Attached files
file | filename |
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8-K - Breitburn Energy Partners LP | v206528_8k.htm |
EX-23.1 - Breitburn Energy Partners LP | v206528_ex23-1.htm |
EX-99.2 - Breitburn Energy Partners LP | v206528_ex99-2.htm |
Exhibit
99.1
See
Item 8.01 of the accompanying Current Report on Form 8-K for an
explanation regarding the following disclosure. The following information
replaces the Report of Independent Registered Public Accounting Firm and
Consolidating Financial Statements and audited Notes thereto in Part
IV—Item 15 “—Exhibits and Financial Statement Schedules,” incorporated by
reference into Part II—Item 8 “ —Financial Statements and Supplementary
Data,” previously filed in the Annual Report on Form 10-K for the year
ended December 31, 2009 for BreitBurn Energy Partners L.P. (the “2009
10-K”). Except as set forth in this Exhibit 99.1, the 2009 10-K has not
been otherwise modified or updated.
- 1
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Report
of Independent Registered Public Accounting Firm
To the Board of Directors of BreitBurn
GP, LLC and Unitholders of BreitBurn Energy Partners L.P.:
In our
opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, partners' equity and cash flows present
fairly, in all material respects, the financial position of BreitBurn Energy
Partners L.P. and its subsidiaries ("the Partnership") at December 31, 2009 and
2008, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2009, in conformity with accounting
principles generally accepted in the United States of America. Also
in our opinion, the Partnership maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, based on
criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Partnership's management is
responsible for these financial statements, for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting, included in Management's Report to
Unitholders on Internal Control Over Financial Reporting (not presented herein)
appearing under Item 9A of the Partnership's 2009 Annual Report on Form
10-K. Our responsibility is to express opinions on these financial
statements and on the Partnership's internal control over financial reporting
based on our integrated audits. We conducted our audits in accordance with
the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audits to
obtain reasonable assurance about whether the financial statements are free of
material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the
financial statements included 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. Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audits
also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our
opinions.
As
discussed in Note 16 to the consolidated financial statements, the Partnership
changed the manner in which it accounts for recurring fair value measurements of
financial instruments in 2008.
A
partnership’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A partnership's internal
control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the partnership; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the partnership are being made only in accordance with
authorizations of management and directors of the partnership; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the partnership’s assets
that could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers
LLP
Los
Angeles, California
March 11,
2010 except with respect to our opinion on the consolidated financial statements
insofar as it relates to the presentation of financial information of guarantor
and non-guarantor subsidiaries discussed in Note 21, as to which the date is
December 23, 2010.
- 2
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BreitBurn
Energy Partners L.P. and Subsidiaries
Consolidated
Statements of Operations
Year Ended December 31,
|
||||||||||||
Thousands of dollars, except per unit amounts
|
2009
|
2008
|
2007
|
|||||||||
Revenues
and other income items:
|
||||||||||||
Oil,
natural gas and natural gas liquid sales
|
$ | 254,917 | $ | 467,381 | $ | 184,372 | ||||||
Gains
(losses) on commodity derivative instruments, net (note
16)
|
(51,437 | ) | 332,102 | (110,418 | ) | |||||||
Other
revenue, net (note 11)
|
1,382 | 2,920 | 1,037 | |||||||||
Total
revenues and other income items
|
204,862 | 802,403 | 74,991 | |||||||||
Operating
costs and expenses:
|
||||||||||||
Operating
costs
|
138,498 | 162,005 | 73,989 | |||||||||
Depletion,
depreciation and amortization (note 6)
|
106,843 | 179,933 | 29,422 | |||||||||
General
and administrative expenses
|
36,367 | 31,111 | 26,928 | |||||||||
Loss
on sale of assets
|
5,965 | - | - | |||||||||
Total
operating costs and expenses
|
287,673 | 373,049 | 130,339 | |||||||||
Operating
income (loss)
|
(82,811 | ) | 429,354 | (55,348 | ) | |||||||
Interest
and other financing costs, net
|
18,827 | 29,147 | 6,258 | |||||||||
Loss
on interest rate swaps (note 16)
|
7,246 | 20,035 | - | |||||||||
Other
income, net
|
(99 | ) | (191 | ) | (111 | ) | ||||||
Income
(loss) before taxes
|
(108,785 | ) | 380,363 | (61,495 | ) | |||||||
Income
tax expense (benefit) (note 7)
|
(1,528 | ) | 1,939 | (1,229 | ) | |||||||
Net
income (loss)
|
(107,257 | ) | 378,424 | (60,266 | ) | |||||||
Less:
Net income attributable to noncontrolling interest
|
(33 | ) | (188 | ) | (91 | ) | ||||||
Net
income (loss) attributable to the partnership
|
(107,290 | ) | 378,236 | (60,357 | ) | |||||||
General
Partner's interest in net loss
|
- | (2,019 | ) | (672 | ) | |||||||
Net
income (loss) attributable to limited partners
|
$ | (107,290 | ) | $ | 380,255 | $ | (59,685 | ) | ||||
Basic
net income (loss) per unit (note 14)
|
$ | (2.03 | ) | $ | 6.29 | $ | (1.83 | ) | ||||
Diluted
net income (loss) per unit (note 14)
|
$ | (2.03 | ) | $ | 6.28 | $ | (1.83 | ) |
The
accompanying notes are an integral part of these consolidated financial
statements.
- 3
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BreitBurn
Energy Partners L.P. and Subsidiaries
Consolidated
Balance Sheets
December 31,
|
||||||||
Thousands
|
2009
|
2008
|
||||||
ASSETS
|
||||||||
Current
assets:
|
||||||||
Cash
|
$ | 5,766 | $ | 2,546 | ||||
Accounts
and other receivables, net (note 2)
|
65,209 | 47,221 | ||||||
Derivative
instruments (note 16)
|
57,133 | 76,224 | ||||||
Related
party receivables (note 8)
|
2,127 | 5,084 | ||||||
Inventory
(note 9)
|
5,823 | 1,250 | ||||||
Prepaid
expenses
|
5,888 | 5,300 | ||||||
Intangibles
(note 10)
|
495 | 2,771 | ||||||
Other
current assets
|
- | 170 | ||||||
Total
current assets
|
142,441 | 140,566 | ||||||
Equity investments (note
11)
|
8,150 | 9,452 | ||||||
Property,
plant and equipment
|
||||||||
Oil
and gas properties (note 4)
|
2,058,968 | 2,057,531 | ||||||
Non-oil
and gas assets (note 4)
|
7,717 | 7,806 | ||||||
2,066,685 | 2,065,337 | |||||||
Accumulated
depletion and depreciation (note 6)
|
(325,596 | ) | (224,996 | ) | ||||
Net
property, plant and equipment
|
1,741,089 | 1,840,341 | ||||||
Other
long-term assets
|
||||||||
Intangibles
(note 10)
|
- | 495 | ||||||
Derivative
instruments (note 16)
|
74,759 | 219,003 | ||||||
Other
long-term assets
|
4,590 | 6,977 | ||||||
Total
assets
|
$ | 1,971,029 | $ | 2,216,834 | ||||
LIABILITIES
AND PARTNERS' EQUITY
|
||||||||
Current
liabilities:
|
||||||||
Accounts
payable
|
$ | 21,314 | $ | 28,302 | ||||
Book
overdraft
|
- | 9,871 | ||||||
Derivative
instruments (note 16)
|
20,057 | 10,192 | ||||||
Related
party payables (note 8)
|
13,000 | - | ||||||
Revenue
and royalties payable
|
18,224 | 20,084 | ||||||
Salaries
and wages payable
|
10,244 | 6,249 | ||||||
Accrued
liabilities
|
9,051 | 5,292 | ||||||
Total
current liabilities
|
91,890 | 79,990 | ||||||
Long-term
debt (note 12)
|
559,000 | 736,000 | ||||||
Deferred
income taxes (note 7)
|
2,492 | 4,282 | ||||||
Asset
retirement obligation (note 13)
|
36,635 | 30,086 | ||||||
Derivative
instruments (note 16)
|
50,109 | 10,058 | ||||||
Other
long-term liabilities
|
2,102 | 2,987 | ||||||
Total
liabilities
|
742,228 | 863,403 | ||||||
Equity:
|
||||||||
Partners'
equity (note 14)
|
1,228,373 | 1,352,892 | ||||||
Noncontrolling
interest (note 15)
|
428 | 539 | ||||||
Total
equity
|
1,228,801 | 1,353,431 | ||||||
Total
liabilities and equity
|
$ | 1,971,029 | $ | 2,216,834 | ||||
Limited
partner units outstanding
|
52,784 | 52,636 |
The
accompanying notes are an integral part of these consolidated financial
statements.
- 4
-
Consolidated
Statements of Cash Flows
Year Ended December 31,
|
||||||||||||
Thousands of dollars
|
2009
|
2008
|
2007
|
|||||||||
Cash
flows from operating activities
|
||||||||||||
Net
income (loss)
|
$ | (107,257 | ) | $ | 378,424 | $ | (60,266 | ) | ||||
Adjustments
to reconcile net income (loss) to cash flow from operating
activities:
|
||||||||||||
Depletion,
depreciation and amortization
|
106,843 | 179,933 | 29,422 | |||||||||
Unit-based
compensation expense
|
12,661 | 6,907 | 12,999 | |||||||||
Unrealized
(gain) loss on derivative instruments
|
213,251 | (370,734 | ) | 103,862 | ||||||||
Distributions
greater (less) than income from equity affiliates
|
1,302 | 1,198 | (28 | ) | ||||||||
Deferred
income tax
|
(1,790 | ) | 1,207 | (1,229 | ) | |||||||
Amortization
of intangibles
|
2,771 | 3,131 | 2,174 | |||||||||
Loss
on sale of assets
|
5,965 | - | - | |||||||||
Other
|
3,294 | 2,643 | 2,182 | |||||||||
Changes
in net assets and liabilities:
|
||||||||||||
Accounts
receivable and other assets
|
(6,313 | ) | 258 | (24,713 | ) | |||||||
Inventory
|
(4,573 | ) | 4,454 | 4,829 | ||||||||
Net
change in related party receivables and payables
|
2,957 | 32,688 | (39,202 | ) | ||||||||
Accounts
payable and other liabilities
|
(4,753 | ) | (13,413 | ) | 30,072 | |||||||
Net
cash provided by operating activities
|
224,358 | 226,696 | 60,102 | |||||||||
Cash
flows from investing activities (a)
|
||||||||||||
Capital
expenditures
|
(29,513 | ) | (131,082 | ) | (23,549 | ) | ||||||
Proceeds
from sale of assets, net
|
23,284 | - | - | |||||||||
Property
acquisitions
|
- | (9,957 | ) | (996,561 | ) | |||||||
Net
cash used by investing activities
|
(6,229 | ) | (141,039 | ) | (1,020,110 | ) | ||||||
Cash
flows from financing activities
|
||||||||||||
Issuance
of common units, net of discount
|
- | - | 663,338 | |||||||||
Purchase
of common units
|
- | (336,216 | ) | - | ||||||||
Distributions
to predecessor members concurrent with initial public
offering
|
- | - | 581 | |||||||||
Distributions
(b)
|
(28,038 | ) | (121,349 | ) | (60,497 | ) | ||||||
Proceeds
from the issuance of long-term debt
|
249,975 | 803,002 | 574,700 | |||||||||
Repayments
of long-term debt
|
(426,975 | ) | (437,402 | ) | (205,800 | ) | ||||||
Book
overdraft
|
(9,871 | ) | 7,951 | (116 | ) | |||||||
Long-term
debt issuance costs
|
- | (5,026 | ) | (6,362 | ) | |||||||
Net
cash provided (used) by financing activities
|
(214,909 | ) | (89,040 | ) | 965,844 | |||||||
Increase
(decrease) in cash
|
3,220 | (3,383 | ) | 5,836 | ||||||||
Cash
beginning of period
|
2,546 | 5,929 | 93 | |||||||||
Cash
end of period
|
$ | 5,766 | $ | 2,546 | $ | 5,929 |
(a)
Non-cash investing activity in 2007 was $700 million, reflecting the issuance of
21.348 million Common Units for the Quicksilver acquisition.
(b) 2009
and 2008 include distributions on equivalent units of $0.7 million and $2.3
million, respectively.
The
accompanying notes are an integral part of these consolidated financial
statements.
- 5
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BreitBurn
Energy Partners L.P. and Subsidiaries
Consolidated
Statements of Partners' Equity
Thousands
|
Common Units
|
Limited
Partners
|
General
Partner
|
Total
|
||||||||||||
Balance,
December 31, 2006
|
21,976 | $ | 174,395 | $ | 2,813 | $ | 177,208 | |||||||||
Issuance
of units (a)
|
21,348 | 700,000 | - | 700,000 | ||||||||||||
Private
offering investment (b)
|
23,697 | 663,338 | - | 663,338 | ||||||||||||
Distributions
|
- | (59,746 | ) | (751 | ) | (60,497 | ) | |||||||||
Unit-based
compensation
|
- | 5,133 | - | 5,133 | ||||||||||||
Net
loss
|
- | (59,685 | ) | (672 | ) | (60,357 | ) | |||||||||
Other
|
- | (17 | ) | - | (17 | ) | ||||||||||
Balance,
December 31, 2007
|
67,021 | $ | 1,423,418 | $ | 1,390 | $ | 1,424,808 | |||||||||
Redemption
of common units from predecessors (c)
|
(14,405 | ) | (336,216 | ) | - | (336,216 | ) | |||||||||
Distributions
|
- | (118,580 | ) | (427 | ) | (119,007 | ) | |||||||||
Distributions
paid on unissued units under incentive plans
|
- | (2,335 | ) | (7 | ) | (2,342 | ) | |||||||||
Unit-based
compensation
|
- | 7,383 | - | 7,383 | ||||||||||||
Net
income (loss)
|
- | 380,255 | (2,019 | ) | 378,236 | |||||||||||
Contribution
of general partner interest to the Partnership (d)
|
- | (1,063 | ) | 1,063 | - | |||||||||||
BreitBurn
Management purchase (e)
|
20 | - | - | - | ||||||||||||
Other
|
- | 30 | - | 30 | ||||||||||||
Balance,
December 31, 2008
|
52,636 | $ | 1,352,892 | $ | - | $ | 1,352,892 | |||||||||
Distributions
|
- | (27,371 | ) | - | (27,371 | ) | ||||||||||
Distributions
paid on unissued units under incentive plans
|
- | (667 | ) | - | (667 | ) | ||||||||||
Units
issued under incentive plans
|
148 | 7,488 | 7,488 | |||||||||||||
Unit-based
compensation
|
3,322 | - | 3,322 | |||||||||||||
Net
loss
|
- | (107,290 | ) | - | (107,290 | ) | ||||||||||
Other
|
- | (1 | ) | - | (1 | ) | ||||||||||
Balance,
December 31, 2009
|
52,784 | $ | 1,228,373 | $ | - | $ | 1,228,373 |
(a)
Reflects the issuance of Common Units for the Quicksilver
acquisition.
(b)
Reflects the issuance of Common Units in three private placements.
(c)
Reflects the purchase of Common Units from subsidiaries of
Provident.
(d)
General partner interests were purchased as of June 17, 2008.
(e)
Reflects issuance of Common Units to Co-CEOs in exchange for their interest in
BreitBurn Management.
The
accompanying notes are an integral part of these consolidated financial
statements.
- 6
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Notes
to Consolidated Financial Statements
Note
1. Organization
The
Partnership is a Delaware limited partnership formed on March 23, 2006. In
connection with our initial public offering in October 2006, BreitBurn Energy
Company L.P. (“BEC”), our Predecessor, contributed to us certain properties,
which included fields in the Los Angeles Basin in California and the Wind River
and Big Horn Basins in central Wyoming. In 2007, we acquired certain
interests in oil leases and related assets located in Florida for approximately
$110 million, assets located in California for approximately $93 million and
properties located in Michigan, Indiana and Kentucky from Quicksilver Resources
Inc. (“Quicksilver”) for approximately $1.46 billion (the “Quicksilver
Acquisition”).
Our
general partner is BreitBurn GP, a Delaware limited liability company, also
formed on March 23, 2006. The board of directors of our General Partner
has sole responsibility for conducting our business and managing our operations.
We conduct our operations through a wholly owned subsidiary, BOLP and BOLP’s
general partner BOGP. We own all of the ownership interests in BOLP and
BOGP.
Our
wholly owned subsidiary, BreitBurn Management, manages our assets and performs
other administrative services for us such as accounting, corporate development,
finance, land administration, legal and engineering. See Note 8 for
information regarding our relationship with BreitBurn Management.
Our
wholly owned subsidiary, BreitBurn Finance Corporation was incorporated on June
1, 2009 under the laws of the State of Delaware. BreitBurn Finance
Corporation is wholly owned by us, and has no assets or liabilities. Its
activities are limited to co-issuing debt securities and engaging in other
activities incidental thereto.
As of
December 31, 2009, the public unitholders, the institutional investors in our
private placements and Quicksilver owned 98.69 percent of the Common
Units. BreitBurn Corporation owned 690,751 Common Units, representing a
1.31 percent limited partner interest. We own 100 percent of the General
Partner, BreitBurn Management, BOLP and BreitBurn Finance
Corporation.
2.
Summary of Significant Accounting Policies
Principles
of consolidation
The
consolidated financial statements include our accounts and the accounts of our
wholly owned subsidiaries and our predecessor. Investments in affiliated
companies with a 20 percent or greater ownership interest, and in which we do
not have control, are accounted for on the equity basis. Investments in
affiliated companies with less than a 20 percent ownership interest, and in
which we do not have control, are accounted for on the cost basis.
Investments in which we own greater than 50 percent interest are
consolidated. Investments in which we own less than a 50 percent interest
but are deemed to have control or where we have a variable interest in an entity
where we will absorb a majority of the entity’s expected losses or receive a
majority of the entity’s expected residual returns or both, however, are
consolidated. The effects of all intercompany transactions have been
eliminated.
- 7
-
Basis
of Presentation
Our
financial statements are prepared in conformity with U.S. generally accepted
accounting principles. Certain items included in the prior year financial
statements have been reclassified to conform to the 2009
presentation.
In the
first quarter of 2009, we began classifying regional operation management
expenses as operating costs rather than general and administrative expenses to
better align our operating and management costs with our organizational
structure and to be more consistent with industry practices. As such, we
have revised classification of these expenses for the years ended December 31,
2008 and 2007, respectively. The reclassification did not affect
previously reported total revenues, net income or net cash provided by operating
activities. The following table reflects all classification changes for
the years ended December 31, 2008 and 2007, respectively:
Year Ended December 31,
|
||||||||
Thousands of dollars
|
2008
|
2007
|
||||||
Operating
costs
|
||||||||
As
previously reported
|
$ | 149,681 | $ | 70,329 | ||||
District
expense reclass from G&A
|
12,324 | 3,660 | ||||||
As
revised
|
$ | 162,005 | $ | 73,989 | ||||
G&A
expenses
|
||||||||
As
previously reported
|
$ | 43,435 | $ | 30,588 | ||||
District
expense reclass to operating costs
|
(12,324 | ) | (3,660 | ) | ||||
As
revised
|
$ | 31,111 | $ | 26,928 |
Use
of estimates
The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates. The financial statements are based on a number of significant
estimates including oil and gas reserve quantities, which are the basis for the
calculation of depletion, depreciation, amortization, asset retirement
obligations and impairment of oil and gas properties.
We
account for business combinations using the purchase method, in accordance with
Financial Accounting Standards Board (“FASB”) Accounting Standards Codification
(“ASC”) 805 “Business
Combinations.” We use estimates to record the assets and
liabilities acquired. All purchase price allocations are finalized within
one year from the acquisition date.
Business
segment information
ASC 280
“Segment Reporting”
establishes standards for reporting information about operating segments.
Segment reporting is not applicable because our oil and gas operating areas have
similar economic characteristics. We acquire, exploit, develop and produce
oil and natural gas in the United States. Corporate management administers
all properties as a whole rather than as discrete operating segments.
