Value
Measurement, which defines fair value, establishes a
framework for measuring fair value, and expands disclosures
about fair value measurements. The provisions of ASC 820
are effective January 1, 2008. The FASB has also issued
820-10-55,
which delayed the effective date of ASC 820 for
nonfinancial assets and liabilities, except for items that are
recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually), until
fiscal years beginning after November 15, 2008. Effective
January 1, 2008, the Company adopted ASC 820 as
discussed above and elected to defer the application thereof to
nonfinancial assets and liabilities in accordance with
820-10-55
until January 1, 2009.
23
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As discussed in Note 8, the Company utilizes derivative
instruments to hedge against the variability in cash flows
associated with the forecasted sale of its anticipated future
natural gas production. The Company generally hedges a
substantial, but varying, portion of anticipated natural gas
production for the next 12 to 60 months. These derivatives
are carried at fair value on the consolidated balance sheets.
As defined in ASC 820, fair value is the price that would
be received to sell an asset or paid to transfer a liability in
an orderly transaction between market participants at the
measurement date (exit price). The Company utilizes market data
or assumptions that market participants would use in pricing the
asset or liability, including assumptions about risk and the
risks inherent in the inputs to the valuation technique. These
inputs can be readily observable, market corroborated, or
generally unobservable. The Company classifies fair value
balances based on the observability of those inputs.
ASC 820 establishes a fair value hierarchy that prioritizes
the inputs used to measure fair value. The hierarchy gives the
highest priority to unadjusted quoted prices in active markets
for identical assets or liabilities (Level 1 measurement)
and the lowest priority to unobservable inputs (Level 3
measurement).
The three levels of the fair value hierarchy defined by
ASC 820 are as follows:
Level 1 Quoted prices are available in
active markets for identical assets or liabilities as of the
reporting date. Active markets are those in which transactions
for the asset or liability occur in sufficient frequency and
volume to provide pricing information on an ongoing basis.
Level 1 primarily consists of financial instruments such as
exchange-traded derivatives, marketable securities and listed
equities.
Level 2 Pricing inputs are other than
quoted prices in active markets included in level 1, which
are either directly or indirectly observable as of the reported
date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. These
models are primarily industry-standard models that consider
various assumptions, including quoted forward prices for
commodities, time value, volatility factors, and current market
and contractual prices for the underlying instruments, as well
as other relevant economic measures. Substantially all of these
assumptions are observable in the marketplace throughout the
full term of the instrument, can be derived from observable
data, or are supported by observable levels at which
transactions are executed in the marketplace. Instruments in
this category generally include non-exchange-traded derivatives
such as commodity swaps, basis swaps, options, and collars.
Level 3 Pricing inputs include
significant inputs that are generally less observable from
objective sources. These inputs may be used with internally
developed methodologies that result in managements best
estimate of fair value.
The following table sets forth, by level, within the fair value
hierarchy, the Companys financial assets and liabilities
that were accounted for at fair value as of December 31,
2010 and 2009. As required by ASC 820, financial assets and
liabilities are classified in their entirety based on the lowest
level of input that is significant to the fair value
measurement. The Companys assessment of the significance
of a particular input to the fair value measurement requires
judgment and may affect the valuation of fair value assets and
liabilities and their placement within the fair value hierarchy
levels.
Recurring Fair Value Measures | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(In millions) | ||||||||||||||||
As of December 31, 2010
|
||||||||||||||||
Derivative Assets
|
$ | | $ | 109.0 | $ | | $ | 109.0 | ||||||||
Derivative Liabilities
|
| | | | ||||||||||||
Total
|
$ | | $ | 109.0 | $ | | $ | 109.0 | ||||||||
24
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
As of December 31, 2009
|
||||||||||||||||
Derivative Assets
|
$ | | $ | 61.0 | $ | | $ | 61.0 | ||||||||
Derivative Liabilities
|
| (0.7 | ) | | (0.7 | ) | ||||||||||
Total
|
$ | | $ | 60.3 | $ | | $ | 60.3 | ||||||||
Derivatives listed above include commodity swaps, basis swaps,
and collars that are carried at fair value. The fair value
amounts on the consolidated balance sheets associated with the
Companys derivatives resulted from Level 2 fair value
methodologies, that is, the Company is able to value the assets
and liabilities based on observable market data for similar
instruments. The amounts above include the impact of netting
assets and liabilities with counterparties with which the right
of offset exists.