Operational data is tracked by area; however, financial performance is measured
as a single enterprise and not on an area-by-area basis. Allocation of
capital resources is employed on a project-by-project basis across our entire
asset base to maximize profitability without regard to individual
areas.
Revenue
recognition
Revenues
associated with sales of our crude oil and natural gas are recognized when title
passes from us to our customer. Revenues from properties in which we have
an interest with other partners are recognized on the basis of our working
interest (‘‘entitlement’’ method of accounting). We generally market most
of our natural gas production from our operated properties and pay our partners
for their working interest shares of natural gas production sold. As a
result, we have no material natural gas producer imbalance
positions.
- 8
-
Cash
and cash equivalents
We
consider all investments with original maturities of three months or less to be
cash equivalents. At December 31, 2009 and 2008 we had no such
investments.
Accounts
Receivable
Our accounts receivable are primarily
from purchasers of crude oil and natural gas and counterparties to our financial
instruments. Crude oil receivables are generally collected within 30 days
after the end of the month. Natural gas receivables are generally
collected within 60 days after the end of the month. We review all
outstanding accounts receivable balances and record a reserve for amounts that
we expect will not be fully recovered. Actual balances are not applied
against the reserve until substantially all collection efforts have been
exhausted.
At December 31, 2009, accounts
receivable also included a $4.3 million receivable from our insurance company
related to legal costs incurred during the lawsuit with Quicksilver and a $13.0
million receivable from our insurance company related to the settlement of the
lawsuit.
As of December 31, 2009, we did not
carry an allowance for doubtful accounts receivable.
During 2008 we terminated our crude oil
derivative instruments with Lehman Brothers due to their bankruptcy. On
October 21, 2009, we completed the transfer and sale of our claims in the
bankruptcy cases filed by Lehman Brothers Commodity Services Inc. and Lehman
Brothers Holdings Inc. (together referred to as Lehman Brothers), to a third
party. We recognized a $1.9 million gain reflected in gains and losses on
commodity derivative instruments on the consolidated statements of
operations. At December 31, 2008, we had an allowance of $4.6 million
related to the Lehman Brothers crude oil derivative contracts.
Inventory
Oil
inventories are carried at the lower of cost to produce or market price.
We match production expenses with crude oil sales. Production expenses
associated with unsold crude oil inventory are recorded as
inventory.
Investments
in Equity Affiliates
Income
from equity affiliates is included as a component of operating income, as the
operations of these affiliates are associated with the processing and
transportation of our natural gas production.
Property,
plant and equipment
Oil
and gas properties
We follow
the successful efforts method of accounting. Lease acquisition and
development costs (tangible and intangible) incurred relating to proved oil and
gas properties are capitalized. Delay and surface rentals are charged to
expense as incurred. Dry hole costs incurred on exploratory wells are
expensed. Dry hole costs associated with developing proved fields are
capitalized. Geological and geophysical costs related to exploratory
operations are expensed as incurred.
Upon sale
or retirement of proved properties, the cost thereof and the accumulated
depletion, depreciation and amortization (“DD&A”) are removed from the
accounts and any gain or loss is recognized in the statement of operations.
Maintenance and repairs are charged to operating expenses. DD&A of proved
oil and gas properties, including the estimated cost of future abandonment and
restoration of well sites and associated facilities, are generally computed on a
field-by-field basis where applicable and recognized using the
units-of-production method net of any anticipated proceeds from equipment
salvage and sale of surface rights. Other gathering and processing facilities
are recorded at cost and are depreciated using straight line, generally over 20
years.
- 9
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Non-oil
and gas assets
Buildings
and non-oil and gas assets are recorded at cost and depreciated using the
straight-line method over their estimated useful lives, which range from three
to 20 years.
Oil
and natural gas reserve quantities
Reserves
and their relation to estimated future net cash flows impact our depletion and
impairment calculations. As a result, adjustments to depletion are made
concurrently with changes to reserve estimates. We disclose reserve
estimates, and the projected cash flows derived from these reserve estimates, in
accordance with SEC guidelines. In 2009, our reserves disclosures were in
accordance with Release
No. 33-8995, “Modernization of Oil and Gas Reporting” (“Release
33-8995”), issued by the SEC in December, 2008 as well as ASC 932 which
incorporates the SEC release. The independent
engineering firms adhere to the SEC definitions when preparing their reserve
reports.
Asset
retirement obligations
We have
significant obligations to plug and abandon oil and natural gas wells and
related equipment at the end of oil and natural gas production operations.
The computation of our asset retirement obligations (“ARO”) is prepared in
accordance with ASC 410 “Asset
Retirement and Environmental Obligations.” This topic applies to
the fair value of a liability for an asset retirement obligation that is
recorded when there is a legal obligation associated with the retirement of a
tangible long-lived asset and the liability can be reasonably estimated.
Over time, changes in the present value of the liability are accreted and
expensed. The capitalized asset costs are depreciated over the useful
lives of the corresponding asset. Recognized liability amounts are based
upon future retirement cost estimates and incorporate many assumptions such as:
(1) expected economic recoveries of crude oil and natural gas, (2) time to
abandonment, (3) future inflation rates and (4) the risk free rate of interest
adjusted for our credit costs. Future revisions to ARO estimates will
impact the present value of existing ARO liabilities and corresponding
adjustments will be made to the capitalized asset retirement costs
balance.
Impairment
of assets
Long-lived
assets with recorded values that are not expected to be recovered through future
cash flows are written-down to estimated fair value in accordance with ASC 360
“Property, Plant and
Equipment.” Under ASC 360, a long-lived asset is tested for
impairment when events or circumstances indicate that its carrying value may not
be recoverable. The carrying value of a long-lived asset is not
recoverable if it exceeds the sum of the undiscounted cash flows expected to
result from the use and eventual disposition of the asset. If the carrying
value exceeds the sum of the undiscounted cash flows, an impairment loss equal
to the amount by which the carrying value exceeds the fair value of the asset is
recognized. Fair value is generally determined from estimated discounted
future net cash flows. For purposes of performing an impairment test, the
undiscounted future cash flows are based on total proved and risk-adjusted
probable and possible reserves and are forecast using five-year NYMEX forward
strip prices at the end of the period and escalated along with expenses and
capital starting year six thereafter at 2.5 percent per year. For
impairment charges, the associated property’s expected future net cash flows are
discounted using a rate of approximately ten percent. Reserves are calculated
based upon reports from third-party engineers adjusted for acquisitions or other
changes occurring during the year as determined to be appropriate in the good
faith judgment of management.
We assess
our long-lived assets for impairment generally on a field-by-field basis where
applicable. We did not record an impairment charge in 2009 or 2007.
Because of the low commodity prices that existed at year end 2008, we recorded
$51.9 million in impairments and $34.5 million in price related depletion and
depreciation adjustments. Price related adjustments to depletion and
depreciation in 2009 were immaterial. See Note 6 for a discussion of our
impairments and price related depletion and depreciation
adjustments.
Debt
issuance costs
The costs
incurred to obtain financing have been capitalized. Debt issuance costs
are amortized using the straight-line method over the term of the related
debt. Use of the straight-line method does not differ materially from the
“effective interest” method of amortization.
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Equity-based
compensation
ASC 718
“Compensation – Stock
Compensation” establishes standards for charging compensation expenses
based on fair value provisions. BreitBurn Management
has various forms of equity-based compensation outstanding under employee
compensation plans that are described more fully in Note 17. Awards
classified as equity are valued on the grant date and are recognized as
compensation expense over the vesting period. We recognize
equity-based compensation costs on a straight line basis over the annual vesting
periods. Awards classified as liabilities were revalued at each reporting
period and changes in the fair value of the options were recognized as
compensation expense over the vesting schedules of the awards.
Fair
market value of financial instruments
The
carrying amount of our cash, accounts receivable, accounts payable, related
party receivables and payables, and accrued expenses, approximate their
respective fair value due to the relatively short term of the related
instruments. The carrying amount of long-term debt approximates fair
value; however, changes in the credit markets at year-end may impact our ability
to enter into future credit facilities at similar terms.
Accounting
for business combinations
We have
accounted for all business combinations using the purchase method, in accordance
with ASC 805 “Business
Combinations.” Under the purchase method of accounting, a business
combination is accounted for at a purchase price based upon the fair value of
the consideration given, whether in the form of cash, assets, equity or the
assumption of liabilities. The assets and liabilities acquired are
measured at their fair values, and the purchase price is allocated to the assets
and liabilities based upon these fair values. The excess of the fair value
of assets acquired and liabilities assumed over the cost of an acquired entity,
if any, is allocated as a pro rata reduction of the amounts that otherwise would
have been assigned to certain acquired assets. We have not recognized any
goodwill from any business combinations.
Concentration
of credit risk
We maintain our cash accounts primarily
with a single bank and invest cash in money market accounts, which we believe to
have minimal risk. At times, such balances may be in excess of the Federal
Insurance Corporation insurance limit. As operator of jointly owned oil
and gas properties, we sell oil and gas production to U.S. oil and gas
purchasers and pay vendors on behalf of joint owners for oil and gas
services. We periodically monitor our major purchasers’ credit
ratings. We enter into commodity and interest rate derivative
instruments. Our derivative counterparties are all lenders under our
credit facility and we periodically monitor their credit ratings.
Derivatives
ASC 815
“Derivatives and
Hedging” establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and hedging activities. It requires the recognition of all
derivative instruments as assets or liabilities on our balance sheet and
measurement of those instruments at fair value. The accounting treatment
of changes in fair value is dependent upon whether or not a derivative
instrument is designated as a hedge and if so, the type of hedge. For
derivatives designated as cash flow hedges, changes in fair value are recognized
in other comprehensive income, to the extent the hedge is effective, until the
hedged item is recognized in earnings. Hedge effectiveness is measured
based on the relative changes in fair value between the derivative contract and
the hedged item over time. Any change in fair value resulting from
ineffectiveness, as defined by ASC 815, is recognized immediately in
earnings. Gains and losses on derivative instruments not designated as
hedges are currently included in earnings. The resulting cash flows are
reported as cash from operating activities. We currently do not designate
any of our derivatives as hedges for accounting purposes.
Effective
January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,”
now codified within ASC 820, “Fair Value Measurements and
Disclosures.” ASC 820 defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value
measurements. Fair value measurement under ASC 820 is based upon a
hypothetical transaction to sell an asset or transfer a liability at the
measurement date, considered from the perspective of a market participant that
holds the asset or owes the liability. The objective of fair value
measurement as defined in ASC 820 is to determine the price that would be
received in selling the asset or transferring the liability in an orderly
transaction between market participants at the measurement date. If there
is an active market for the asset or liability, the fair value measurement shall
represent the price in that market whether the price is directly observable or
otherwise obtained using a valuation technique.
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Income
taxes
Our
subsidiaries are mostly partnerships or limited liability companies treated as
partnerships for federal tax purposes with essentially all taxable income or
loss being passed through to the members. As such, no federal income tax
for these entities has been provided.
We have
three wholly owned subsidiaries, which are subject to corporate income
taxes. We account for the taxes associated with one entity in accordance
with ASC 740, “Income
Taxes.” Deferred income taxes are recorded under the asset and
liability method. Where material, deferred income tax assets and
liabilities are computed for differences between the financial statement and
income tax bases of assets and liabilities that will result in taxable or
deductible amounts in the future. Such deferred income tax asset and
liability computations are based on enacted tax laws and rates applicable to
periods in which the differences are expected to affect taxable income.
Income tax expense is the tax payable or refundable for the period plus or minus
the change during the period in deferred income tax assets and
liabilities.
ASC 740
clarifies the accounting for uncertainty in income taxes recognized in a
company’s financial statements. A company can only recognize the tax
position in the financial statements if the position is more-likely-than-not to
be upheld on audit based only on the technical merits of the tax position.
This accounting standard also provides guidance on thresholds, measurement,
derecognition, classification, interest and penalties, accounting in interim
periods, disclosure, and transition that is intended to provide better
financial-statement comparability among different companies.
We
performed evaluations as of December 31, 2009, 2008 and 2007 and concluded that
there were no uncertain tax positions requiring recognition in our financial
statements.
Net
Income or loss per unit
ASC 260
“Earnings per Share”
requires use of the “two-class” method of computing earnings per unit for
all periods presented. The “two-class” method is an earnings allocation
formula that determines earnings per unit for each class of Common Unit and
participating security as if all earnings for the period had been
distributed. Unvested restricted unit awards that earn non-forfeitable
dividend rights qualify as participating securities and, accordingly, are
included in the basic computation. Our unvested restricted phantom units
(“RPUs”) and convertible phantom units (“CPUs”) participate in dividends on an
equal basis with Common Units; therefore, there is no difference in
undistributed earnings allocated to each participating security.
Accordingly, our calculation is prepared on a combined basis and is presented as
earnings per Common Unit. See Note 14 for our earnings per Common Unit
calculation.
Environmental
expenditures
We
review, on an annual basis, our estimates of the cleanup costs of various
sites. When it is probable that obligations have been incurred and where a
reasonable estimate of the cost of compliance or remediation can be determined,
the applicable amount is accrued. For other potential liabilities, the
timing of accruals coincides with the related ongoing site assessments. We
do not discount any of these liabilities. At December 31, 2009 and 2008,
we had a $2.0 million environmental liability related to a closure of a drilling
pit in Michigan, which we assumed in the Quicksilver
Acquisition.
- 12
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3.
Accounting Pronouncements
We
adopted new accounting pronouncements during 2009 related to fair value
measurements as discussed in Notes 13 and 16, the earnings per share impact of
instruments granted in share-based payment transactions as discussed in Note 14,
noncontrolling interests as discussed in Note 15, disclosures about derivative
instruments and hedging activities as discussed in Note 16 and business
combinations as discussed in Note 4, which we will apply prospectively to
business combinations with acquisition dates after January 1, 2009.
We also adopted a new accounting pronouncement related to the determination of
the useful lives of intangible assets and an accounting pronouncement related to
the fair valuation of liabilities when a quoted price in an active market is not
available, with no impact on our financial position, results of operations or
cash flows.
Financial
Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”)
Topic 105 “Generally Accepted
Accounting Principles” establishes the FASB ASC as the source of
authoritative accounting principles recognized by the FASB to be applied in the
preparation of financial statements in conformity with GAAP. ASC 105
explicitly recognizes rules and interpretive releases of the SEC under federal
securities laws as authoritative GAAP for SEC registrants. This topic,
which has changed the way we reference GAAP, is effective for financial
statements ending after September 15, 2009. This topic does not change
GAAP and did not have an impact on our financial position, results of operations
or cash flows.
SEC Release No. 33-8995,
“Modernization of Oil and Gas Reporting.” In December 2008,
the SEC issued Release 33-8995 adopting new rules for reserves estimate
calculations and related disclosures. The new reserve estimate disclosures
apply to all annual reports for fiscal years ending on or after December 31,
2009 and thereafter, and to all registration statements filed after that
date. The new rules do not permit companies to voluntarily comply at an
earlier date. The revised proved reserve definition incorporates a new
definition of “reasonable certainty” using the PRMS (Petroleum Resource
Management System) standard of “high degree of confidence” for deterministic
method estimates, or a 90 percent recovery probability for probabilistic methods
used in estimating proved reserves. The new rules also permit a company to
establish undeveloped reserves as proved with appropriate degrees of reasonable
certainty established absent actual production tests and without artificially
limiting such reserves to spacing units adjacent to a producing well. For
reserve reporting purposes, the new rules also replace the end-of-the-year oil
and gas reserve pricing with an unweighted average first-day-of-the-month
pricing for the past 12 fiscal months. We use quarter-end reserves to
calculate quarterly DD&A and, as such, adoption of the new standard had an
impact on fourth quarter 2009 DD&A expense. See Note 22. The
impact that adopting Release 33-8995 has had on our financial statements is not
practical to estimate due to the operational and technical challenges associated
with calculating a cumulative effect of adoption by preparing reserve reports
under both the old and new rules. Costs associated with reserves will
continue to be measured on the last day of the fiscal year. A revised
tabular presentation of reserves by development category, final product type,
and oil and gas activity disclosure by geographic regions and significant fields
and a general disclosure of the internal controls a company uses to assure
objectivity in reserves estimation will be required. See Note 22 for the
impact Release 33-8995 has had on the calculation of our crude oil and natural
gas reserves.
Accounting Standards Update (“ASU”)
2010-03 “Extractive Activities – Oil and Gas.” In
January 2010, the FASB issued ASU 2010-03 to align the oil and gas reserve
estimation and disclosure requirements of Extractive Activities – Oil and Gas
(Topic 932) with the requirements in the Securities and Exchange Commission’s
final rule, Modernization of the Oil and Gas Reporting Requirements which was
issued on December 31, 2008. We calculate total
estimated proved reserves and disclose our oil and natural gas activities in
accordance with ASC 932“Extractive Activities – Oil and
Gas,” which incorporates SEC release No. 33-8995, “Modernization of
Oil and Gas Reporting.” and ASU 2010-03 “Extractive Activities – Oil and
Gas.”
ASU 2010-06 “Fair Value Measurements
and Disclosures.” In January 2010, the FASB issued ASU 2010-06
to make certain amendments to Subtopic 820-10 that require two additional
disclosures and clarify two existing disclosures. The new disclosures
require details of significant transfers in and out of level 1 and level 2
measurements and the reasons for the transfers, and a gross presentation of
activity within the level 3 roll forward that presents separately, information
about purchases, sales, issuances and settlements. The ASU clarifies the
existing disclosures with regard to the level of disaggregation of fair value
measurements by class of assets and liabilities rather than major category where
the reporting entities would need to apply judgment to determine the appropriate
classes of other assets and liabilities. The second clarification relates
to disclosures of valuation techniques and inputs for recurring and non
recurring fair value measurements using significant other observable inputs and
significant unobservable inputs for level 2 and level 3 measurements,
respectively. ASU 2010-06 (ASC 820-10) is prospectively effective for
financial statements issued for interim or annual periods beginning after
December 15, 2009, except for the disclosures about purchases, sales,
issuances, and settlements in the roll forward of activity in Level 3 fair value
measurements which are effective for fiscal years beginning after December 15,
2010 and for interim periods within those fiscal years. We do not expect
the adoption of ASU 2010-06 (ASC 820-10) to have an impact on our financial
position, results of operations or cash flows.
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In June
2009, the FASB issued authoritative guidance for the consolidation of variable
interest entities, which changed the consolidation guidance applicable to a
variable interest entity ("VIE"). The guidance governing the determination
of whether an enterprise is the primary beneficiary of a VIE, and is, therefore,
required to consolidate an entity, by requiring a qualitative analysis rather
than a quantitative analysis. The qualitative analysis will include, among
other things, consideration of who has the power to direct the activities of the
entity that most significantly impact the entity’s economic performance and who
has the obligation to absorb losses or the right to receive benefits of the VIE
that could potentially be significant to the VIE. This guidance also
requires continuous reassessments of whether an enterprise is the primary
beneficiary of a VIE. Former guidance required reconsideration of whether
an enterprise was the primary beneficiary of a VIE only when specific events had
occurred. The guidance also requires enhanced disclosures about an
enterprise’s involvement with a VIE. We will adopt this guidance effective
January 1, 2010, and we are assessing the impact this guidance may have on our
consolidated financial statements.
4.
Acquisitions
On June 17, 2008, we purchased
Provident Energy Trust’s 95.55 percent limited liability company interest in
BreitBurn Management for a purchase price of approximately $10.0 million.
This transaction resulted in BreitBurn Management becoming our wholly owned
subsidiary and was accounted for as a business combination using the purchase
method.
The
following table presents the purchase price allocation of the BreitBurn
Management Purchase:
Thousands of dollars
|
||||
Related
party receivables - current, net
|
$ | 10,662 | ||
Other
current assets
|
21 | |||
Oil
and gas properties
|
8,451 | |||
Non-oil
and gas assets
|
4,343 | |||
Related
party receivables - non-current
|
6,704 | |||
Current
liabilities
|
(13,510 | ) | ||
Long-term
liabilities
|
(6,704 | ) | ||
$ | 9,967 |
Certain
of the current and long-term related party receivables are with the Partnership,
so they are now eliminated in consolidation.
- 14
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The
following unaudited pro forma financial information presents a summary of our
consolidated results of operations for 2007, assuming the Quicksilver
Acquisition and the acquisitions in Florida and California had been completed as
of the beginning of the year, including adjustments to reflect the allocation of
the purchase price to the acquired net assets. The pro forma
financial information assumes our 2007 private placements of Common Units (see
Note 14) were completed as of the beginning of the year, since the private
placements were contingent on two of the acquisitions. The revenues
and expenses of these three acquisitions are included in the 2007 consolidated
results of the Partnership effective May 24, May 25 and November 1,
2007. The pro forma financial information is not necessarily
indicative of the results of operations if the acquisitions had been effective
as of these dates.
Pro Forma Year Ended
|
||||
Thousands of dollars, except per unit amounts
|
December 31, 2007 (1)
|
|||
Revenues
|
$ | 233,761 | ||
Net
income (loss)
|
(43,966 | ) | ||
Net
income (loss) per unit
|
||||
Basic
|
$ | (0.65 | ) | |
Diluted
|
(0.65 | ) | ||
(1)
Results include losses on derivative instruments of $101.0 million for the
year ended December 31,
2007.
|
Effective
January 1, 2009, we will account for all business combinations using the
acquisition method in accordance with ASC 805.
5. Disposition
of Assets
On July
17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas
to a private buyer for $23 million in cash. This transaction was
effective July 1, 2009. The proceeds from this transaction were used
to reduce our outstanding borrowings under our credit facility. In
connection with the sale, the borrowing base under our credit facility was
reduced by $3 million to $732 million.
The Lazy
JL Field properties produced approximately 245 Boe per day during the first six
months of 2009, of which 96 percent was crude oil. The net carrying
value at the date of sale was $28.5 million, of which $28.7 million was
reflected in net property, plant and equipment on the balance sheet and $0.2
million was reflected in asset retirement obligation on the balance
sheet. We recognized a loss of $5.5 million in 2009 related to the
sale of the field.
6. Impairments
and Price Related Depletion and Depreciation Adjustments
We assess our developed and undeveloped
oil and gas properties and other long-lived assets for possible impairment
whenever events or changes in circumstances indicate that the carrying value of
the assets may not be recoverable. Such indicators include changes in business
plans, changes in commodity prices and, for crude oil and natural gas
properties, significant downward revisions of estimated proved-reserve
quantities. If the carrying value of an asset exceeds the future undiscounted
cash flows expected from the asset, an impairment charge is recorded for the
excess of carrying value of the asset over its estimated fair
value.
Determination as to whether and how
much an asset is impaired involves management estimates on highly uncertain
matters such as future commodity prices, the effects of inflation and technology
improvements on operating expenses, production profiles, and the outlook for
market supply and demand conditions for crude oil and natural gas. The
impairment reviews and calculations are based on assumptions that are consistent
with our business plans. The low commodity price environment that
existed at December 31, 2008 influenced our future commodity price
projections. As a result, the expected discounted cash flows for many
of our fields (i.e., fair values) were negatively impacted resulting in a charge
to depletion and depreciation expense of approximately $51.9 million for oil and
gas property impairments for the year ended December 31, 2008.
An estimate as to the sensitivity to
earnings for these periods if other assumptions had been used in impairment
reviews and calculations is not practicable, given the number of assumptions
involved in the estimates. That is, favorable changes to some assumptions might
have avoided the need to impair any assets in these periods, whereas unfavorable
changes might have caused an additional unknown number of other assets to become
impaired.
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Lower commodity prices also negatively
impacted our oil and gas reserves in the fourth quarter of 2008 resulting in
significant price related adjustments to our depletion and depreciation expense
in the fourth quarter of 2008 as compared to the fourth quarter of 2007. These
price related reserve reductions in 2008 resulted in additional depletion and
depreciation charges of approximately $34.5 million for the fourth quarter and
for the year ended December 31, 2008.
For the years ended December 31, 2009
and 2007, we reviewed our long-lived oil and gas assets and did not record any
material impairments or price related adjustments to depletion and depreciation
expense.
7. Income
Taxes
We, and
all of our subsidiaries, with the exception of Phoenix Production Company
(“Phoenix”), Alamitos Company, BreitBurn Management and BreitBurn Finance
Corporation, are partnerships or limited liability companies treated as
partnerships for federal and state income tax purposes. Essentially
all of our taxable income or loss, which may differ considerably from the net
income or loss reported for financial reporting purposes, is passed through to
the federal income tax returns of our partners. As such, we have not
recorded any federal income tax expense for those pass-through
entities.
The
consolidated income tax expense (benefit) attributable to our tax-paying
entities consisted of the following:
Year Ended December 31,
|
||||||||||||
Thousands
of dollars
|
2009
|
2008
|
2007
|
|||||||||
Federal
income tax expense (benefit)
|
||||||||||||
Current
|
$ | 247 | $ | 257 | $ | - | ||||||
Deferred
(a)
|
(1,790 | ) | 1,207 | (1,229 | ) | |||||||
State
income tax expense (benefit) (b)
|
15 | 475 | - | |||||||||
Total
|
$ | (1,528 | ) | $ | 1,939 | $ | (1,229 | ) |
(a)
Related to Phoenix Production Company, our wholly owned subsidiary.
(b)
Primarily in the states of Michigan, California and Texas.
We record
income tax expense for Phoenix, a tax-paying corporation, in accordance with ASC
740 “Income Taxes.” The following is a reconciliation of federal
income taxes at the statutory rates to federal income tax expense (benefit) for
Phoenix:
Year Ended December 31,
|
||||||||||||
Thousands
of dollars
|
2009
|
2008
|
2007
|
|||||||||
Income
(loss) subject to federal income tax
|
(4,052 | ) | 3,904 | (4,498 | ) | |||||||
Federal
income tax rate
|
34 | % | 34 | % | 34 | % | ||||||
Income
tax at statutory rate
|
(1,378 | ) | 1,327 | (1,529 | ) | |||||||
Other
|
(299 | ) | - | 300 | ||||||||
Income
tax expense (benefit)
|
$ | (1,677 | ) | $ | 1,327 | $ | (1,229 | ) |
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At
December 31, 2009 and 2008, a net deferred federal income tax liability of $2.5
million and $4.3 million, respectively, were reported in our consolidated
balance sheet for Phoenix. Deferred income taxes reflect the net tax
effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting and the amount used for income tax
purposes. Significant components of our net deferred tax liabilities
are presented in the following table.
December 31,
|
||||||||
Thousands
of dollars
|
2009
|
2008
|
||||||
Deferred
tax assets:
|
||||||||
Net
operating loss carryforwards
|
$ | 422 | $ | 767 | ||||
Asset
retirement obligation
|
358 | 337 | ||||||
Unrealized
hedge loss
|
85 | - | ||||||
Other
|
276 | 103 | ||||||
Deferred tax liabilities:
|
||||||||
Depreciation,
depletion and intangible drilling costs
|
(3,101 | ) | (3,404 | ) | ||||
Unrealized
hedge gain
|
- | (2,085 | ) | |||||
Deferred
realized hedge gain
|
(532 | ) | - | |||||
Net
deferred tax liability
|
$ | (2,492 | ) | $ | (4,282 | ) |
At
December 31, 2009, we had $1.2 million of estimated unused operating loss carry
forwards. We did not provide a valuation allowance against this
deferred tax asset as we expect sufficient future taxable income to offset the
unused operating loss carry forwards.
On a
consolidated basis, cash paid for federal and state income taxes totaled $0.6
million in 2009, $0.6 million in 2008 and $0.1 million in
2007.
ASC 740
“Income Taxes,”
clarifies the accounting for uncertainty in income taxes recognized in a
company’s financial statements. A company can only recognize the tax
position in the financial statements if the position is more-likely-than-not to
be upheld on audit based only on the technical merits of the tax
position. This topic also provides guidance on thresholds,
measurement, derecognition, classification, interest and penalties, accounting
in interim periods, disclosure, and transition that is intended to provide
better financial-statement comparability among different
companies.
We
performed evaluations as of December 31, 2009 and 2008 and concluded that there
were no uncertain tax positions requiring recognition in our financial
statements.
8. Related
Party Transactions
BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering. All of our employees, including our executives, are
employees of BreitBurn Management. Prior to June 17, 2008, BreitBurn
Management provided services to us and to BEC, and allocated its expenses
between the two entities. On June 17, 2008, BreitBurn Management
became our wholly-owned subsidiary and entered into an Amended and Restated
Administrative Services Agreement with BEC, pursuant to which BreitBurn
Management agreed to continue to provide administrative services to BEC, in
exchange for a monthly fee for indirect expenses. The monthly fee was
set at $775,000 for 2008.
On August
26, 2008, members of our senior management, in their individual capacities,
together with Metalmark Capital Partners (“Metalmark”), Greenhill Capital
Partners (“Greenhill”) and a third-party institutional investor, completed the
acquisition BEC. This transaction included the acquisition of a 96.02
percent indirect interest in BEC, previously owned by Provident Energy Trust
(“Provident”), and the remaining indirect interests in BEC, previously owned by
Randall H. Breitenbach, Halbert S. Washburn and other members of our
senior management. BEC is a separate Delaware oil and gas partnership
with operations in California, was a separate U.S. subsidiary of Provident and
was our Predecessor.
- 17
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In
connection with the acquisition of Provident’s ownership in BEC by members of
senior management, Metalmark, Greenhill and a third party institutional
investor, BreitBurn Management entered into the Second Amended and Restated
Administrative Services Agreement (the “Administrative Services Agreement”) to
manage BEC's properties for a term of five years. In addition to the
monthly fee, BreitBurn Management charges BEC for all direct expenses including
incentive plan costs and direct payroll and administrative costs related to BEC
properties and operations. The monthly fee is contractually based on
an annual projection of anticipated time spent by each employee who provides
services to both us and BEC during the ensuing year and is subject to
renegotiation annually by the parties during the term of the
agreement. For 2009, each BreitBurn Management employee estimated his
or her time allocation independently based on 2008. These estimates
were then reviewed and approved by each employee’s manager or
supervisor. The results of this process were provided to both the
audit committee of the board of directors of our General Partner (composed
entirely of independent directors) (the “audit committee”) and the board of
representatives of BEC’s parent (the “BEC board”). The audit
committee and the non-management members of the BEC board agreed on the 2009
monthly fee as provided in the Administrative Services
Agreement. Effective January 1, 2009, the monthly fee was
renegotiated to $500,000. The reduction in the monthly fee is
attributable to the overall reduction in general and administrative expenses,
excluding unit-based compensation, for BreitBurn Management in 2009, the new
time allocation study described above and the fact that additional costs are
being charged directly to us and BEC compared to prior years. The
monthly fee will be renegotiated for 2010.
In
addition, we entered into an Omnibus Agreement with BEC detailing rights with
respect to business opportunities and providing us with a right of first offer
with respect to the sale of assets by BEC.
At
December 31, 2009 and December 31, 2008, we had current receivables of $1.4
million and $4.4 million, respectively, due from BEC related to the
Administrative Services Agreement, outstanding liabilities for employee related
costs and oil and gas sales made by BEC on our behalf from certain
properties. During 2009, the monthly charges to BEC for indirect
expenses totaled $6.5 million and charges for direct expenses including direct
payroll and administrative costs totaled $6.1 million. For the year
ended December 31, 2009, total oil and gas sales made by BEC on our behalf were
approximately $1.3 million. For the year ended December 31, 2008,
total oil and gas sales made by BEC on our behalf were approximately $2.1
million. At December 31, 2009 and 2008, we had receivables of $0.3
million and $0.1 million, respectively, due from certain of our affiliates for
management fees due from equity affiliates and operational expenses incurred on
behalf of equity affiliates.
Pursuant
to a transition services agreement through March 2008, Quicksilver provided to
us services for accounting, land administration, and marketing and charged us
$0.9 million for the first quarter of 2008. These charges were
included in general and administrative expenses on the consolidated statements
of operations. Quicksilver also buys natural gas from us in
Michigan. For the year ended December 31, 2009, total net gas sales
to Quicksilver were approximately $2.8 million and the related receivable was
$0.4 million as of December 31, 2009. For the year ended December 31,
2008, total net gas sales to Quicksilver were approximately $8.0 million and the
related receivable was $0.6 million as of December 31, 2008.
On
October 31, 2008, Quicksilver, an owner of approximately 40 percent of our
Common Units, instituted a lawsuit in the District Court of Tarrant County,
Texas naming us as a defendant along with others. The primary claims
were as follows: Quicksilver alleged that BOLP breached the Contribution
Agreement with Quicksilver, dated September 11, 2007, based on allegations that
we made false and misleading statements relating to our relationship with
Provident. Quicksilver also alleged common law and statutory fraud claims
against all of the defendants by contending that the defendants made false and
misleading statements to induce Quicksilver to acquire Common Units in us.
Finally, Quicksilver also alleged claims for breach of the Partnership’s First
Amended and Restated Agreement of Limited Partnership, dated as of October 10,
2006 (“Partnership Agreement”), and other common law claims relating to certain
transactions and an amendment to the Partnership Agreement that occurred in June
2008. Quicksilver sought a permanent injunction, a declaratory judgment
relating primarily to the interpretation of the Partnership Agreement and the
voting rights in that agreement, indemnification, punitive or exemplary damages,
avoidance of BreitBurn GP's assignment to us of all of its economic interest in
us, attorneys’ fees and costs, pre- and post-judgment interest, and monetary
damages.
In
February 2010, we and Quicksilver agreed to settle all claims with respect to
the litigation filed by Quicksilver (the “Settlement”). We expect the
terms of the Settlement to be implemented upon the dismissal of the lawsuit in
Texas in early April 2010. The parties have agreed to dismiss all
pending claims before the Court and have mutually released each party, its
affiliates, agents, officers, directors and attorneys from any and all claims
arising from the subject matter of the pending case before the
Court. We have also agreed to pay Quicksilver $13.0 million and
expect this amount to be paid by insurance. In addition, Mr. Halbert
S. Washburn and Mr. Randall H. Breitenbach will resign from the Board of
Directors and the Board will appoint two new directors designated by
Quicksilver, one of whom will qualify as an independent director and one of whom
will be a current independent board member now serving on Quicksilver’s board of
directors, provided that such director not be a member of Quicksilver’s
management.
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At
December 31, 2009, we recorded a $13.0 million payable to Quicksilver in
connection with the monetary portion of the Settlement.
Mr. Greg
L. Armstrong is the Chairman of the Board and Chief Executive Officer of Plains
All American GP LLC (“PAA”). Mr. Armstrong was a director of our General Partner
until March 26, 2008 when his resignation became effective. We sell all of the
crude oil produced from our Florida properties to Plains Marketing, L.P.
(“Plains Marketing”), a wholly owned subsidiary of PAA. In 2008, prior to Mr.
Armstrong’s resignation on March 26, 2008, we sold $19.3 million of our crude
oil to Plains Marketing. At December 31, 2007, the receivable from Plains
Marketing was $10.5 million, which was collected in the first quarter of
2008.
9.
Inventory
In
Florida, crude oil inventory was $5.8 million and $1.3 million at December 31,
2009 and 2008, respectively. For the year ended December 31, 2009, we sold 529
MBbls of crude oil and produced 590 MBbls from our Florida operations. For the
year ended December 31, 2008, we sold 762 MBbls of crude oil and produced 707
MBbls from our Florida operations. Crude oil inventory additions are at cost and
represent our production costs. We match production expenses with crude oil
sales. Production expenses associated with unsold crude oil inventory are
recorded to inventory. Crude oil sales are a function of the number and size of
crude oil shipments in each quarter and thus crude oil sales do not always
coincide with volumes produced in a given quarter.
We carry
inventory at the lower of cost or market. When using lower of cost or market to
value inventory, market should not exceed the net realizable value or the
estimated selling price less costs of completion and disposal. We assessed our
crude-oil inventory at December 31, 2009 and determined that the carrying value
of our inventory was below market value and, therefore, no write-down was
necessary. During the fourth quarter of 2008, commodity prices decreased
substantially. As a result, we assessed our crude oil inventory and recorded
$1.2 million to write-down the Florida crude oil inventory to our net realizable
value at December 31, 2008.
For our
properties in Florida, there are a limited number of alternative methods of
transportation for our production. Substantially all of our oil production is
transported by pipelines, trucks and barges owned by third parties. The
inability or unwillingness of these parties to provide transportation services
for a reasonable fee could result in our having to find transportation
alternatives, increased transportation costs, or involuntary curtailment of our
oil production, which could have a negative impact on our future consolidated
financial position, results of operations and cash flows.
10.
Intangibles
In May
2007, we acquired certain interests in oil leases and related assets through the
acquisition of a limited liability company from Calumet Florida, L.L.C. As part
of this acquisition, we assumed certain crude oil sales contracts for the
remainder of 2007 and for 2008 through 2010. A $3.4 million intangible asset was
established to value the portion of the crude oil contracts that were above
market at closing in the purchase price allocation. Realized gains or losses
from these contracts are recognized as part of oil sales and the intangible
asset will be amortized over the life of the contracts. Amortization expense of
$1.0 million for 2009 and 2008, respectively, is included in the oil, natural
gas and natural gas liquid sales line on the consolidated statements of
operations. As of December 31, 2009, our intangible asset related to the crude
oil sales contracts was $0.5 million.
In
November 2007, we acquired oil and gas properties and facilities from
Quicksilver. Included in the Quicksilver purchase price was a $5.2 million
intangible asset related to retention bonuses. In connection with the
acquisition, we entered into an agreement with Quicksilver which provides for
Quicksilver to fund retention bonuses payable to 139 former Quicksilver
employees in the event these employees remain continuously employed by BreitBurn
Management from November 1, 2007 through November 1, 2009 or in the event of
termination without cause, disability or death. Amortization expense of $1.8
million and $2.1 million for 2009 and 2008, respectively, is included in the
total operating expenses line on the consolidated statements of operations. As
of December 31, 2009, the intangible asset related to these retention bonuses
was fully amortized.
- 19
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11. Equity
Investments
We had
equity investments at December 31, 2009 and December 31, 2008 of $8.2 million
and $9.5 million, respectively which primarily represent investments in natural
gas processing facilities. For the years ended December 31, 2009 and 2008, we
recorded less than $0.1 million and $0.8 million, respectively, in earnings from
equity investments and $1.4 million and $2.0 million, respectively, in
dividends. Earnings from equity investments are reported in the other revenue,
net line on the consolidated statements of operations.
At
December 31, 2009, our equity investments consisted primarily of a 24.5 percent
limited partner interest and a 25.5 percent general partner interest in
Wilderness Energy Services LP, with a combined carrying value of $7.0 million.
The remaining $1.2 million consists of smaller interests in several other
investments. At December 31, 2008, our equity investment totaled $9.5 million.
The decrease during 2009 is primarily due to dividends received during the
year.
12.
Long-Term Debt
On
November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as
borrower, and we and our wholly owned subsidiaries, as guarantors, entered into
a four year, $1.5 billion amended and restated revolving credit facility with
Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of
banks (the “Amended and Restated Credit Agreement”).
The
initial borrowing base of the Amended and Restated Credit Agreement was $700
million and was increased to $750 million on April 10, 2008. On June 17, 2008,
in connection with the Purchase, Contribution and Partnership Transactions, we
and our wholly owned subsidiaries entered into Amendment No. 1 to the Amended
and Restated Credit Agreement, with Wells Fargo Bank, National Association, as
administrative agent (the “Agent”). Amendment No. 1 to the Credit Agreement
increased the borrowing base available under the Amended and Restated Credit
Agreement, from $750 million to $900 million. Borrowings under the Amended and
Restated Credit Agreement are secured by first-priority liens on and security
interests in substantially all of our and certain of our subsidiaries’ assets,
representing not less than 80 percent of the total value of our oil and gas
properties.