This observable data includes the forward curve for commodity
prices and interest rates based on quoted markets prices and
prospective volatility factors related to changes in commodity
prices, as well as the impact of our non-performance risk of the
counterparties which is derived using credit default swap values.
The Company measures fair value of its long term debt based on
quoted market prices with consideration given to the effect of
the Companys credit risk. The carrying value of the
Companys Credit Facility approximates fair value based on
current rates applicable to similar instruments. The following
table outlines the fair value of our 2017 Notes as of
December 31, 2010:
December 31, |
||||
2010 | ||||
(In thousands) | ||||
2017 Senior Notes
|
||||
Carrying Value
|
$ | 346,153 | ||
Fair Value
|
$ | 322,207 |
10. | Related-Party Transactions |
NFR paid $58.7 million, $42.2 million and
$16.1 million during 2010, 2009 and 2008, respectively, to
Nabors and its subsidiaries for drilling and other oilfield
services and the Company has recognized a liability on our
consolidated balance sheets as of December 31, 2010 and
2009 of $16.0 million and $1.6 million, respectively,
for these services.
NFR paid $0.8, $0.8 million and $1.2 million during
2010, 2009 and 2008, respectively, to Smith International, Inc.
(Smith), an oil and natural gas services company, for services
provided. A member of the Companys board of
representatives was the Chief Executive Officer, President, and
Chief Operating Officer of Smith through August of 2010.
11. | Commitments |
The Company leases approximately 55,000 square feet of
office space in downtown Houston, Texas, under a lease, which
terminates on May 13, 2013. The average rent for this space
over the life of the lease is approximately $0.9 million
per year. The Company has an option to extend its lease term for
an additional 60 months. As of December 31, 2010,
total future commitments are $2.0 million.
In December 2008, the Company signed a lease agreement to lease
approximately 11,000 square feet of office space in
downtown Denver, Colorado. The lease term began on June 1,
2009, and terminates on August 31, 2014. The average rent
for this space over the life of the lease is approximately
$0.2 million per
25
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
year. The Company has the option to extend its lease term for an
additional 60 months. As of December 31, 2010 total
future commitments are $0.8 million.
As part of our ongoing operations, we have contracted with
affiliates of Nabors to secure drilling rigs for drilling the
oil and natural gas well activity we expect to undertake. As of
December 31, 2010 total future commitments are
$109.2 million.
As of December 31, 2010, future minimum lease payments were
as follows (in millions):
Estimated Payments | ||||
(In millions) | ||||
Year Ending December 31,
|
||||
2011
|
$ | 46.4 | ||
2012
|
40.4 | |||
2013
|
25.1 | |||
2014
|
0.1 | |||
2015
|
| |||
Thereafter
|
| |||
$ | 112.0 | |||
Rent expense was approximately $0.7 million for the year
ended December 31, 2010, $1.1 million for the year
ended December 31, 2009 and $0.6 million for the year
ended December 31, 2008.
As is customary in the oil and natural gas industry, the Company
may at times have commitments in place to reserve or earn
certain acreage positions or wells. If the Company does not pay
such commitments, the acreage positions or wells may be lost.
The Company is at risk of lawsuits arising in the ordinary
course of our business. In Managements opinion, the
Company is not currently involved in any legal proceedings
which, individually or in aggregate, could have a material
effect on the financial condition, operations or cashflows of
the Company.