The
credit facility contains customary covenants, including restrictions on our
ability to: incur additional indebtedness; make certain investments, loans or
advances; make distributions to our unitholders (including the restriction on
our ability to make distributions unless after giving effect to such
distribution, our outstanding debt is less than 90 percent of the borrowing
base, and we have the ability to borrow at least ten percent of the borrowing
base while remaining in compliance with all terms and conditions of our credit
facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is
total indebtedness to EBITDAX); make dispositions or enter into sales and
leasebacks; or enter into a merger or sale of our property or assets, including
the sale or transfer of interests in our subsidiaries.
EBITDAX
is not a defined GAAP measure. Our credit facility defines EBITDAX as net income
plus interest expense and other financing costs, income tax provision,
depletion, depreciation and amortization, unrealized loss or gain on derivative
instruments, non-cash unit based compensation expense, loss or gain on sale of
assets, cumulative effect of changes in accounting principles, amortization of
intangible sales contracts and amortization of intangible asset related to
employment retention allowance, excluding adjusted EBITDAX attributable to our
BEPI limited partner interest and including the cash distribution received from
BEPI.
In
addition, Amendment No. 1 to the Credit Agreement enacted certain additional
amendments, waivers and consents to the Amended and Restated Credit Agreement
and the related Security Agreement, dated November 1, 2007, among BOLP, certain
of its subsidiaries and the Agent, necessary to permit the Amendment No. 1 to
the First Amended and Restated Limited Partnership Agreement and the
transactions consummated in the Purchase, Contribution and Partnership
Transactions. Under Amendment No. 1 to the Credit Agreement, the interest
margins applicable to borrowings, the letter of credit fee and the commitment
fee under the Amended and Restated Credit Agreement were increased by amounts
ranging from 12.5 to 25 basis points.
The
events that constitute an Event of Default (as defined in the Amended and
Restated Credit Agreement) include: payment defaults; misrepresentations;
breaches of covenants; cross-default and cross-acceleration to certain other
indebtedness; adverse judgments against us in excess of a specified amount;
changes in management or control; loss of permits; failure to perform under a
material agreement; certain insolvency events; assertion of certain
environmental claims; and occurrence of a material adverse effect. At December
31, 2009 and December 31, 2008, we were in compliance with the credit facility’s
covenants.
- 20
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In
January 2009, we monetized certain in-the-money commodity hedges for
approximately $46 million, the net proceeds of which were used to reduce
outstanding borrowings under our credit facility. In April 2009, in connection
with a scheduled redetermination, our borrowing base under our Amended and
Restated Credit Agreement was redetermined at $760 million. In June 2009, we
monetized additional in-the-money commodity hedges for approximately $25
million, the net proceeds of which were used to reduce outstanding borrowings
under our credit facility. As a result of the monetization, our borrowing base
was reset at $735 million.
On July
17, 2009, we sold the Lazy JL Field for $23 million in cash. The proceeds from
this transaction were used to reduce outstanding borrowings under our credit
facility and our borrowing base was reduced by $3 million to $732
million.
In
October 2009, in connection with our semi-annual borrowing base redetermination,
our borrowing base was reaffirmed at $732 million. Our next semi-annual
borrowing base redetermination is scheduled for April 2010.
As of
December 31, 2009 and December 31, 2008, we had $559.0 million and $736.0
million, respectively, in indebtedness outstanding under the credit facility,
which will mature on November 1, 2011. At December 31, 2009, we had $173.0
million available under our borrowing base. At December 31, 2009, the 1-month
LIBOR interest rate plus an applicable spread was 1.990 percent on the 1-month
LIBOR portion of $552.0 million and the prime rate plus an applicable spread was
4.000 percent on the prime debt portion of $7.0 million. The amounts reported on
our consolidated balance sheets for long-term debt approximate fair value due to
the variable nature of our interest rates.
At
December 31, 2009 and 2008, we had $0.3 million in letters of credit
outstanding.
Our
interest expense is detailed in the following table:
Year Ended December 31,
|
||||||||||||
Thousands
of dollars
|
2009
|
2008
|
2007
|
|||||||||
Credit
agreement (including commitment fees)
|
$ | 15,532 | $ | 26,534 | $ | 5,876 | ||||||
Amortization
of discount and deferred issuance costs
|
3,295 | 2,613 | 382 | |||||||||
Total
|
$ | 18,827 | $ | 29,147 | $ | 6,258 | ||||||
Cash
paid for interest
|
$ | 28,350 | $ | 29,767 | $ | 3,545 |
13. Asset
Retirement Obligation
Our asset
retirement obligation is based on our net ownership in wells and facilities and
our estimate of the costs to abandon and remediate those wells and facilities as
well as our estimate of the future timing of the costs to be
incurred. The total undiscounted amount of future cash flows required
to settle our asset retirement obligations is estimated to be $257.4 million at
December 31, 2009 and was $256.8 million at December 31,
2008. Payments to settle asset retirement obligations occur over the
operating lives of the assets, estimated to be from less than one year to 50
years. We expect our cash settlements to be approximately $1.1
million and less than $0.1 million for 2010 and 2012,
respectively. Cash settlements for the years after 2014 are expected
to be $35.5 million. Estimated cash flows have been discounted at our
credit adjusted risk free rate of seven percent and adjusted for inflation using
a rate of two percent. Our credit adjusted risk free rate is
calculated based on our cost of borrowing adjusted for the effect of our credit
standing and specific industry and business risk. Each year we review
and, to the extent necessary, revise our asset retirement obligation estimates.
During 2009, we obtained new estimates to evaluate the cost of abandoning our
properties. As a result, we increased our ARO estimates by $4.9 million to
reflect recent costs incurred for plugging and abandonment activities in
Michigan and Florida.
ASC 820
“Fair Value Measurements and
Disclosures” establishes a fair value hierarchy that prioritizes the
inputs to valuation techniques into three broad levels based upon how observable
those inputs are. The highest priority of Level 1 is given to unadjusted
quoted prices in active markets for identical assets or liabilities. Level
2 includes inputs other than quoted prices that are included in Level 1, and can
be derived from observable data, including third party data providers.
These inputs may also include observable transactions in the market place.
Level 3 is given to unobservable inputs. We consider the inputs to
our asset retirement obligation valuation to be Level 3 as fair value is
determined using discounted cash flow methodologies based on standardized inputs
that are not readily observable in public markets.
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Changes
in the asset retirement obligation for the years ended December 31, 2009 and
2008 are presented in the following table:
Year Ended December 31,
|
||||||||
Thousands
of dollars
|
2009
|
2008
|
||||||
Carrying
amount, beginning of period
|
$ | 30,086 | $ | 27,819 | ||||
Liabilities
settled in the current period
|
(470 | ) | (1,054 | ) | ||||
Revisions
(a)
|
4,883 | 1,363 | ||||||
Acquisitions
(dispositions) (b)
|
(252 | ) | - | |||||
Accretion
expense
|
2,388 | 1,958 | ||||||
Carrying
amount, end of period
|
$ | 36,635 | $ | 30,086 |
(a)
Increased cost estimates and revisions to reserve life.
(b)
Relates to disposition of the Lazy JL Field.
14. Partners’
Equity
At
December 31, 2009, we had 52,784,201 Common Units outstanding.
At
December 31, 2009 and December 31, 2008, we had 6,700,000 units authorized for
issuance under our long-term incentive compensation plans. At
December 31, 2009 and December 31, 2008, there were 2,961,659 and 1,422,171,
respectively, of partnership-based units outstanding that are eligible to be
paid in Common Units upon vesting.
In
February 2009, 134,377 Common Units were issued to employees under our 2006
Long-Term Incentive Plan.
In
October 2009, 14,190 Common Units were issued to outside directors for phantom
units and distribution equivalent rights which were granted in 2006 and vested
in October 2009.
On June
17, 2008, we purchased 14,404,962 Common Units from subsidiaries of Provident at
$23.26 per unit, for a purchase price of approximately $335 million. These units
have been cancelled and are no longer outstanding. This transaction
was accounted for as a repurchase of issued Common Units and a cancellation of
those Common Units. This transaction decreased equity by $336.2
million, including $1.2 million in capitalized transaction costs. We
also purchased Provident’s 95.55 percent limited liability company interest in
BreitBurn Management, which owned the General Partner. Also on June
17, 2008, we entered into a contribution agreement with the General Partner,
BreitBurn Management and BreitBurn Corporation, pursuant to which BreitBurn
Corporation contributed its 4.45 percent limited liability company interest in
BreitBurn Management to us in exchange for 19,955 Common Units and BreitBurn
Management contributed its 100 percent limited liability company interest in the
General Partner to us. On the same date, we entered into Amendment
No. 1 to the First Amended and Restated Agreement of Limited Partnership of the
Partnership, pursuant to which the economic portion of the General Partner’s
0.66473 percent general partner interest in us was eliminated. As a
result of these transactions, the General Partner and BreitBurn Management
became our wholly owned subsidiaries.
On
December 22, 2008, we entered into a Unit Purchase Rights Agreement, dated as of
December 22, 2008 (the “Rights Agreement”), between us and American Stock
Transfer & Trust Company LLC, as Rights Agent. Under the Rights
Agreement, each holder of Common Units at the close of business on December 31,
2008 automatically received a distribution of one unit purchase right (a
“Right”), which entitles the registered holder to purchase from us one
additional Common Unit at a price of $40.00 per Common Unit, subject to
adjustment. We entered into the Rights agreement to increase the likelihood that
our unitholders receive fair and equal treatment in the event of a takeover
proposal.
The
issuance of the Rights was not taxable to the holders of the Common Units, had
no dilutive effect, will not affect our reported earnings per Common Unit, and
will not change the method of trading the Common Units. The Rights will not
trade separately from the Common Units unless the Rights become
exercisable. The Rights will become exercisable if a person or group
acquires beneficial ownership of 20 percent or more of the outstanding Common
Units or commences, or announces its intention to commence, a tender offer that
could result in beneficial ownership of 20 percent or more of the outstanding
Common Units. If the Rights become exercisable, each Right will entitle holders,
other than the acquiring party, to purchase a number of Common Units having a
market value of twice the then-current exercise price of the Right. Such
provision will not apply to any person who, prior to the adoption of the Rights
Agreement, beneficially owns 20 percent or more of the outstanding Common Units
until such person acquires beneficial ownership of any additional Common
Units.
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The
Rights Agreement has a term of three years and will expire on December 22, 2011,
unless the term is extended, the Rights are earlier redeemed or we terminate the
Rights Agreement.
On May
24, 2007, we sold 4,062,500 Common Units, at a negotiated purchase price of
$32.00 per unit, to certain investors (the “Purchasers”). We used
$108 million from such sale to fund the cash consideration for the Calumet
Acquisition and the remaining $22 million of the proceeds was used to repay
indebtedness under our credit facility. Most of the debt repaid was
associated with our first quarter 2007 acquisition of the Lazy JL Field
properties in West Texas.
On May
25, 2007, we sold an additional 2,967,744 Common Units to the same
Purchasers at a negotiated purchase price of $31.00 per unit. We used
the proceeds of approximately $92 million to fund the BEPI Acquisition,
including the termination of existing hedge contracts related to future
production from BEPI.
On
November 1, 2007, we sold 16,666,667 Common Units, at a negotiated purchase
price of $27.00 per unit, to certain investors in a third private
placement. We used the proceeds from such sale to fund a portion of
the cash consideration for the Quicksilver Acquisition. Also on November 1,
2007, we issued 21,347,972 Common Units to Quicksilver as partial consideration
for the Quicksilver Acquisition as a private placement.
In
connection with the private placements of Common Units to finance the
Quicksilver Acquisition, we entered into registration rights agreements with the
institutional investors in our private placements and Quicksilver to file shelf
registration statements to register the resale of the Common Units sold or
issued in the Private Placements and to use our commercially reasonable efforts
to cause the registration statements to become effective with respect to the
Common Units sold to the institutional investors not later than August 2, 2008
and, with respect to the Common Units issued to Quicksilver, within one year
from November 1, 2007. Quicksilver was prohibited from selling any of
the Common Units issued to it prior to the first anniversary of November 1, 2007
or more than 50 percent of such Common Units prior to 18 months after November
1, 2007. In addition, the agreements gave the institutional investors
and Quicksilver piggyback registration rights under certain
circumstances. These registration rights are transferable to
affiliates of the institutional investors and Quicksilver and, in certain
circumstances, to third parties.
On July
31, 2008, the registration statement relating to the resale of the Common Units
issued in the private placement to the institutional investors was declared
effective. On October 28, 2008, the registration statement relating
to the resale of the Common Units issued in the private placement to Quicksilver
was declared effective.
Earnings
per Common Unit
ASC 260
“Earnings per Share”
requires use of the “two-class” method of computing earnings per unit for
all periods presented. The “two-class” method is an earnings
allocation formula that determines earnings per unit for each class of Common
Unit and participating security as if all earnings for the period had been
distributed. Unvested restricted unit awards that earn
non-forfeitable dividend rights qualify as participating securities and,
accordingly, are included in the basic computation. Our unvested RPUs
and CPUs participate in dividends on an equal basis with Common Units;
therefore, there is no difference in undistributed earnings allocated to each
participating security. Accordingly, the presentation below is
prepared on a combined basis and is presented as earnings per Common
Unit.
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-
The
following is a reconciliation of net earnings and weighted average units for
calculating basic net earnings per Common Unit and diluted net earnings per
Common Unit. For the years ended December 31, 2009 and 2007, RPUs and
CPUs have been excluded from the calculation of basic earnings per unit, as we
were in a net loss position.
Year Ended December 31,
|
||||||||||||
Thousands,
except per unit amounts
|
2009
|
2008
|
2007
|
|||||||||
Net
income (loss) attributable to limited partners
|
$ | (107,290 | ) | $ | 380,255 | $ | (59,685 | ) | ||||
Distributions
on participating units not expected to vest
|
- | 22 | - | |||||||||
Net
income (loss) attributable to common unitholders and participating
securities
|
$ | (107,290 | ) | $ | 380,277 | $ | (59,685 | ) | ||||
Weighted
average number of units used to calculate basic and diluted net income
(loss) per unit:
|
||||||||||||
Common
Units
|
52,757 | 59,239 | 32,577 | |||||||||
Participating
securities (a)
|
- | 1,184 | - | |||||||||
Denominator
for basic earnings per Common Unit
|
52,757 | 60,423 | 32,577 | |||||||||
Dilutive
units (b)
|
- | 142 | - | |||||||||
Denominator
for diluted earnings per Common Unit
|
52,757 | 60,565 | 32,577 | |||||||||
Net
income (loss) per common unit
|
||||||||||||
Basic
|
$ | (2.03 | ) | $ | 6.29 | $ | (1.83 | ) | ||||
Diluted
|
$ | (2.03 | ) | $ | 6.28 | $ | (1.83 | ) |
(a) The
year ended December 31, 2009 excludes 2,636,800 of potentially issuable weighted
average RPUs and CPUs from participating securities, as we were in a loss
position. For the year ended December 31, 2008, basic earnings per
unit is based upon the weighted average number of Common Units outstanding plus
the weighted average number of potentially issuable RPUs and CPUs. The year
ended December 31, 2007 had no potentially issuable weighted average RPUs and
CPUs from participating securities.
(b) The
years ended December 31, 2009 and 2007 exclude 102,090 and 150,813,
respectively, of weighted average anti-dilutive units from the calculation of
the denominator for diluted earnings per Common Unit. Weighted
average dilutive units for the year ended December 31, 2008 include units
potentially issuable under compensation plans that do not qualify as
participating securities.
Cash
Distributions
The
partnership agreement requires us to distribute all of our available cash
quarterly. Available cash is cash on hand, including cash from
borrowings, at the end of a quarter after the payment of expenses and the
establishment of reserves for future capital expenditures and operational
needs. We may fund a portion of capital expenditures with additional
borrowings or issuances of additional units. We may also borrow to
make distributions to unitholders, for example, in circumstances where we
believe that the distribution level is sustainable over the long term, but
short-term factors have caused available cash from operations to be insufficient
to pay the distribution at the current level. The partnership
agreement does not restrict our ability to borrow to pay
distributions. The cash distribution policy reflects a basic judgment
that unitholders will be better served by us distributing our available cash,
after expenses and reserves, rather than retaining it.
Distributions
are not cumulative. Consequently, if distributions on Common Units
are not paid with respect to any fiscal quarter at the initial distribution
rate, our unitholders will not be entitled to receive such payments in the
future.
Distributions
are paid within 45 days of the end of each fiscal quarter to holders of record
on or about the first or second week of each such month. If the
distribution date does not fall on a business day, the distribution will be made
on the business day immediately preceding the indicated distribution
date.
- 24
-
We do not
have a legal obligation to pay distributions at any rate except as provided in
the partnership agreement. Our distribution policy is consistent with
the terms of our partnership agreement, which requires that we distribute all of
our available cash quarterly. Under the partnership agreement,
available cash is defined to generally mean, for each fiscal quarter, cash
generated from our business in excess of the amount of reserves the General
Partner determines is necessary or appropriate to provide for the conduct of the
business, to comply with applicable law, any of its debt instruments or other
agreements or to provide for future distributions to its unitholders for any one
or more of the upcoming four quarters. The partnership agreement
provides that any determination made by the General Partner in its capacity as
general partner must be made in good faith and that any such determination will
not be subject to any other standard imposed by the partnership agreement, the
Delaware limited partnership statute or any other law, rule or regulation or at
equity.
On
February 13, 2009, we paid a cash distribution of approximately $27.4
million to our common unitholders of record as of the close of business on
February 9, 2009. The distribution that was paid to unitholders was
$0.52 per Common Unit. During the three months ended March 31, 2009,
we also paid cash equivalent to the distribution paid to our unitholders of $0.7
million to holders of outstanding Restricted Phantom Units and Convertible
Phantom Units issued under our Long-Term Incentive Plans.
With the
borrowing base redetermination in April 2009 (see Note 12), our borrowings
exceeded 90 percent of the reset borrowing base and, therefore, under the terms
of our credit facility we were restricted from making a distribution for the
first quarter of 2009. Although we were not restricted from making
distributions under the terms of our credit facility for the second, third and
fourth quarters of 2009, we elected not to declare distributions in light of
total leverage levels and other factors. We are restricted from
paying distributions under our credit facility unless, after giving effect to
such distribution, our outstanding debt is less than 90 percent of the borrowing
base and we have the ability to borrow at least ten percent of the borrowing
base while remaining in compliance with all terms and conditions of our credit
facility, including the leverage ratio not exceeding 3.50 to 1.00 (which is
total indebtedness to EBITDAX).
15. Noncontrolling
interest
ASC 810
“Consolidation” requires that
noncontrolling interests be classified as a component of equity and establishes
reporting requirements that provide sufficient disclosures that clearly identify
and distinguish between the interests of the parent and the interests of the
noncontrolling owners.
On May
25, 2007, we acquired the limited partner interest (99 percent) of BEPI from
TIFD. As such, we are fully consolidating the results of BEPI and
thus are recognizing a noncontrolling interest representing the book value of
the general partner’s interests. At December 31, 2009 and December
31, 2008, the amount of this noncontrolling interest was $0.4 million and $0.5
million, respectively. For the years ended December 31, 2009 and
2008, we recorded net income attributable to the noncontrolling interest of less
than $0.1 million and $0.2 million, respectively, and $0.1 million and $0.2
million, respectively, in dividends.
BEPI’s
general partner interest is held by a wholly owned subsidiary of
BEC. The general partner of BEPI holds a 35 percent reversionary
interest under the existing limited partnership agreement applicable to the
properties. This reversionary interest is expected to occur at a
defined payout, which is estimated to occur in 2015 based on year-end price and
cost projections.
- 25
-
16. Financial
Instruments
Fair
Value of Financial Instruments
Our risk
management programs are intended to reduce our exposure to commodity prices and
interest rates and to assist with stabilizing cash flow. Routinely,
we utilize derivative financial instruments to reduce this
volatility. To the extent we have hedged prices for a significant
portion of our expected production through commodity derivative instruments and
the cost for goods and services increase, our margins would be adversely
affected.