12. | Employee Benefit Plans |
The Company co-sponsors a 401(k) tax deferred savings plan (the
Plan) and makes it available to employees. The Plan is a defined
contribution plan, and the Company may make discretionary
matching contributions of up to 6% of each participating
employees compensation to the Plan. The contributions made
by the Company totaled approximately $643,000 during the year
ended December 31, 2010, $502,000 during the year ended
December 31, 2009, and $220,000 for the period ended
December 31, 2008.
13. | Subsequent Events |
Management has evaluated subsequent events through
February 24, 2011, which represents the date the
consolidated financial statements were issued.
On January 31, 2011 and February 8, 2011, the Company
closed on the acquisition of approximately 25,000 net acres
and interests in 33 producing wells located in Harrison and
Panola Counties, Texas for approximately $76.2 million.
Pursuant to ASC 805, the acquisition does qualify as
business combination; however, no further disclosure is feasible
as of the date of this report as the Company is still in the
process of determining the fair value.
On February 4, 2011, the Company received an equity
contribution from our member of $38 million. The
contribution was used to partially fund the aforementioned
acquisition of oil and gas properties in East Texas.
26
Consolidated
Financial Statements
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NFR Energy LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During February 2011, the Company restructured its hedge
portfolio through the execution of new financial commodity
derivative contracts, the restructuring of certain existing
derivative contracts and the liquidation of certain derivative
contract positions as follows:
| The Company liquidated and settled all existing hedge contracts covering volumes for the years 2014 and 2015. | |
| The Company re-couponed all volumes covered by the existing 2013 swap contracts from $7.40MMBTU to $6.0MMBTU. | |
| Added new swap contracts of 9.6BCF at an average price of $6.17MMBTU and 16.4BCF at an average price of $5.67MMBTU in 2011 and 2012, respectively. Proceeds from the liquidation and re-couponing actions taken in the bullets above were used to execute the new swap contracts that were added for 2011 and 2012. |
27
SUPPLEMENTAL
OIL AND GAS DISCLOSURE (UNAUDITED)
The following supplemental information regarding our natural gas
and oil producing activities is presented in accordance with the
requirements of
Section 932-235-50
of the ASC.
Costs
Incurred
The costs incurred in oil and natural gas acquisitions,
exploration and development activities were as follows:
For the Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Property acquisition costs, proved(1)
|
$ | 60,252 | $ | 6,297 | $ | 162,300 | ||||||
Property acquisition costs, unproved
|
68,758 | 62,725 | 86,353 | |||||||||
Exploration and extension well costs
|
218 | 2,263 | 1,692 | |||||||||
Development costs(1)
|
238,850 | 252,838 | 219,108 | |||||||||
Asset retirement costs
|
595 | 1,100 | 5,000 | |||||||||
Total Costs
|
$ | 368,673 | $ | 325,223 | $ | 474,453 | ||||||
(1) | Property acquisition and development costs for the year ended December 31, 2008 differ from the amounts reflected in the notes to our audited consolidated financial statements due in part to the inclusion in the amount shown in the notes of the acquisition costs related to the acquisition of certain gathering assets and to the recharacterization as development costs of a portion of the costs originally characterized as property acquisition costs. The Company reclassified and recharacterized these cost to reflect the total cost incurred for oil and gas producing activities during the period, versus costs relating solely to acquisitions that closed during the period, which are disclosed in Note 4. |
Capitalized
Costs
The capitalized costs in oil and natural gas properties were as
follows:
For the Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Proved properties
|
$ | 1,506,565 | $ | 1,177,439 | $ | 796,916 | ||||||
Unproved properties
|
218,172 | 178,625 | 233,924 | |||||||||
1,724,737 | 1,356,064 | 1,030,840 | ||||||||||
Accumulated depletion, depreciation and amortization
|
(925,874 | ) | (877,190 | ) | (450,101 | ) | ||||||
Net capitalized costs
|
$ | 798,863 | $ | 478,874 | $ | 580,739 | ||||||
28
SUPPLEMENTAL