Credit
and Counterparty Risk
Financial
instruments which potentially subject us to concentrations of credit risk
consist principally of derivatives and accounts receivable. Our
derivatives expose us to credit risk from counterparties. As of
December 31, 2009, our derivative counterparties were Barclays Bank PLC,
Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse
Energy LLC, Union Bank N.A, Wells Fargo Bank N.A., JP Morgan Chase Bank N.A.,
Royal Bank of Scotland plc, The Bank of Nova Scotia and Toronto-Dominion
Bank. We terminated all derivative financial instruments with Lehman
Brothers on September 19, 2008. Our counterparties are all
lenders under our Amended and Restated Credit Agreement. During
2008, there was extreme volatility and disruption in the capital and credit
markets which reached unprecedented levels. Continued volatility and
disruption may adversely affect the financial condition of our derivative
counterparties. On all transactions where we are exposed to
counterparty risk, we analyze the counterparty's financial condition prior to
entering into an agreement, establish limits, and monitor the appropriateness of
these limits on an ongoing basis. We periodically obtain credit
default swap information on our counterparties. Although we currently
do not believe we have a specific counterparty risk with any party, our loss
could be substantial if any of these parties were to fail to perform in
accordance with the terms of the contract. This risk is managed by
diversifying the derivative portfolio. As of December 31, 2009,
each of these financial institutions carried an S&P credit rating of A or
above. As of December 31, 2009, our largest derivative asset balances were
with JP Morgan Chase Bank N.A., who accounted for approximately 64 percent of
our derivative asset balances, and Credit Suisse International and Credit Suisse
Energy LLC, who together accounted for approximately 26 percent of our
derivative asset balances.
Commodity
Activities
The
derivative instruments we utilize are based on index prices that may and often
do differ from the actual crude oil and natural gas prices realized in our
operations. These variations often result in a lack of adequate
correlation to enable these derivative instruments to qualify for cash flow
hedges under ASC 815 “Derivatives and
Hedging.” Accordingly, we do not attempt to account for our
derivative instruments as cash flow hedges for financial reporting purposes and
instead recognize changes in the fair value immediately in
earnings. We had a realized gain of $167.7 million and an unrealized
loss of $219.1 million for the year ended December 31, 2009 relating to our
various market-based commodity contracts. We had a net derivative
asset relating to our commodity contracts of $73.2 million at December 31,
2009.
In
January 2009, we terminated a portion of our 2011 and 2012 crude oil derivative
contracts and replaced them with new contracts with the same counterparty for
the same volumes at market prices. We realized $32.3 million from
this termination. In January 2009, we also terminated a portion of
our 2011 and 2012 natural gas derivative contracts and replaced them with new
contracts with the same counterparty for the same volumes at market
prices. We realized $13.3 million from this
termination. Proceeds from these contracts were used to pay down
outstanding borrowings under our credit facility.
In June
2009, we terminated an additional portion of our 2011 and 2012 crude oil and
natural gas derivative contracts and replaced them with new contracts for the
same volumes at market prices. We realized $18.9 million from the
termination of natural gas derivative contracts and $6.1 million from the
termination of crude oil contracts. Proceeds from these contracts
were used to pay down outstanding borrowings under our credit
facility.
For the
year ended December 31, 2008, we had realized losses of $55.9 million and
unrealized gains of $388.0 million relating to our market based commodity
contracts. We had net financial instruments receivable relating to
our commodity contracts of $292.3 million at December 31, 2008. On
September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated our crude
oil derivative instruments with Lehman Brothers. Our derivative
contract with Lehman Brothers, commonly referred to as a “zero cost collar,” was
for oil volumes of 1,000 Bbls/d for the full year 2011. This represented
approximately eight percent of our total 2011 oil and natural gas hedge
portfolio. The floor price for the collar was $105.00 per Bbl and the ceiling
price was $174.50 per Bbl. This contract was replaced by contracts
with substantially similar terms, with different counterparties, for oil volumes
of 1,000 Bbls/d covering January 1, 2011 to January 31, 2011 and March 1, 2011
to December 31, 2011.
- 26
-
For the
year ended December 31, 2007, we had realized losses of $6.6 million and
unrealized losses of $103.9 million relating to our market based commodity
contracts.
Including
the impact of the changes noted above we had the following contracts in place at
December 31, 2009:
Year
|
||||||||||||||||||||
2010
|
2011
|
2012
|
2013
|
2014
|
||||||||||||||||
Gas
Positions:
|
||||||||||||||||||||
Fixed
Price Swaps:
|
||||||||||||||||||||
Hedged
Volume (MMBtu/d)
|
43,869 | 25,955 | 19,129 | 27,000 | - | |||||||||||||||
Average
Price ($/MMBtu)
|
$ | 8.20 | $ | 7.26 | $ | 7.10 | $ | 6.92 | $ | - | ||||||||||
Collars:
|
||||||||||||||||||||
Hedged
Volume (MMBtu/d)
|
3,405 | 16,016 | 19,129 | - | - | |||||||||||||||
Average
Floor Price ($/MMBtu)
|
$ | 9.00 | $ | 9.00 | $ | 9.00 | $ | - | $ | - | ||||||||||
Average
Ceiling Price ($/MMBtu)
|
$ | 12.79 | $ | 11.28 | $ | 11.89 | $ | - | $ | - | ||||||||||
Total:
|
||||||||||||||||||||
Hedged
Volume (MMBtu/d)
|
47,275 | 41,971 | 38,257 | 27,000 | - | |||||||||||||||
Average
Price ($/MMBtu)
|
$ | 8.26 | $ | 7.92 | $ | 8.05 | $ | 6.92 | $ | - | ||||||||||
Oil
Positions:
|
||||||||||||||||||||
Fixed
Price Swaps:
|
||||||||||||||||||||
Hedged
Volume (Bbls/d)
|
2,808 | 2,616 | 2,539 | 3,500 | 748 | |||||||||||||||
Average
Price ($/Bbl)
|
$ | 81.35 | $ | 66.22 | $ | 67.24 | $ | 76.79 | $ | 88.65 | ||||||||||
Participating
Swaps: (a)
|
||||||||||||||||||||
Hedged
Volume (Bbls/d)
|
1,993 | 1,439 | - | - | - | |||||||||||||||
Average
Price ($/Bbl)
|
$ | 64.40 | $ | 61.29 | $ | - | $ | - | $ | - | ||||||||||
Average
Participation %
|
55.5 | % | 53.2 | % | - | - | - | |||||||||||||
Collars:
|
||||||||||||||||||||
Hedged
Volume (Bbls/d)
|
1,279 | 2,048 | 2,477 | 500 | - | |||||||||||||||
Average
Floor Price ($/Bbl)
|
$ | 102.85 | $ | 103.42 | $ | 110.00 | $ | 77.00 | $ | - | ||||||||||
Average
Ceiling Price ($/Bbl)
|
$ | 136.16 | $ | 152.61 | $ | 145.39 | $ | 103.10 | $ | - | ||||||||||
Floors:
|
||||||||||||||||||||
Hedged
Volume (Bbls/d)
|
500 | - | - | - | - | |||||||||||||||
Average
Floor Price ($/Bbl)
|
$ | 100.00 | $ | - | $ | - | $ | - | $ | - | ||||||||||
Total:
|
||||||||||||||||||||
Hedged
Volume (Bbls/d)
|
6,580 | 6,103 | 5,016 | 4,000 | 748 | |||||||||||||||
Average
Price ($/Bbl)
|
$ | 81.81 | $ | 77.54 | $ | 88.35 | $ | 76.82 | $ | 88.65 |
(a) A
participating swap combines a swap and a call option with the same strike
price.
- 27
-
Interest
Rate Activities
We are
subject to interest rate risk associated with loans under our credit facility
that bear interest based on floating rates. As of December 31, 2009,
our total debt outstanding was $559 million. In order to mitigate our
interest rate exposure, we had the following interest rate swaps in place at
December 31, 2009, to fix a portion of floating LIBOR-base debt on our credit
facility:
Notional amounts in thousands of dollars
|
Notional Amount
|
Fixed Rate
|
||||||
Period
Covered
|
||||||||
January
1, 2010 to January 8, 2010
|
$ | 100,000 | 3.3873 | % | ||||
January
1, 2010 to December 20, 2010
|
300,000 | 3.6825 | % | |||||
January
20, 2010 to October 20, 2011
|
100,000 | 1.6200 | % | |||||
December
20, 2010 to October 20, 2011
|
200,000 | 2.9900 | % |
For the
year ended December 31, 2009, we had realized losses of $13.1 million and
unrealized gains of $5.9 million relating to our interest rate
swaps. We had net financial instruments payable related to our
interest rate swaps of $11.4 million at December 31, 2009.
For the
year ended December 31, 2008, we had realized losses of $2.7 million and
unrealized losses of $17.3 million relating to our interest rate
swaps. We had net financial instruments payable related to our
interest rate swaps of $17.3 million at December 31, 2008. On
September 19, 2008, due to Lehman Brothers’ bankruptcy, we terminated, at no
cost, our interest rate swap with Lehman Brothers for $50 million at a fixed
rate of 3.438 percent, which covered the period from January 8, 2008 to July 8,
2009. On October 2, 2008, we entered into a new interest rate swap
for $50 million at a fixed rate of 3.0450 percent, for the period from September
8, 2008 to July 8, 2009.
ASC 815
requires disclosures about how and why an entity uses derivative instruments,
how derivative instruments and related hedge items are accounted for under ASC
815, and how derivative instruments and related hedged items affect an entity’s
financial position, financial performance, and cash flows. This topic
requires the disclosures detailed below.
- 28
-
Fair
value of derivative instruments not designated as hedging instruments under ASC
815:
Balance sheet location, thousands of
dollars
|
Oil
Commodity
Derivatives
|
Natural Gas
Commodity
Derivatives
|
Interest
Rate
Derivatives
|
Commodity
derivative
netting (a)
|
Total
Financial
Instruments
|
|||||||||||||||
December
31, 2009
|
||||||||||||||||||||
Assets
|
||||||||||||||||||||
Current
assets - derivative instruments
|
$ | 17,666 | $ | 39,467 | $ | - | $ | - | $ | 57,133 | ||||||||||
Other
long-term assets - derivative instruments
|
35,382 | 42,620 | - | (3,243 | ) | 74,759 | ||||||||||||||
Total
assets
|
53,048 | 82,087 | - | (3,243 | ) | 131,892 | ||||||||||||||
Liabilities
|
||||||||||||||||||||
Current
liabilities - derivative instruments
|
(10,234 | ) | - | (9,823 | ) | - | (20,057 | ) | ||||||||||||
Long-term
liabilities - derivative instruments
|
(51,730 | ) | - | (1,622 | ) | 3,243 | (50,109 | ) | ||||||||||||
Total
liabilities
|
(61,964 | ) | - | (11,445 | ) | 3,243 | (70,166 | ) | ||||||||||||
Net
assets (liabilities)
|
$ | (8,916 | ) | $ | 82,087 | $ | (11,445 | ) | $ | - | $ | 61,726 | ||||||||
December
31, 2008
|
||||||||||||||||||||
Assets
|
||||||||||||||||||||
Current
assets - derivative instruments
|
$ | 44,086 | $ | 32,138 | $ | - | $ | - | $ | 76,224 | ||||||||||
Other
long-term assets - derivative instruments
|
145,061 | 73,942 | - | - | 219,003 | |||||||||||||||
Total
assets
|
189,147 | 106,080 | - | - | 295,227 | |||||||||||||||
Liabilities
|
||||||||||||||||||||
Current
liabilities - derivative instruments
|
(1,115 | ) | - | (9,077 | ) | - | (10,192 | ) | ||||||||||||
Long-term
liabilities - derivative instruments
|
(1,820 | ) | - | (8,238 | ) | - | (10,058 | ) | ||||||||||||
Total
liabilities
|
(2,935 | ) | - | (17,315 | ) | - | (20,250 | ) | ||||||||||||
Net
assets (liabilities)
|
$ | 186,212 | $ | 106,080 | $ | (17,315 | ) | $ | - | $ | 274,977 |
(a)
Represents counterparty netting under derivative netting agreements - these
contracts are reflected net on the balance sheet.
Gains and
losses on derivative instruments not designated as hedging instruments under ASC
815:
Location of gain/loss, thousands of
dollars
|
Oil
Commodity
Derivatives (a)
|
Natural Gas
Commodity
Derivatives (a)
|
Interest Rate
Derivatives (b)
|
Total
Financial
Instruments
|
||||||||||||
Year
Ended December 31, 2009
|
||||||||||||||||
Realized
gains (losses)
|
66,176 | 101,507 | (13,115 | ) | $ | 154,568 | ||||||||||
Unrealized
gains (losses)
|
(195,127 | ) | (23,993 | ) | 5,869 | (213,251 | ) | |||||||||
Net
gains (losses)
|
$ | (128,951 | ) | $ | 77,514 | $ | (7,246 | ) | $ | (58,683 | ) | |||||
Year
Ended December 31, 2008
|
||||||||||||||||
Realized
losses
|
$ | (35,146 | ) | $ | (20,800 | ) | $ | (2,721 | ) | $ | (58,667 | ) | ||||
Unrealized
gains (losses)
|
293,720 | 94,328 | (17,314 | ) | 370,734 | |||||||||||
Net
gains (losses)
|
$ | 258,574 | $ | 73,528 | $ | (20,035 | ) | $ | 312,067 |
(a)
Included in gains (losses) on commodity derivative instruments on the
consolidated statements of operations.
(b)
Included in loss on interest rate swaps on the consolidated statements of
operations.
Effective
January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” now
codified within ASC 820 “Fair
Value Measurements and Disclosures.” ASC 820 defines fair value,
establishes a framework for measuring fair value and establishes required
disclosures about fair value measurements. Fair value measurement
under ASC 820 is based upon a hypothetical transaction to sell an asset or
transfer a liability at the measurement date, considered from the perspective of
a market participant that holds the asset or owes the liability. The
objective of fair value measurement as defined in ASC 820 is to determine the
price that would be received in selling the asset or transferring the liability
in an orderly transaction between market participants at the measurement
date. If there is an active market for the asset or liability, the
fair value measurement shall represent the price in that market whether the
price is directly observable or otherwise obtained using a valuation
technique.
- 29
-
ASC 820
requires valuation techniques consistent with the market approach, income
approach or cost approach to be used to measure fair value. The
market approach uses prices and other relevant information generated by market
transactions involving identical or comparable assets or
liabilities. The income approach uses valuation techniques to convert
future cash flows or earnings to a single present value amount and is based upon
current market expectations about those future amounts. The cost
approach, sometimes referred to as the current replacement cost approach, is
based upon the amount that would currently be required to replace the service
capacity of an asset.
We
principally use the income approach for our recurring fair value measurements
and strive to use the best information available. We use valuation
techniques that maximize the use of observable inputs and obtain the majority of
our inputs from published objective sources or third party market
participants. We incorporate the impact of nonperformance risk,
including credit risk, into our fair value measurements.
ASC 820
also establishes a fair value hierarchy that prioritizes the inputs to valuation
techniques into three broad levels based upon how observable those inputs
are. The highest priority of Level 1 is given to unadjusted quoted
prices in active markets for identical assets or liabilities and the lowest
priority of Level 3 is given to unobservable inputs. We categorize
our fair value financial instruments based upon the objectivity of the inputs
and how observable those inputs are. The three levels of inputs as
defined in ASC 820 are described further as follows:
Level 1 –
Unadjusted quoted prices in active markets for identical assets or liabilities
as of the reporting date. Active markets are markets in which
transactions for the asset or liability occur with sufficient frequency and
volume to provide pricing information on an ongoing basis. An example
of a Level 1 input would be quoted prices for exchange traded commodity futures
contracts.
Level 2 –
Inputs other than quoted prices that are included in Level 1. Level 2
includes financial instruments that are actively traded but are valued using
models or other valuation methodologies. These models include
industry standard models that consider standard assumptions such as quoted
forward prices for commodities, interest rates, volatilities, current market and
contractual prices for underlying assets as well as other relevant
factors. Substantially all of these inputs are evident in the market
place throughout the terms of the financial instruments and can be derived by
observable data, including third party data providers. These inputs
may also include observable transactions in the market place. We
consider the over the counter (“OTC”) commodity and interest rate swaps in our
portfolio to be Level 2. These are assets and liabilities that can be
bought and sold in active markets and quoted prices are available from multiple
potential counterparties.
Level 3 –
Inputs that are not directly observable for the asset or liability and are
significant to the fair value of the asset or liability. These inputs
generally reflect management’s estimates of the assumptions market participants
would use when pricing the instruments. Level 3 includes financial
instruments that are not actively traded and have little or no observable data
for input into industry standard models. Level 3 instruments
primarily include derivative instruments for which we do not have sufficient
corroborating market evidence, such as binding broker quotes, to support
classifying the asset or liability as Level 2. Level 3 also
includes complex structured transactions that sometimes require the use of
non-standard models.
Certain
OTC derivatives that trade in less liquid markets or contain limited observable
model inputs are currently included in Level 3. We include these
assets and liabilities in Level 3 as required by current interpretations of ASC
820. As of December 31, 2009 and December 31, 2008, our Level 3
derivative assets and liabilities consisted entirely of OTC commodity put and
call options.
Financial
assets and liabilities that are categorized in Level 3 may later be
reclassified to the Level 2 category at the point we are able to obtain
sufficient binding market data or the interpretation of Level 2 criteria is
modified in practice to include non-binding market corroborated
data.
Through
December 2009, we contracted with Provident on a month-to-month basis for
certain derivative instrument valuation services. Provident’s risk
management group calculated the fair values of our commodity and interest rate
hedges using software that marks to market our hedge contracts using forward
commodity price curves and interest rates. Inputs were obtained from third
party data providers and were verified to published data where available (e.g.,
NYMEX).
- 30
-
Beginning
in the fourth quarter of 2009, our Treasury/Risk Management group began
calculating the fair value of our commodity and interest rate swaps and
options. For the fourth quarter of 2009, we compared our fair value
calculations to those received from the counterparties to our derivative
instruments and to those received from Provident, our former fair valuation
provider, and determined that our valuation results were consistent with those
of our counterparties and Provident. As such, we used our valuation
for December 31, 2009. Beginning January 1, 2010, we no longer obtain
fair value calculations for our derivative instruments from Provident, but
calculate them internally and continue to compare these fair value amounts to
the fair value amounts that we receive from the counterparties on a monthly
basis. Any differences will be resolved and any required changes will
be recorded prior to the issuance of our financial
statements.
The model
we utilize to calculate the fair value of our commodity derivative instruments
is a standard option pricing model. Inputs to the option pricing
models include fixed monthly commodity strike prices and volumes from each
specific contract, commodity prices from commodity forward price curves,
volatility and interest rate factors and time to expiry. Model inputs are
obtained from our counterparties and third party data providers and are verified
to published data where available (e.g., NYMEX).
Financial
assets and liabilities carried at fair value on a recurring basis are presented
in the table below. Our assessment of the significance of an input to
its fair value measurement requires judgment and can affect the valuation of the
assets and liabilities as well as the category within which they are
categorized.