OIL AND GAS DISCLOSURE
(UNAUDITED) (Continued)
Results
of Operations
Results of operations for oil and natural gas producing
activities, which exclude processing and other activities,
corporate general and administrative expenses, and straight-line
depreciation expense on non oil and gas assets, were as follows:
For the Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Revenues
|
$ | 130,123 | $ | 81,937 | $ | 96,015 | ||||||
Gain (loss) on derivative instruments
|
51,104 | 60,686 | (2,266 | ) | ||||||||
Operating costs:
|
||||||||||||
Lease operating expenses
|
18,982 | 18,520 | 13,249 | |||||||||
Workover expenses
|
848 | 482 | 843 | |||||||||
Marketing, gathering, transportation and other
|
11,792 | 6,031 | 3,107 | |||||||||
Production and ad valorem taxes
|
5,483 | 4,228 | 5,364 | |||||||||
Depletion, depreciation and amortization
|
48,685 | 41,137 | 32,993 | |||||||||
Impairments
|
1,711 | 407,295 | 415,843 | |||||||||
Results of operations
|
$ | 93,726 | $ | (335,070 | ) | $ | (377,650 | ) | ||||
Amortization rate per bcfe
|
$ | 3.32 | $ | (15.66 | ) | $ | (32.00 | ) |
Oil and
Natural Gas Reserves and Related Financial Data
Users of this information should be aware that the process of
estimating quantities of proved and proved
developed natural gas and crude oil reserves is very
complex, requiring significant subjective decisions in the
evaluation of all available geological, engineering and economic
data for each reservoir. The data for a given reservoir also may
change substantially over time as a result of numerous factors,
including additional development activity, evolving production
history and continual reassessment of the viability of
production under varying economic conditions. Consequently,
material revisions to existing reserve estimates may occur from
time to time.
The following tables set forth our total proved reserves and the
changes in our total proved reserves. These reserve estimates
are based in part on reports prepared by Miller and Lents, Ltd.
(Miller and Lents), independent petroleum engineers, utilizing
data compiled by us. In preparing its reports, Miller and Lents
evaluated properties representing all of our proved reserves at
December 31, 2010 and 2009 and approximately 94% of our
proved reserves at December 31, 2008. Our proved reserves
are located onshore in the United States. There are many
uncertainties inherent in estimating proved reserve quantities,
and projecting future production rates and the timing of future
development expenditures. In addition, reserve estimates of new
discoveries are more imprecise than those of properties with
production history. Accordingly, these estimates are subject to
change as additional information becomes available. Proved
reserves are the estimated quantities of natural gas, natural
gas liquids and oil that geoscience and engineering data
demonstrate with reasonable certainty to be economically
producible in future years from known oil and natural gas
reservoirs under existing economic conditions, operating methods
and government regulations at the end of the respective years.
Proved developed reserves are those reserves expected to be
recovered through existing wells with existing equipment and
operating methods.
Proved reserves as of December 31, 2010 were estimated
using the average of the historical unweighted
first-day-of-the-month
prices of oil and natural gas for the prior twelve months as
required under new SEC rules effective for fiscal years ending
on or after that date. Future prices actually received may
materially differ from current prices or the prices used in
making the reserve estimates. With respect to future development
costs and operating expenses, the Company derived estimates
using the current cost environment
29
SUPPLEMENTAL
OIL AND GAS DISCLOSURE
(UNAUDITED) (Continued)
at year end, which is consistent with both the current and
former SEC rules. The new SEC rules, which were adopted for the
year ended December 31, 2009, also contain new reserve
definitions and permit the use of new technologies to determine
proved reserves, if those technologies have been demonstrated to
result in reliable conclusions about reserve volumes. As
reflected in the table below, approximately 472.4 Bcfe of
the increase in our total estimated proved reserves from
December 31, 2008 to December 31, 2009 relates to the
application of the new SEC rules discussed herein.
Natural |
Natural Gas |
|||||||||||||||
Gas |
NGLS |
Oil |
Equivalents |
|||||||||||||
Estimated Proved Reserves | (Bcf) | (BBLS) | (BBLS) | (Bcfe) | ||||||||||||
December 31, 2007
|
270.1 | 6.3 | 2.5 | 323.1 | ||||||||||||
Revisions Performance
|
4.3 | | (0.4 | ) | 1.9 | |||||||||||
Revisions Pricing
|
(82.9 | ) | (2.0 | ) | (0.8 | ) | (99.9 | ) | ||||||||
Extensions, Additions and Discoveries
|
121.3 | 0.9 | 0.8 | 131.1 | ||||||||||||
Production
|
(10.2 | ) | (0.2 | ) | (0.1 | ) | (11.6 | ) | ||||||||
Purchases in Place
|
73.2 | 0.3 | 0.7 | 79.2 | ||||||||||||
Sales in Place
|
| | | | ||||||||||||
December 31, 2008
|
375.8 | 5.3 | 2.7 | 423.8 | ||||||||||||
Revisions Performance
|
14.1 | 0.3 | 0.2 | 17.0 | ||||||||||||
Revisions Pricing
|
(86.2 | ) | (1.3 | ) | (0.5 | ) | (96.9 | ) | ||||||||
Extensions, Additions and Discoveries (Old SEC Rules)
|
192.7 | 0.6 | 1.7 | 207.1 | ||||||||||||
Extensions, Additions and Discoveries (New SEC Rules)(1)
|
460.9 | 1.3 | 0.6 | 472.4 | ||||||||||||
Production
|
(18.9 | ) | (0.3 | ) | (0.1 | ) | (21.4 | ) | ||||||||
Purchases in Place
|
| | | | ||||||||||||
Sales in Place
|
| | | | ||||||||||||
December 31, 2009
|
938.4 | 5.9 | 4.6 | 1,002.0 | ||||||||||||
Revisions Performance(2)
|
(248.2 | ) | 3.9 | (0.9 | ) | (230.3 | ) | |||||||||
Revisions Pricing
|
8.8 | 0.1 | | 9.4 | ||||||||||||
Extensions, Additions and Discoveries
|
218.1 | 0.8 | 0.5 | 226.2 | ||||||||||||
Production
|
(24.8 | ) | (0.4 | ) | (0.1 | ) | (28.2 | ) | ||||||||
Purchases in Place(3)
|
220.8 | 0.9 | 0.8 | 230.3 | ||||||||||||
Sales in Place
|
(2.1 | ) | | (0.1 | ) | (2.7 | ) | |||||||||
December 31, 2010
|
1,111.0 | 11.2 | 4.8 | 1,206.7 | ||||||||||||
Estimated Proved Developed Reserves
|
||||||||||||||||
December 31, 2008
|
164.0 | 2.2 | 1.1 | 183.8 | ||||||||||||
December 31, 2009
|
214.5 | 2.3 | 1.3 | 236.0 | ||||||||||||
December 31, 2010
|
295.6 | 4.6 | 1.5 | 332.6 |
(1) | Primarily due to the application of revised definitions contained in the SECs new rules, particularly the definition of proved oil and natural gas reserves, which now permits the addition of undrilled locations beyond immediate offsets of producing wells that are supported by a determination, with reasonable certainty, of reservoir continuity. |
30
SUPPLEMENTAL
OIL AND GAS DISCLOSURE
(UNAUDITED) (Continued)
(2) | The decrease in the quantity of reserves due to the change in estimate is primarily attributable to reserve quantities associated with proved undeveloped locations included as proved in 2009 that were not included in the 2010 report as they could not be developed with a five year time horizon as prescribed under ASC 932. | |
(3) | Attributable to the purchase of oil and gas properties in East Texas as described in Note 4 in the Notes to Consolidated Financial Statements. |
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
The following information was developed utilizing procedures
prescribed by ASC 932, Disclosures about Oil and Gas
Producing Activities. The information is based on estimates
prepared by our petroleum engineering staff. The
standardized measure of discounted future net cash
flows should not be viewed as representative of the
current value of our proved oil and natural gas reserves. It and
the other information contained in the following tables may be
useful for certain comparative purposes, but should not be
solely relied upon in evaluating us or our performance.