Recurring fair value measurements at
December 31, 2009 and December 31, 2008:
As of December 31, 2009
|
||||||||||||||||
Thousands of dollars
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
Assets
(Liabilities):
|
||||||||||||||||
Commodity
Derivatives (swaps, put and call options)
|
$ | - | $ | (29,303 | ) | $ | 102,475 | $ | 73,172 | |||||||
Other
Derivatives (interest rate swaps)
|
- | (11,446 | ) | - | (11,446 | ) | ||||||||||
Total
|
$ | - | $ | (40,749 | ) | $ | 102,475 | $ | 61,726 |
As of December 31, 2008
|
||||||||||||||||
Thousands of dollars
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||
Assets
(Liabilities):
|
||||||||||||||||
Commodity
Derivatives (swaps, put and call options)
|
$ | - | $ | 139,074 | $ | 153,218 | $ | 292,292 | ||||||||
Other
Derivatives (interest rate swaps)
|
- | (17,315 | ) | - | (17,315 | ) | ||||||||||
Total
|
$ | - | $ | 121,759 | $ | 153,218 | $ | 274,977 |
The
following table sets forth a reconciliation primarily of changes in fair value
of our derivative instruments classified as Level 3:
Year Ended December
31,
|
||||||||
Thousands of
dollars
|
2009
|
2008
|
||||||
Assets
(Liabilities):
|
||||||||
Beginning
balance
|
$ | 153,218 | $ | 44,236 | ||||
Realized
and unrealized gains (losses)
|
(44,713 | ) | 106,154 | |||||
Purchases
and issuances
|
- | 7,452 | ||||||
Settlements
(a)
|
(6,030 | ) | (4,624 | ) | ||||
Ending
balance
|
$ | 102,475 | $ | 153,218 |
(a)
Settlements reflect the monetization of oil collar contracts in June 2009 and
the termination of derivative contracts with Lehman in September 2008 due to the
Lehman bankruptcy.
- 31
-
Unrealized
losses of $63.8 million for the year ended December 31, 2009 related to our
derivative instruments classified as Level 3 are included in Gains (losses) on
commodity derivative instruments, net on the consolidated statements of
operations. Realized gains of $19.1 million for the year ended
December 31, 2009 related to our derivative instruments classified as Level 3
are also included in gains (losses) on commodity derivative instruments, net on
the consolidated statements of operations. Unrealized gains of $112.2
million for the year ended December 31, 2008 related to our derivative
instruments classified as Level 3 are included in gains (losses) on commodity
derivative instruments, net on the consolidated statements of
operations. Realized losses of $6.0 million for the year ended
December 31, 2008 related to our derivative instruments classified as Level 3
are also included in gains (losses) on commodity derivative instruments, net on
the consolidated statements of operations. Determination of fair
values incorporates various factors as required by ASC 820 including, but not
limited to, the credit standing of the counterparties, the impact of guarantees
as well as our own abilities to perform on our liabilities.
17. Unit
and Other Valuation-Based Compensation Plans
BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering. All of our employees, including our executives, are
employees of BreitBurn Management. On June 17, 2008, in connection
with the Purchase, Contribution and Partnership Transactions, BreitBurn
Management became our wholly owned subsidiary and entered into an Amended and
Restated Administrative Services Agreement with BEC, pursuant to which BreitBurn
Management agreed to continue to provide administrative services to
BEC. In addition, BreitBurn Management agreed to continue to charge
BEC for direct expenses, including incentive plan costs and direct payroll and
administrative costs. Beginning on June 17, 2008, all of BreitBurn
Management’s costs that were not charged to BEC are consolidated with our
results.
Prior to
June 17, 2008, BreitBurn Management provided services to us and to BEC, and
allocated its expenses between the two entities. We were managed by
our General Partner, the executive officers of which were and are employees of
BreitBurn Management. We had entered into an Administrative Services
Agreement with BreitBurn Management. Under the Administrative
Services Agreement, we reimbursed BreitBurn Management for all direct and
indirect expenses it incurred in connection with the services it performed on
our behalf (including salary, bonus, certain incentive compensation and other
amounts paid to executive officers and other employees).
Effective
on the initial public offering date of October 10, 2006, BreitBurn Management
adopted the existing Long-Term Incentive Plan (BreitBurn Management LTIP) and
the Unit Appreciation Rights Plan (UAR plan) of the predecessor as previously
amended. The predecessor’s Executive Phantom Option Plan, Unit
Appreciation Plan for Officers and Key Individuals (Founders Plan), and the
Performance Trust Units awarded to the Chief Financial Officer during 2006 under
the BreitBurn Management LTIP, were adopted by BreitBurn Management with
amendments at the initial public offering date as described in the subject plan
discussions below.
We may
terminate or amend the long-term incentive plan at any time with respect to any
units for which a grant has not yet been made. We also have the right
to alter or amend the long-term incentive plan or any part of the plan from time
to time, including increasing the number of units that may be granted subject to
the requirements of the exchange upon which the Common Units are listed at that
time. However, no change in any outstanding grant may be made that
would materially reduce the rights or benefits of the participant without the
consent of the participant. The plan will expire when units are no
longer available under the plan for grants or, if earlier, it is terminated by
us.
Unit
Based Compensation
ASC 718
“Compensation – Stock
Compensation” establishes standards for charging compensation expenses
based on fair value provisions. At December 31,
2009, the Restricted Phantom Units (RPUs) and the Convertible Phantom Units
(CPUs) granted under the BreitBurn Management LTIP as well as the outstanding
Directors RPUs discussed below were all classified as equity awards under the
provisions of ASC 718. These awards are being recognized as
compensation expense on a straight line basis over the annual vesting periods as
prescribed in the award agreements.
Prior
year awards classified as liabilities were revalued at each reporting period
using the Black-Scholes option pricing model and changes in the fair value of
the options were recognized as compensation expense over the vesting schedules
of the awards. These awards were settled in cash or had the option of
being settled in cash or units at the choice of the holder, and were indexed to
either our Common Units or to Provident Trust Units. The
liability-classified option awards were distribution-protected awards through
either an Adjustment Ratio as defined in the plan or the holders received
cumulative distribution amounts upon vesting equal to the actual distribution
amounts per Common Unit of the underlying notional Units.
- 32
-
In
connection with the changes to BreitBurn Management’s executive compensation
program during 2007, employees of BreitBurn Management began to receive two new
types of awards under our LTIP, namely, Restricted Phantom Units (RPUs) and
Convertible Phantom Units (CPUs).
We
recognized $12.7 million of compensation expense related to our various plans
for the year ended December 31, 2009.
Restricted
Phantom Units (RPUs)
RPUs are
phantom equity awards that, to the extent vested, represent the right to receive
actual partnership units upon specified payment events. Certain
employees of BreitBurn Management including its executives are eligible to
receive RPU awards. We believe that RPUs properly incentivize holders
of these awards to grow stable distributions for our common
unitholders. RPUs generally vest in three equal annual installments
on each anniversary of the vesting commencement date of the award. In
addition, each RPU is granted in tandem with a distribution equivalent right
that will remain outstanding from the grant of the RPU until the earlier to
occur of its forfeiture or the payment of the underlying unit, and which
entitles the grantee to receive payment of amounts equal to distributions paid
to each holder of an actual partnership unit during such period. RPUs
that do not vest for any reason are forfeited upon a grantee’s termination of
employment.
RPU
awards were granted to BreitBurn Management employees in 2009, 2008 and 2007 as
shown in the table below. We recorded compensation expense of $9.1
million in 2009, $3.4 million in 2008 and $7.0 million in 2007. As of
December 31, 2009, there was $13.7 million of total unrecognized compensation
cost remaining for the unvested RPUs. This amount is expected to be
recognized over the remaining two year vesting period.
Compensation
expense recorded in 2009 and 2008 relates to the amortization of outstanding
RPUs over their related vesting periods. Compensation expense of $7.0
million recorded in 2007 was primarily due to the exchange of executive phantom
options awards for RPUs in 2007. Pursuant to the employment
agreements between the predecessor and the Co-Chief Executive Officers, which
were adopted by us and BreitBurn Management at January 1, 2007, the Co-Chief
Executive Officers were each awarded 336,364 phantom option units at a grant
price of $24.10 per unit under the executive phantom option
plan. These phantom units, in late 2007, were cancelled and
terminated in exchange for the right to receive a lump-sum payment of $2.4
million and 184,400 of Restricted Phantom Units (RPUs) at a grant price of
$31.68 per unit, which has a fair value of $5.8 million. The RPUs
will vest and be paid in Common Units in three equal annual installments on each
anniversary date of the vesting commencement date of the award. They
will receive quarterly distributions at the same rate payable to common
unitholders immediately after grant. Of the total amount expensed in
2007, $4.6 million was recorded to equity. The remaining fair value
of the awards in the amount of $1.2 million is being expensed ratably over a
three-year period beginning in 2008. The remaining 188,545 RPUs
issued in 2007 were issued to the top seven executives – including the Co-Chief
Executive Officers - at a grant price of $30.29 per Common
Unit.
- 33
-
The
following table summarizes information about RPUs:
December 31,
|
||||||||||||||||||||||||
2009
|
2008
|
2007 (a)
|
||||||||||||||||||||||
Number of
|
Weighted
|
Number of
|
Weighted
|
Number of
|
Weighted
|
|||||||||||||||||||
RPU
|
Average
|
RPU
|
Average
|
RPU
|
Average
|
|||||||||||||||||||
Units
|
Fair Value *
|
Units
|
Fair Value*
|
Units
|
Fair Value*
|
|||||||||||||||||||
Outstanding
, beginning of period
|
607,263 | $ | 26.91 | 372,945 | $ | 30.98 | - | $ | - | |||||||||||||||
Granted
|
1,790,589 | 8.17 | 245,290 | 20.44 | 372,945 | 30.98 | ||||||||||||||||||
Exercised
|
(808,700 | ) | 13.08 | - | - | - | - | |||||||||||||||||
Cancelled
|
(14,402 | ) | 14.45 | (10,972 | ) | 20.83 | - | - | ||||||||||||||||
Outstanding,
end of period
|
1,574,750 | $ | 12.82 | 607,263 | $ | 26.91 | 372,945 | $ | 30.98 | |||||||||||||||
Exercisable,
end of period
|
- | $ | - | - | $ | - | - | $ | - |
* At
grant date
(a) 2007
includes Co-Chief Executive Officers' 184,400 RPUs received as a result of the
termination of the executive phantom option plan in November 2007.
Convertible Phantom Units
(CPUs)
In
December 2007, seven executives received 681,500 units of CPUs at a grant price
of $30.29 per Common Unit. Each of the awards has the vesting
commencement date of January 1, 2008. CPUs are significantly tied to
the amount of distributions we make to holders of our Common
Units. As discussed further below, the number of CPUs ultimately
awarded to each of these senior executives will be based upon the level of
distributions to common unitholders achieved during the term of the
CPUs. The CPU grants vest over a longer-term period of up to five
years. Therefore, these grants will not be made on an annual
basis. New grants could be made at the Board’s discretion at a future
date after the present CPU grants have vested.
CPUs
vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the
aggregate amount of distributions paid to common unitholders for any four
consecutive quarters during the term of the award is greater than or equal to
$3.10 per Common Unit and (iii) upon the occurrence of the death or “disability”
of the grantee or his or her termination without “cause” or for “good reason”
(as defined in the holder’s employment agreement, if
applicable). Unvested CPUs are forfeited in the event that the
grantee ceases to remain in the service of BreitBurn
Management. Prior to vesting, a holder of a CPU is entitled to
receive payments equal to the amount of distributions made by us with respect to
each of the Common Units multiplied by the number of Common Unit equivalents
underlying the CPUs at the time of the distribution.
Under the
original CPU Agreements, one Common Unit Equivalent (CUE) underlies each CPU at
the time it was awarded to the grantee. However, the number of CUEs
underlying the CPUs would increase at a compounded rate of 25 percent upon the
achievement of each 5 percent compounded increase in the distributions paid by
us to our common unitholders. Conversely, the number of CUEs
underlying the CPUs would decrease at a compounded rate of 25 percent if the
distributions paid by us to our common unitholders decreases at a compounded
rate of 5 percent.
On
October 29, 2009, the Compensation and Governance Committee approved an
amendment to each of the existing CPU Agreements entered into with each named
executive officer. Originally under the CPU Agreements, the number of
CUEs per CPU could be reduced over the five year life of the agreement to a
minimum of zero, or be multiplied by a maximum of 4.768 times, based on our
distribution levels. We suspended the payment of distributions in
April 2009; therefore, holders of CPU’s did not receive any distributions under
the CPU Agreements as long as distributions were suspended. Under the
original chart, if the CPU’s were to vest currently – for instance in the case
of the death or disability of a holder – zero units would vest to that
holder. The Committee determined that the elimination of multipliers
between zero and one best represented the original incentive and retention
purpose of the CPU Agreements. With this modification to the CPU
Agreements, the number of CUEs per CPU can no longer be less than one,
regardless of Common Unit distribution levels.
- 34
-
On
January 29, 2010, the Committee also approved an amendment to each of the
existing Convertible Phantom Unit (“CPU”) Agreements entered into with each
named executive officer. Under these agreements,
each CPU entitles its holder to receive (i) a number of our Common Units at the
time of vesting equal to the number of “common unit equivalents” (“CUEs”)
underlying the CPU at vesting, and (ii) current distributions on Common Units
during the vesting period based on the number of CUEs underlying the CPU at the
time of such distribution. The number of CUEs underlying each CPU is
determined by reference to Common Unit distribution levels during the applicable
vesting period, generally calculated based upon the aggregate amount of
distributions made per Common Unit for the four quarters preceding
vesting. The amendment to the CPU agreements now limits the
multiplier for 20 percent of the total number of CPUs and related CUEs granted
in each award to “1.” As a result, upon vesting, CPUs for 20 percent
of each award will convert to Common Units on a 1:1 basis, and with respect to
that portion of the award, holders will lose the ability to earn additional
Common Units based on increased distributions on Common Units. No
other modification was made to the CPU Agreements under this
amendment. Because we were accruing compensation expense using a CPU
multiplier of one, these amendments had no impact on compensation expense
recorded.
In the
event that the CPUs vest on January 1, 2013 or if the aggregate amount of
distributions paid to common unitholders for any four consecutive quarters
during the term of the award is greater than $3.10 per Common Unit, the CPUs
would convert into a number of Common Units equal to the number of Common Unit
equivalents underlying the CPUs at such time (calculated based upon the
aggregate amount of distributions made per Common Unit for the preceding four
quarters subject to the 80 percent limitation put in place on January 29, 2010
as noted above).
In the
event that CPUs vest due to the death or disability of the grantee or his or her
termination without cause or good reason, the CPUs would convert into a number
of Common Units equal to the number of Common Unit equivalents underlying the
CPUs at such time, pro-rated based the date of death or
disability. First, the number of Common Unit equivalents would be
calculated based upon the aggregate amount of distributions made per Common Unit
for the preceding four quarters or, if such calculation would provide for a
greater number of Common Unit equivalents, the most recently announced quarterly
distribution level by us on an annualized basis (subject to the 80 percent
limitation noted above). Then, this number would be pro rated by
multiplying it by a percentage equal to:
|
·
|
if
such termination occurs on or before December 31, 2008, a percentage equal
to 40 percent;
|
|
·
|
if
such termination occurs on or before December 31, 2009, a percentage equal
to 60 percent;
|
|
·
|
if
such termination occurs on or before December 31, 2010, a percentage equal
to 80 percent; and
|
|
·
|
if
such termination occurs on or after January 1, 2011, a percentage equal to
100 percent.
|
For the
CPUs, we recorded compensation expense of $4.1 million in 2009 and $4.1 million
in 2008. At December 31, 2009, there was $12.3 million of total
unrecognized compensation cost related to the unvested CPUs
remaining. This amount is expected to be recognized over the next
three years.
Founders
Plan Awards
Under the
Founders Plan, participants received unit appreciation rights which provide cash
compensation in relation to the appreciation in the value of a specified number
of underlying notional phantom units. The value of the unit
appreciation rights was determined on the basis of a valuation of the
predecessor at the end of the fiscal period plus distributions during the period
less the value of the predecessor at the beginning of the period. The
base price and vesting terms were determined by BreitBurn Management at the time
of the grant. Outstanding unit appreciation rights vest in the
following manner: one-third vest three years after the grant date, one-third
vest four years after the grant date and one-third vest five years after the
grant date and are subject to specified service requirements.
Effective
on the initial public offering date of October 10, 2006, all outstanding unit
appreciation rights under the Founders Plan were adopted by BreitBurn Management
and converted into three separate awards. The first and second awards
became the obligations of our predecessor. The third award
represented 309,570 Partnership unit appreciation rights at a base price of
$18.50 per unit with respect to the operations of the properties that were
transferred to us for the period beginning on the initial public offering date
of October 10, 2006. The award is liability-classified and is being
charged to us as compensation expense over the remaining vesting
schedule. The value of the outstanding Partnership unit appreciation
rights is remeasured each period using a Black-Scholes option pricing
model. Market prices of $10.59, $7.05 and $28.90 were used in the
model for the periods ending December 31, 2009, 2008 and 2007,
respectively. Expected volatility ranged from 9 percent to 21 percent
and had a weighted average volatility of 9.8 percent. The average
risk free rate used was approximately 3.3 percent. The expected
option terms ranged from one half year to two and one half years.
We
recorded credits of approximately $0.4 million and $0.3 million and a charge of
$2.7 million of compensation expense under the plan for the years ended December
31, 2009, December 31, 2008 and December 31, 2007, respectively. The
aggregate value of the vested and unvested unit appreciation rights was zero at
December 31, 2009.
- 35
-
The
following table summarizes information about Appreciation Rights Units issued
under the Founders Plan:
December 31,
|
||||||||||||||||||||||||
2009
|
2008
|
2007
|
||||||||||||||||||||||
Number of
|
Weighted
|
Number of
|
Weighted
|
Number of
|
Weighted
|
|||||||||||||||||||
Appreciation
|
Average
|
Appreciation
|
Average
|
Appreciation
|
Average
|
|||||||||||||||||||
Rights Units
|
Exercise Price
|
Rights Units
|
Exercise Price
|
Rights Units
|
Exercise Price
|
|||||||||||||||||||
Outstanding
, beginning of period
|
122,644 | $ | 18.50 | 214,107 | $ | 18.50 | 305,570 | $ | 18.50 | |||||||||||||||
Exercised
|
- | - | (91,463 | ) | 18.50 | (91,463 | ) | 18.50 | ||||||||||||||||
Cancelled
(a)
|
(101,856 | ) | 18.50 | - | - | - | - | |||||||||||||||||
Outstanding,
end of period
|
20,788 | $ | 18.50 | 122,644 | $ | 18.50 | 214,107 | $ | 18.50 | |||||||||||||||
Exercisable,
end of period
|
- | $ | - | - | $ | - | - | $ | - |
(a) These
units expired out of the money and the remaining units outstanding at year end
will vest one half in 2010 and one half in 2011.
BreitBurn
Management LTIP and the Partnership LTIP
BreitBurn Management
LTIP
In
September 2005, certain employees other than the Co-Chief Executive Officers of
the predecessor were granted restricted units (RTUs) and/or performance units
(PTUs), both of which entitle the employee to receive cash compensation in
relation to the value of a specified number of underlying notional trust units
indexed to Provident Energy Trust Units. The grants are based on
personal performance objectives. This plan replaced the Unit
Appreciation Right Plan for Employees and Consultants for the period after
September 2005 and subsequent years. RTUs vest one third at the end
of year one, one third at the end of year two and one third at the end of year
three after grant. In general, cash payments equal to the value of
the underlying notional units were made on the anniversary dates of the RTU to
the employees entitled to receive them. PTUs vest three years from
the end of the third year after grant and the payout can range from zero to two
hundred percent of the initial grant depending on the total return of the
underlying notional units as compared to the returns of selected peer
companies. The total return of the Provident Energy Trust unit is
compared with the return of 25 selected Canadian trusts and
funds. The Provident indexed PTUs granted in 2005 and 2006 entitle
employees to receive cash payments equal to the market price of the underlying
notional units. Under our LTIP, Partnership indexed PTUs were granted
in 2007 and are payable in cash or may be paid in Common Units if elected at
least 60 days prior to vesting by the grantees. The total return of
the Partnership unit is compared with the return of 49 companies in the Alerian
MLP Index for the payout multiplier. All of the grants are
liability-classified. Underlying notional units are established based
on target salary LTIP threshold for each employee. The awarded
notional units are adjusted cumulatively thereafter for distribution payments
through the use of an adjustment ratio. The estimated fair value
associated with RTUs and PTUs is expensed in the statement of income over the
vesting period.
On June
17, 2008, we entered into the BreitBurn Management Purchase agreement with Pro
LP and Pro GP. The BreitBurn Management Purchase Agreement contains
certain covenants of the parties relating to the allocation of responsibility
for liabilities and obligations under certain pre-existing equity-based
compensation plans adopted by BreitBurn Management, BEC and us. The
pre-existing compensation plans include the outstanding 2005 and 2006 LTIP
grants which are indexed to the Provident Trust Units. As a result,
we paid $0.9 million for our share of the 2005 LTIP grants that vested in June
2008 in accordance with the agreed allocation of liability.
In
September 2008, BreitBurn Management made an offer to holders of the 2006 LTIP
grants to cash out their Provident-indexed units at $10.32 per share before the
normal vesting date of December 31, 2008. By the end of September
2008, the offer was accepted by all employees who had outstanding 2006 LTIP
grants. Consequently, compensation expense was recognized for the
full amount of the remaining unvested liability during
2008. BreitBurn Management paid employees $0.6 million in 2008 for
its share of the 2006 LTIP grants in accordance with the agreed allocation of
liability.
We
recognized no expense for the year ended December 31, 2009, $0.9 million and
$0.4 million of compensation expense for the years ended December 31, 2008 and,
December 31, 2007, respectively. The following table summarizes
information about the restricted/performance units granted in 2005 and
2006:
- 36
-
PVE indexed units
|
||||||||||||||||
December 31,
|
||||||||||||||||
2008
|
2007
|
|||||||||||||||
Weighted
|
Weighted
|
|||||||||||||||
Number of
|
Average
|
Number of
|
Average
|
|||||||||||||
Units
|
Grant Price
|
Units
|
Grant Price
|
|||||||||||||
Outstanding
, beginning of period
|
267,702 | $ | 10.77 | 318,389 | $ | 10.82 | ||||||||||
Granted
|
- | - | - | - | ||||||||||||
Exercised
|
(267,351 | ) | 10.77 | (36,203 | ) | 10.87 | ||||||||||
Cancelled
|
(351 | ) | 10.73 | (14,484 | ) | 11.53 | ||||||||||
Outstanding,
end of period
|
- | $ | 10.77 | 267,702 | $ | 10.77 | ||||||||||
Exercisable,
end of period
|
- | $ | - | - | $ | - |
Partnership
LTIP
Under our
LTIP, Partnership-indexed restricted units (RTUs) and/or performance units
(PTUs) were granted in 2007 certain individuals other than the Co-Chief
Executive Officers. RTUs vest one third at the end of year one, one
third at the end of year two and one third at the end of year three after
grant. In general, cash payments equal to the value of the underlying
notional units were made on the anniversary dates of the RTUs. PTUs
vest three years from the end of third year after grant and are payable in cash
or in Common Units of the Partnership if elected by the grantee at least 60 days
prior to the vesting date. PTU payouts are further determined by a
performance multiplier which can range from zero to two hundred percent of the
initial grant depending on the total return of the underlying notional units as
compared to the returns of a selected peer group of companies. The
multiplier is determined by comparing our total return to the returns of 49
companies in the Alerian MLP Index. Underlying notional units are
established based on target salary LTIP threshold for each
employee. The awarded notional units are adjusted cumulatively
thereafter for distribution payments through the use of an adjustment
ratio. The estimated fair value associated with RTUs and PTUs is
expensed in the statement of income over the vesting period.
We
recognized credits of $0.5 million and $1.4 million and a charge of $2.1 million
of compensation expense for the years ended December 31, 2009, December 31, 2008
and December 31, 2007, respectively. Our share of the aggregate
liability or the remaining unvested value under the BreitBurn Management LTIP
was less than $0.1 million at December 31, 2009.
Due
to the suspension of our distribution in April 2009, the multiplier as
calculated at the end of 2009 was below that required to generate a
payout. As a result, all outstanding PTUs vested and expired January
1, 2010 and no payout was made.
- 37
-
The
following table summarizes information about the restricted/performance units
granted in 2007. Market prices of $10.59, $7.05 and $28.90 were used
in the model for the periods ending December 31, 2009 December 31, 2008 and
December 31, 2007, respectively.
PTUs and RTUs
|
||||||||||||||||||||||||
December 31,
|
||||||||||||||||||||||||
2009
|
2008
|
2007
|
||||||||||||||||||||||
Weighted
|
Weighted
|
Weighted
|
||||||||||||||||||||||
Number of
|
Average
|
Number of
|
Average
|
Number of
|
Average
|
|||||||||||||||||||
Units
|
Grant Price
|
Units
|
Grant Price
|
Units
|
Grant Price
|
|||||||||||||||||||
Outstanding
, beginning of period
|
86,992 | $ | 24.10 | 108,717 | $ | 23.64 | 20,483 | $ | 21.67 | |||||||||||||||
Granted
|
- | - | - | - | 91,834 | 24.10 | ||||||||||||||||||
Exercised
|
(6,357 | ) | 24.10 | (20,645 | ) | 20.39 | (98 | ) | 24.10 | |||||||||||||||
Cancelled
|
(75,034 | ) | 24.10 | (1,080 | ) | 24.10 | (3,502 | ) | 24.10 | |||||||||||||||
Outstanding,
end of period
|
5,601 | $ | 24.10 | 86,992 | $ | 24.10 | 108,717 | $ | 23.64 | |||||||||||||||
Exercisable,
end of period
|
- | $ | - | - | $ | - | - | $ | - |
Unit
Appreciation Right Plan Awards
In 2004,
the predecessor adopted the Unit Appreciation Right Plan for Employees and
Consultants (the ‘‘UAR Plan’’). Under the UAR Plan, certain employees
of the predecessor were granted unit appreciation rights
(‘‘UARs’’). The UARs entitle the employee to receive cash
compensation in relation to the value of a specified number of underlying
notional trust units of Provident (‘‘Phantom Units’’). The exercise
price and the vesting terms of the UARs were determined at the sole discretion
of the Plan Administrator at the time of the grant. The UAR Plan was
replaced with the BreitBurn Management LTIP at the end of September
2005. The grants issued prior to the replacement of the UAR Plan
fully vested in 2008.
UARs vest
one third at the end of year one, one third at the end of year two and one third
at the end of year three after grant. Upon vesting, the employee is
entitled to receive a cash payment equal to the excess of the market price of
Provident’s units (PVE units) over the exercise price of the Phantom Units at
the grant date, adjusted for an additional amount equal to any Excess
Distributions, as defined in the plan. The predecessor settles rights
earned under the plan in cash. All of the outstanding UAR units at
December 31, 2008 expired during 2009.
The total
compensation expense for the UAR plan is allocated between us and our
predecessor. Our share of expense was an immaterial amount in 2009
and 2008. We recorded $0.4 million in expense for 2007 under the UAR
Plan.
Director
Restricted Phantom Units
Effective
with the initial public offering, we also made grants of Restricted Phantom
Units in the Partnership to the non-employee directors of our General
Partner. Each phantom unit is accompanied by a distribution
equivalent unit right entitling the holder to an additional number of phantom
units with a value equal to the amount of distributions paid on each of our
Common Units until settlement. Upon vesting, the majority of the
phantom units will be paid in Common Units, except for certain directors’ awards
which will be settled in cash. The unit-settled awards are classified
as equity and the cash-settled awards are classified as
liabilities. The estimated fair value associated with these phantom
units is expensed in the statement of income over the vesting
period. The accumulated compensation expense for unit-settled awards
is reported in equity, and for cash-settled grants, it is reflected as a
liability on the consolidated balance sheet.
We
recorded compensation expense for the director’s phantom units of approximately
$0.4 million in 2009, $0.1 million in 2008 and $0.5 million in
2007. As of December 31, 2009, there was $0.5 million of total
unrecognized compensation cost for the unvested Director Performance Units and
such cost is expected to be recognized over the next two years. The
total fair value of units vested in 2009 was $0.2 million.
- 38
-
The
following table summarizes information about the Director Restricted Phantom
Units:
December 31,
|
||||||||||||||||||||||||
2009
|
2008
|
2007
|
||||||||||||||||||||||
Number of
|
Weighted
|
Number of
|
Weighted
|
Number of
|
Weighted
|
|||||||||||||||||||
Performance
|
Average
|
Performance
|
Average
|
Performance
|
Average
|
|||||||||||||||||||
Units
|
Fair Value *
|
Units
|
Fair Value *
|
Units
|
Fair Value *
|
|||||||||||||||||||
Outstanding
, beginning of period
|
35,429 | $ | 22.60 | 37,473 | $ | 21.11 | 20,026 | $ | 18.50 | |||||||||||||||
Granted
|
56,736 | 9.20 | 20,146 | 25.02 | 17,447 | 24.10 | ||||||||||||||||||
Exercised
|
(10,810 | ) | 18.50 | (22,190 | ) | 22.28 | - | - | ||||||||||||||||
Outstanding,
end of period
|
81,355 | $ | 13.80 | 35,429 | $ | 22.60 | 37,473 | $ | 21.11 | |||||||||||||||
Exercisable,
end of period
|
- | $ | - | - | $ | - | - | $ | - |
* At
grant date
18. Commitments
and Contingencies
Lease
Rental Obligations
We had
operating leases for office space and other property and equipment having
initial or remaining non-cancelable lease terms in excess of one
year. Our future minimum rental payments for operating leases at
December 31, 2009 are presented below:
Payments Due by Year
|
||||||||||||||||||||||||||||
Thousands of dollars
|
2010
|
2011
|
2012
|
2013
|
2014
|
after 2014
|
Total
|
|||||||||||||||||||||
Operating
leases
|
$ | 2,838 | $ | 2,636 | $ | 2,174 | $ | 814 | $ | 465 | $ | 543 | $ | 9,470 |
Net
rental payments made under non-cancelable operating leases were $2.6 million,
$2.8 million and $0.4 million in 2009, 2008 and 2007,
respectively. As of December 31, 2009, we had no purchase obligations
for the next five years.
Surety
Bonds and Letters of Credit
In the
normal course of business, we have performance obligations that are secured, in
whole or in part, by surety bonds or letters of credit. These
obligations primarily cover self-insurance and other programs where governmental
organizations require such support. These surety bonds and letters of
credit are issued by financial institutions and are required to be reimbursed by
us if drawn upon. At December 31, 2009, we had $10.6 million in
surety bonds and $0.3 million in letters of credit outstanding. At
December 31, 2008, we had $10.1 million in surety bonds and $0.3 million in
letters of credit outstanding.
Legal
Proceedings
Although
we may, from time to time, be involved in litigation and claims arising out of
our operations in the normal course of business, we are not currently a party to
any material legal proceedings other than the Quicksilver lawsuit, which was
settled in February 2010 (see Note 21). In addition, we are not aware of
any material legal or governmental proceedings against us, or contemplated to be
brought against us, under the various environmental protection statues to which
we are subject.
We have
no independent assets or operations other than those of our
subsidiaries. BOLP or BOGP may guarantee debt securities that may be
issued by us and BreitBurn Finance Corporation, our wholly owned
subsidiary. See Note 1 for a description of BreitBurn Finance
Corporation. The guarantees will be full and unconditional and joint
and several.
- 39
-
19. Retirement
Plan
BreitBurn
Management operates our assets and performs other administrative services for us
such as accounting, corporate development, finance, land administration, legal
and engineering. All of our employees, including our executives, are
employees of BreitBurn Management. BreitBurn Management has a defined
contribution retirement plan, which, through November 30, 2007, covered
substantially all of its employees who had completed at least three months of
service and, starting December 1, 2007, covers substantially all of its
employees on the first day of the month following the month of
hire. The plan provides for BreitBurn Management to make regular
contributions based on employee contributions as provided for in the plan
agreement. Employees fully vest in BreitBurn Management’s
contributions after five years of service. BEC is charged for a
portion of the matching contributions made by BreitBurn
Management. For the year ended December 31, 2009, the matching
contribution paid by us was $1.0 million. For the year ended December
31, 2008 and December 31, 2007, the matching contributions paid by us were $0.4
million and $0.1 million, respectively.
20. Significant
Customers
We sell
oil, natural gas and natural gas liquids primarily to large domestic
refiners. For the year ended December 31, 2009, purchasers that
accounted for ten percent or more of our net sales were ConocoPhillips which
accounted for 30 percent of net sales, Marathon Oil Company which accounted for
16 percent of net sales, and Plains Marketing & Transportation LLC which
accounted for 11 percent of net sales. For the years ended December
31, 2008 and 2007, ConocoPhillips purchased approximately 25 percent and 20
percent of our production, respectively, and Marathon Oil Company purchased
approximately 13 percent and 24 percent of our production,
respectively. Plains Marketing & Transportation LLC accounted for
less than ten percent of our total production for the years ended December 31,
2008 and 2007, respectively.
21. Subsequent
Events
In
January 2010, 496,194 Common Units were issued to employees under our 2006
Long-Term Incentive Plan and 13,617 Common Units were issued to outside
directors for phantom units and distribution equivalent rights which were
granted in 2007 and vested in January 2010.
On
February 19, 2010, we entered into a crude oil fixed price swap contract for 500
Bbl/d for 2013 at a price of $84.55. On March 3, 2010, we entered
into a crude oil fixed price swap contract for 400 Bbl/d for 2011 through 2013
at $84.30 per Bbl. On March 10, 2010, we entered into a crude oil
fixed price swap contract for 600 Bbl/d for 2011 through 2013 at $86.35 per
Bbl.
In
February 2010, we and Quicksilver agreed to settle all claims with respect to
the litigation filed by Quicksilver. The terms of the Settlement which we
expect to be implemented in April 2010 include a monetary settlement to
Quicksilver, which we expect will be paid by insurance. See Note 8 for a
discussion of the monetary settlement. In addition, Mr. Halbert S.
Washburn and Mr. Randall H. Breitenbach will resign from the Board of Directors
and the Board will appoint two new directors designated by Quicksilver, one of
whom will qualify as an independent director and the other will be a current
independent board member now serving on Quicksilver’s board of directors,
provided that such director not be a member of Quicksilver’s
management.
- 40
-
Condensed
Consolidating Financial Information
BreitBurn
Energy Partners L.P. (the “Partnership,” “we,” “us” or “our”), BreitBurn Finance
Corporation, a Delaware corporation (together with the Partnership, the
“Issuers”), and certain of our 100% owned subsidiaries, as guarantors (the
“Guarantors”), entered into a Purchase Agreement (the “Purchase Agreement”) with
the Initial Purchasers as defined therein, pursuant to which the Issuers agreed
to sell $305 million in aggregate principal amount of the Issuers’ 8.625%
Senior Notes due 2020 (the “Notes”). The Notes were offered and sold
in private placements to qualified institutional buyers in the United States in
reliance on Rule 144A under the Securities Act of 1933, as amended.
In
connection with the issuance of the Notes, we entered into a registration rights
agreement requiring us to file an exchange offer registration statement with the
Securities and Exchange Commission (the “SEC”) with respect to an offer to
exchange the Notes for substantially identical notes that are registered under
the Securities Act of 1933. Certain, but not all, of our
subsidiaries have issued full, unconditional and joint and several guarantees of
the Notes, will guarantee the exchange offer notes and may guarantee future
issuances of debt securities, in accordance with Rule 3-10(d) of Regulation
S-X.
We are,
therefore, presenting condensed consolidating financial information as of
December 31, 2009 and 2008, and for the three years ended December 31,
2009 on a parent/co-issuer, guarantor subsidiaries, non-guarantor subsidiary,
eliminating entries, and consolidated basis. Eliminating entries presented are
necessary to combine the parent/co-issuer, the guarantor subsidiaries and the
non-guarantor subsidiary. For purposes of the following tables, we and BreitBurn
Finance Corporation are referred to as “Parent/Co-Issuer” and the “Guarantor
Subsidiaries” are all our subsidiaries other than BreitBurn Energy Partners I,
L.P. We hold a 99 percent limited partner interest in BreitBurn Energy Partners
I, L.P. (the “Non-Guarantor Subsidiary”).
BreitBurn
Finance Corporation, our wholly-owned subsidiary, was organized for the sole
purpose of being a co-issuer of certain of our indebtedness, including the
Notes. BreitBurn Finance Corporation has no operations and no revenue other than
as may be incidental to its activities as co-issuer of our
indebtedness.