In reviewing the information that follows, we believe that the
following factors should be taken into account:
| future costs and sales prices will probably differ from those required to be used in these calculations; | |
| actual production rates for future periods may vary significantly from the rates assumed in the calculations; | |
| a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and natural gas revenues. |
Under the standardized measure, future cash inflows were
estimated by using the average of the historical unweighted
first-day-of-the-month
prices of oil and natural gas for 2010 and by using year-end oil
and natural gas prices applicable to our reserves to the
estimated future production of year end proved reserves for 2009
and prior periods. Future cash inflows do not reflect the impact
of open hedge positions. Future cash inflows were reduced by
estimated future development and production costs based on year
end costs in order to arrive at net cash flows before tax. Use
of a 10% discount rate and year-end prices and costs are
required by ASC 932.
In general, management does not rely on the following
information in making investment and operating decisions. Such
decisions are based upon a wide range of factors, including
estimates of probable as well as proved reserves and varying
price and cost assumptions considered more representative of a
range of possible outcomes.
31
SUPPLEMENTAL
OIL AND GAS DISCLOSURE
(UNAUDITED) (Continued)
The standardized measure of discounted future net cash flows
from our estimated proved oil and natural gas reserves follows:
For the Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Future cash inflows
|
$ | 5,807,655 | $ | 3,915,847 | $ | 2,311,193 | ||||||
Less related future:
|
||||||||||||
Production costs
|
(1,513,149 | ) | (1,257,905 | ) | (760,534 | ) | ||||||
Development costs
|
(1,708,651 | ) | (1,307,147 | ) | (581,600 | ) | ||||||
Future net cash inflows
|
2,585,855 | 1,350,795 | 969,059 | |||||||||
10% annual discount for estimated timing of cash flows(1)
|
(2,000,181 | ) | (1,244,380 | ) | (688,632 | ) | ||||||
Standardized measure of discounted future net cash flows
|
$ | 585,674 | $ | 106,415 | $ | 280,427 | ||||||
(1) | The high effective discount factor is attributable to the negative present value factor, which is due to the addition of proved undeveloped properties that require a large amount of development costs. Additionally, these costs are weighted heavily in the first five years. |
A summary of the changes in the standardized measure of
discounted future net cash flows applicable to proved natural
gas and crude oil reserves follows:
For the Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Beginning Balance
|
106,415 | 280,427 | 326,481 | |||||||||
Revisions of previous estimates
|
||||||||||||
Changes in prices and costs
|
296,445 | (147,028 | ) | (253,529 | ) | |||||||
Changes in quantities
|
154,218 | 1,803 | 1,278 | |||||||||
Additions to proved reserves(1)
|
40,663 | (52,953 | ) | 26,513 | ||||||||
Purchases of reserves
|
10,960 | | 145,855 | |||||||||
Sales of reserves
|
(2,907 | ) | | | ||||||||
Accretion of discount
|
10,642 | 28,043 | 32,648 | |||||||||
Sales of oil and gas, net
|
(93,018 | ) | (52,302 | ) | (72,550 | ) | ||||||
Change in estimated future development costs
|
(113,582 | ) | 27,954 | 74,659 | ||||||||
Previously estimated development costs incurred
|
139,109 | 12,279 | 23,068 | |||||||||
Changes in rate of production and other, net
|
36,729 | 8,192 | (23,996 | ) | ||||||||
Net change
|
479,259 | (174,012 | ) | (46,054 | ) | |||||||
Ending Balance
|
585,674 | 106,415 | 280,427 | |||||||||
(1) | The negative value of additions in 2009 is attributable to a large number of wells that were proved as a result of the new SEC rules. Consistent with the new SEC rules, the Company only adds proved undeveloped reserves that will be developed within a five year time horizon. As a result, a large amount of future development costs are included in the present value calculation. Additionally, these costs are not discounted as heavily as costs in the later years, thus causing the total present value to be negative. |
32