Condensed
Consolidating Statements of Operations
Year Ended December 31, 2009
|
||||||||||||||||||||
Thousands of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
Revenues
and other income items:
|
||||||||||||||||||||
Oil,
natural gas and natural gas liquid sales
|
$ | - | $ | 236,266 | $ | 18,651 | $ | - | $ | 254,917 | ||||||||||
Losses
on commodity derivative instruments, net
|
- | (51,437 | ) | - | - | (51,437 | ) | |||||||||||||
Other
revenue, net
|
- | 1,382 | - | - | 1,382 | |||||||||||||||
Total
revenues and other income items
|
- | 186,211 | 18,651 | - | 204,862 | |||||||||||||||
Operating
costs and expenses:
|
||||||||||||||||||||
Operating
costs
|
11 | 129,542 | 8,945 | - | 138,498 | |||||||||||||||
Depletion,
depreciation and amortization
|
387 | 104,274 | 2,182 | - | 106,843 | |||||||||||||||
General
and administrative expenses
|
482 | 35,890 | (5 | ) | - | 36,367 | ||||||||||||||
Loss
on sale of assets
|
- | 5,965 | - | - | 5,965 | |||||||||||||||
Total
operating costs and expenses
|
880 | 275,671 | 11,122 | - | 287,673 | |||||||||||||||
Operating
income (loss)
|
(880 | ) | (89,460 | ) | 7,529 | - | (82,811 | ) | ||||||||||||
Interest
and other financing costs, net
|
- | 18,827 | - | - | 18,827 | |||||||||||||||
Loss
on interest rate swaps
|
- | 7,246 | - | - | 7,246 | |||||||||||||||
Other
income, net
|
- | (98 | ) | (1 | ) | - | (99 | ) | ||||||||||||
Income
(loss) before taxes
|
(880 | ) | (115,435 | ) | 7,530 | - | (108,785 | ) | ||||||||||||
Income
tax expense (benefit)
|
61 | (1,590 | ) | 1 | - | (1,528 | ) | |||||||||||||
Equity
in earnings (losses) of subsidiaries
|
(106,391 | ) | 7,454 | - | 98,937 | - | ||||||||||||||
Net
income (losses)
|
(107,332 | ) | (106,391 | ) | 7,529 | 98,937 | (107,257 | ) | ||||||||||||
Less:
Net income attributable to noncontrolling interest
|
- | - | - | (33 | ) | (33 | ) | |||||||||||||
Net
income (losses) attributable to the partnership
|
(107,332 | ) | (106,391 | ) | 7,529 | 98,904 | (107,290 | ) |
- 41
-
Condensed
Consolidating Statements of Operations
Year Ended December 31, 2008
|
||||||||||||||||||||
Thousands of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
Revenues
and other income items:
|
||||||||||||||||||||
Oil,
natural gas and natural gas liquid sales
|
$ | - | $ | 437,883 | $ | 29,498 | $ | - | $ | 467,381 | ||||||||||
Gains
on commodity derivative instruments, net
|
- | 332,102 | - | - | 332,102 | |||||||||||||||
Other
revenue, net
|
- | 3,439 | (519 | ) | - | 2,920 | ||||||||||||||
Total
revenues and other income items
|
- | 773,424 | 28,979 | - | 802,403 | |||||||||||||||
Operating
costs and expenses:
|
||||||||||||||||||||
Operating
costs
|
- | 152,673 | 9,332 | - | 162,005 | |||||||||||||||
Depletion,
depreciation and amortization
|
211 | 177,641 | 2,081 | - | 179,933 | |||||||||||||||
General
and administrative expenses
|
767 | 30,362 | (18 | ) | - | 31,111 | ||||||||||||||
Total
operating costs and expenses
|
978 | 360,676 | 11,395 | - | 373,049 | |||||||||||||||
Operating
income (loss)
|
(978 | ) | 412,748 | 17,584 | - | 429,354 | ||||||||||||||
Interest
and other financing costs, net
|
- | 29,147 | - | - | 29,147 | |||||||||||||||
Loss
on interest rate swaps
|
- | 20,035 | - | - | 20,035 | |||||||||||||||
Other
income, net
|
- | (100 | ) | (91 | ) | - | (191 | ) | ||||||||||||
Income
(loss) before taxes
|
(978 | ) | 363,666 | 17,675 | - | 380,363 | ||||||||||||||
Income
tax expense
|
1 | 1,936 | 2 | - | 1,939 | |||||||||||||||
Equity
in earnings of subsidiaries
|
379,226 | 17,496 | - | (396,722 | ) | - | ||||||||||||||
Net
income
|
378,247 | 379,226 | 17,673 | (396,722 | ) | 378,424 | ||||||||||||||
Less:
Net income attributable to noncontrolling interest
|
- | - | - | (188 | ) | (188 | ) | |||||||||||||
Net
income attributable to the partnership
|
378,247 | 379,226 | 17,673 | (396,910 | ) | 378,236 | ||||||||||||||
General
Partner's interest in net loss
|
(2,019 | ) | - | - | - | (2,019 | ) | |||||||||||||
Net
income attributable to limited partners
|
$ | 380,266 | $ | 379,226 | $ | 17,673 | $ | (396,910 | ) | $ | 380,255 |
- 42
-
Condensed
Consolidating Statements of Operations
Year Ended December 31, 2007
|
||||||||||||||||||||
Thousands of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor
Subsidiaries
|
Non-Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
Revenues
and other income items:
|
||||||||||||||||||||
Oil,
natural gas and natural gas liquid sales
|
$ | - | $ | 170,086 | $ | 14,286 | $ | - | $ | 184,372 | ||||||||||
Losses
on commodity derivative instruments, net
|
- | (99,952 | ) | (10,466 | ) | - | (110,418 | ) | ||||||||||||
Other
revenue, net
|
- | 1,375 | (338 | ) | - | 1,037 | ||||||||||||||
Total
revenues and other income items
|
- | 71,509 | 3,482 | - | 74,991 | |||||||||||||||
Operating
costs and expenses:
|
||||||||||||||||||||
Operating
costs
|
- | 69,242 | 4,747 | - | 73,989 | |||||||||||||||
Depletion,
depreciation and amortization
|
- | 27,484 | 1,938 | - | 29,422 | |||||||||||||||
General
and administrative expenses
|
3 | 26,892 | 33 | - | 26,928 | |||||||||||||||
Total
operating costs and expenses
|
3 | 123,618 | 6,718 | - | 130,339 | |||||||||||||||
Operating
loss
|
(3 | ) | (52,109 | ) | (3,236 | ) | - | (55,348 | ) | |||||||||||
Interest
and other financing costs, net
|
- | 6,255 | 3 | - | 6,258 | |||||||||||||||
Other
(income) expense, net
|
24 | (55 | ) | (80 | ) | - | (111 | ) | ||||||||||||
Loss
before taxes
|
(27 | ) | (58,309 | ) | (3,159 | ) | - | (61,495 | ) | |||||||||||
Income
tax expense
|
- | (1,229 | ) | - | - | (1,229 | ) | |||||||||||||
Equity
in losses of subsidiaries
|
(60,207 | ) | (3,127 | ) | - | 63,334 | - | |||||||||||||
Net
loss
|
(60,234 | ) | (60,207 | ) | (3,159 | ) | 63,334 | (60,266 | ) | |||||||||||
Less:
Net income attributable to noncontrolling interest
|
- | - | - | (91 | ) | (91 | ) | |||||||||||||
Net
loss attributable to the partnership
|
(60,234 | ) | (60,207 | ) | (3,159 | ) | 63,243 | (60,357 | ) | |||||||||||
General
Partner's interest in net loss
|
(672 | ) | - | - | - | (672 | ) | |||||||||||||
Net
loss attributable to limited partners
|
$ | (59,562 | ) | $ | (60,207 | ) | $ | (3,159 | ) | $ | 63,243 | $ | (59,685 | ) |
- 43
-
Condensed
Consolidating Balance Sheets
As of December 31, 2009
|
||||||||||||||||||||
Thousands of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor
Subsidiaries
|
Non-
Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
ASSETS
|
||||||||||||||||||||
Current
assets:
|
||||||||||||||||||||
Cash
|
$ | 149 | $ | 4,917 | $ | 700 | $ | - | $ | 5,766 | ||||||||||
Accounts
and other receivables, net
|
13,000 | 50,196 | 2,013 | - | 65,209 | |||||||||||||||
Derivative
instruments
|
- | 57,133 | - | - | 57,133 | |||||||||||||||
Related
party receivables
|
- | 2,127 | - | - | 2,127 | |||||||||||||||
Inventory
|
- | 5,823 | - | - | 5,823 | |||||||||||||||
Prepaid
expenses
|
- | 5,888 | - | - | 5,888 | |||||||||||||||
Intangibles
|
- | 495 | - | - | 495 | |||||||||||||||
Total
current assets
|
13,149 | 126,579 | 2,713 | - | 142,441 | |||||||||||||||
Investments
in subsidiaries
|
1,201,492 | 47,074 | - | (1,248,566 | ) | - | ||||||||||||||
Intercompany
receivables (payables)
|
18,743 | (32,209 | ) | 13,466 | - | - | ||||||||||||||
Equity
investments
|
- | 8,150 | - | - | 8,150 | |||||||||||||||
Property,
plant and equipment
|
||||||||||||||||||||
Oil
and gas properties
|
8,467 | 2,005,619 | 44,882 | - | 2,058,968 | |||||||||||||||
Non-oil
and gas assets
|
- | 7,717 | - | - | 7,717 | |||||||||||||||
8,467 | 2,013,336 | 44,882 | - | 2,066,685 | ||||||||||||||||
Accumulated
depletion and depreciation
|
(597 | ) | (315,567 | ) | (9,432 | ) | - | (325,596 | ) | |||||||||||
Net
property, plant and equipment
|
7,870 | 1,697,769 | 35,450 | - | 1,741,089 | |||||||||||||||
Other
long-term assets
|
||||||||||||||||||||
Derivative
instruments
|
- | 74,759 | - | - | 74,759 | |||||||||||||||
Other
long-term assets
|
74 | 4,459 | 57 | - | 4,590 | |||||||||||||||
Total
assets
|
$ | 1,241,328 | $ | 1,926,581 | $ | 51,686 | $ | (1,248,566 | ) | $ | 1,971,029 | |||||||||
LIABILITIES
AND PARTNERS' EQUITY
|
||||||||||||||||||||
Current
liabilities:
|
||||||||||||||||||||
Accounts
payable
|
$ | 2 | $ | 20,386 | $ | 926 | $ | - | $ | 21,314 | ||||||||||
Derivative
instruments
|
- | 20,057 | - | - | 20,057 | |||||||||||||||
Related
party payables
|
13,000 | - | - | - | 13,000 | |||||||||||||||
Revenue
and royalties payable
|
- | 16,888 | 1,336 | - | 18,224 | |||||||||||||||
Salaries
and wages payable
|
- | 10,244 | - | - | 10,244 | |||||||||||||||
Accrued
liabilities
|
- | 8,531 | 520 | - | 9,051 | |||||||||||||||
Total
current liabilities
|
13,002 | 76,106 | 2,782 | - | 91,890 | |||||||||||||||
Long-term
debt
|
- | 559,000 | - | - | 559,000 | |||||||||||||||
Deferred
income taxes
|
- | 2,492 | - | - | 2,492 | |||||||||||||||
Asset
retirement obligation
|
- | 35,280 | 1,355 | - | 36,635 | |||||||||||||||
Derivative
instruments
|
- | 50,109 | - | - | 50,109 | |||||||||||||||
Other
long-term liabilities
|
- | 2,102 | - | - | 2,102 | |||||||||||||||
Total liabilities
|
13,002 | 725,089 | 4,137 | - | 742,228 | |||||||||||||||
Equity:
|
||||||||||||||||||||
Partners'
equity
|
1,228,326 | 1,201,492 | 47,549 | (1,248,994 | ) | 1,228,373 | ||||||||||||||
Noncontrolling
interest
|
- | - | - | 428 | 428 | |||||||||||||||
Total
equity
|
1,228,326 | 1,201,492 | 47,549 | (1,248,566 | ) | 1,228,801 | ||||||||||||||
Total
liabilities and equity
|
$ | 1,241,328 | $ | 1,926,581 | $ | 51,686 | $ | (1,248,566 | ) | $ | 1,971,029 |
- 44
-
Condensed
Consolidating Balance Sheets
As
of December 31, 2008
|
||||||||||||||||||||
Thousands
of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor Subsidiaries
|
Non-Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
ASSETS
|
||||||||||||||||||||
Current
assets:
|
||||||||||||||||||||
Cash
|
$ | 2 | $ | 731 | $ | 1,813 | $ | - | $ | 2,546 | ||||||||||
Accounts
receivable
|
- | 46,606 | 615 | - | 47,221 | |||||||||||||||
Derivative
instruments
|
- | 76,224 | - | - | 76,224 | |||||||||||||||
Related
party receivables
|
- | 5,084 | - | - | 5,084 | |||||||||||||||
Inventory
|
- | 1,250 | - | - | 1,250 | |||||||||||||||
Prepaid
expenses
|
- | 5,220 | 80 | - | 5,300 | |||||||||||||||
Intangibles
|
- | 2,771 | - | - | 2,771 | |||||||||||||||
Other
current assets
|
- | 95 | 75 | - | 170 | |||||||||||||||
Total
current assets
|
2 | 137,981 | 2,583 | - | 140,566 | |||||||||||||||
Investments
in subsidiaries
|
1,347,910 | 40,014 | - | (1,387,924 | ) | - | ||||||||||||||
Intercompany
receivables (payables)
|
(3,215 | ) | (1,379 | ) | 4,594 | - | - | |||||||||||||
Equity
investments
|
- | 9,452 | - | - | 9,452 | |||||||||||||||
Property,
plant and equipment
|
||||||||||||||||||||
Oil
and gas properties
|
8,467 | 2,004,825 | 44,239 | - | 2,057,531 | |||||||||||||||
Non-oil
and gas assets
|
- | 7,806 | - | - | 7,806 | |||||||||||||||
|
8,467 | 2,012,631 | 44,239 | - | 2,065,337 | |||||||||||||||
Accumulated
depletion and depreciation
|
(211 | ) | (217,420 | ) | (7,365 | ) | - | (224,996 | ) | |||||||||||
Net
property, plant and equipment
|
8,256 | 1,795,211 | 36,874 | - | 1,840,341 | |||||||||||||||
Other
long-term assets
|
||||||||||||||||||||
Intangibles
|
- | 495 | - | - | 495 | |||||||||||||||
Derivative
instruments
|
- | 219,003 | - | - | 219,003 | |||||||||||||||
Other
long-term assets
|
75 | 6,902 | - | - | 6,977 | |||||||||||||||
|
||||||||||||||||||||
Total
assets
|
$ | 1,353,028 | $ | 2,207,679 | $ | 44,051 | $ | (1,387,924 | ) | $ | 2,216,834 | |||||||||
LIABILITIES
AND PARTNERS' EQUITY
|
||||||||||||||||||||
Current
liabilities:
|
||||||||||||||||||||
Accounts
payable
|
$ | - | $ | 27,462 | $ | 840 | $ | - | $ | 28,302 | ||||||||||
Book
overdraft
|
- | 9,871 | - | - | 9,871 | |||||||||||||||
Derivative
instruments
|
- | 10,192 | - | - | 10,192 | |||||||||||||||
Revenue
and royalties payable
|
- | 19,916 | 168 | - | 20,084 | |||||||||||||||
Salaries
and wages payable
|
- | 6,249 | - | - | 6,249 | |||||||||||||||
Accrued
liabilities
|
1 | 3,840 | 1,451 | - | 5,292 | |||||||||||||||
Total
current liabilities
|
1 | 77,530 | 2,459 | - | 79,990 | |||||||||||||||
|
||||||||||||||||||||
Long-term
debt
|
- | 736,000 | - | - | 736,000 | |||||||||||||||
Deferred
income taxes
|
- | 4,282 | - | - | 4,282 | |||||||||||||||
Asset
retirement obligation
|
- | 28,912 | 1,174 | - | 30,086 | |||||||||||||||
Derivative
instruments
|
- | 10,058 | - | - | 10,058 | |||||||||||||||
Other
long-term liabilities
|
- | 2,987 | - | - | 2,987 | |||||||||||||||
Total liabilities
|
1 | 859,769 | 3,633 | - | 863,403 | |||||||||||||||
Equity:
|
||||||||||||||||||||
Partners'
equity
|
1,353,027 | 1,347,910 | 40,418 | (1,388,463 | ) | 1,352,892 | ||||||||||||||
Noncontrolling
interest
|
- | - | - | 539 | 539 | |||||||||||||||
Total
equity
|
1,353,027 | 1,347,910 | 40,418 | (1,387,924 | ) | 1,353,431 | ||||||||||||||
Total
liabilities and partners' equity
|
$ | 1,353,028 | $ | 2,207,679 | $ | 44,051 | $ | (1,387,924 | ) | $ | 2,216,834 |
- 45
-
Condensed
Consolidating Statements of Cash Flows
Year Ended December 31, 2009
|
||||||||||||||||||||
Thousands of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor
Subsidiaries
|
Non-
Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
Cash
flows from operating activities
|
||||||||||||||||||||
Net
income (loss)
|
$ | (107,332 | ) | $ | (106,391 | ) | $ | 7,529 | $ | 98,937 | $ | (107,257 | ) | |||||||
Adjustments
to reconcile net income (loss) to cash flow from operating
activities:
|
||||||||||||||||||||
Depletion,
depreciation and amortization
|
387 | 104,274 | 2,182 | - | 106,843 | |||||||||||||||
Unit-based
compensation expense
|
- | 12,661 | - | - | 12,661 | |||||||||||||||
Unrealized
losses on derivative instruments
|
- | 213,251 | - | - | 213,251 | |||||||||||||||
Income
from equity affiliates, net
|
- | 1,302 | - | - | 1,302 | |||||||||||||||
Equity
in (earnings) losses of subsidiaries
|
106,391 | (7,454 | ) | - | (98,937 | ) | - | |||||||||||||
Deferred
income tax
|
- | (1,790 | ) | - | - | (1,790 | ) | |||||||||||||
Amortization
of intangibles
|
- | 2,771 | - | - | 2,771 | |||||||||||||||
Loss
on sale of assets
|
- | 5,965 | - | - | 5,965 | |||||||||||||||
Other
|
- | 3,294 | - | - | 3,294 | |||||||||||||||
Changes
in net assets and liabilities:
|
- | |||||||||||||||||||
Accounts
receivable and other assets
|
- | (5,013 | ) | (1,300 | ) | - | (6,313 | ) | ||||||||||||
Inventory
|
- | (4,573 | ) | - | - | (4,573 | ) | |||||||||||||
Net
change in related party receivables and payables
|
- | 2,957 | - | - | 2,957 | |||||||||||||||
Accounts
payable and other liabilities
|
- | (5,078 | ) | 325 | - | (4,753 | ) | |||||||||||||
Net
cash provided (used) by operating activities
|
(554 | ) | 216,176 | 8,736 | - | 224,358 | ||||||||||||||
Cash
flows from investing activities
|
||||||||||||||||||||
Capital
expenditures
|
- | (28,828 | ) | (685 | ) | - | (29,513 | ) | ||||||||||||
Proceeds
from sale of assets, net
|
- | 23,284 | - | - | 23,284 | |||||||||||||||
Net
cash used by investing activities
|
- | (5,544 | ) | (685 | ) | - | (6,229 | ) | ||||||||||||
Cash
flows from financing activities
|
||||||||||||||||||||
Distributions
|
(28,038 | ) | - | - | - | (28,038 | ) | |||||||||||||
Proceeds
from the issuance of long-term debt
|
- | 249,975 | - | - | 249,975 | |||||||||||||||
Repayments
of long-term debt
|
- | (426,975 | ) | - | - | (426,975 | ) | |||||||||||||
Book
overdraft
|
- | (9,871 | ) | - | - | (9,871 | ) | |||||||||||||
Intercompany
activity
|
28,739 | (19,575 | ) | (9,164 | ) | - | - | |||||||||||||
Net
cash provided (used) by financing activities
|
701 | (206,446 | ) | (9,164 | ) | - | (214,909 | ) | ||||||||||||
Increase
(decrease) in cash
|
147 | 4,186 | (1,113 | ) | - | 3,220 | ||||||||||||||
Cash
beginning of period
|
2 | 731 | 1,813 | - | 2,546 | |||||||||||||||
Cash
end of period
|
$ | 149 | $ | 4,917 | $ | 700 | $ | - | $ | 5,766 |
- 46
-
Condensed
Consolidating Statements of Cash Flows
Year Ended December 31, 2008
|
||||||||||||||||||||
Thousands of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor
Subsidiaries
|
Non-
Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
Cash
flows from operating activities
|
||||||||||||||||||||
Net
income
|
$ | 378,247 | $ | 379,226 | $ | 17,673 | $ | (396,722 | ) | $ | 378,424 | |||||||||
Adjustments
to reconcile net income to cash flow from operating
activities:
|
||||||||||||||||||||
Depletion,
depreciation and amortization
|
211 | 177,641 | 2,081 | - | 179,933 | |||||||||||||||
Unit-based
compensation expense
|
- | 6,907 | - | - | 6,907 | |||||||||||||||
Unrealized
gains on derivative instruments
|
- | (370,734 | ) | - | - | (370,734 | ) | |||||||||||||
Income
from equity affiliates, net
|
- | 1,198 | - | - | 1,198 | |||||||||||||||
Equity
in earnings of subsidiaries
|
(379,226 | ) | (17,496 | ) | - | 396,722 | - | |||||||||||||
Deferred
income tax
|
- | 1,207 | - | - | 1,207 | |||||||||||||||
Amortization
of intangibles
|
- | 3,131 | - | - | 3,131 | |||||||||||||||
Other
|
- | 2,643 | - | - | 2,643 | |||||||||||||||
Changes
in net assets and liabilities:
|
- | |||||||||||||||||||
Accounts
receivable and other assets
|
(71 | ) | (547 | ) | 876 | - | 258 | |||||||||||||
Inventory
|
- | 4,454 | - | - | 4,454 | |||||||||||||||
Net
change in related party receivables and payables
|
- | 32,688 | - | - | 32,688 | |||||||||||||||
Accounts
payable and other liabilities
|
1 | (13,663 | ) | 249 | - | (13,413 | ) | |||||||||||||
Net
cash provided (used) by operating activities
|
(838 | ) | 206,655 | 20,879 | - | 226,696 | ||||||||||||||
Cash
flows from investing activities
|
||||||||||||||||||||
Capital
expenditures
|
- | (130,002 | ) | (1,080 | ) | - | (131,082 | ) | ||||||||||||
Property
acquisitions
|
(8,467 | ) | (1,490 | ) | - | - | (9,957 | ) | ||||||||||||
Net
cash used by investing activities
|
(8,467 | ) | (131,492 | ) | (1,080 | ) | - | (141,039 | ) | |||||||||||
Cash
flows from financing activities
|
||||||||||||||||||||
Purchase
of common units
|
(336,216 | ) | - | - | - | (336,216 | ) | |||||||||||||
Distributions
|
(121,349 | ) | - | - | - | (121,349 | ) | |||||||||||||
Proceeds
from the issuance of long-term debt
|
- | 803,002 | - | - | 803,002 | |||||||||||||||
Repayments
of long-term debt
|
- | (437,402 | ) | - | - | (437,402 | ) | |||||||||||||
Book
overdraft
|
- | 7,951 | - | - | 7,951 | |||||||||||||||
Long-term
debt issuance costs
|
- | (5,026 | ) | - | - | (5,026 | ) | |||||||||||||
Intercompany
activity
|
466,870 | (443,157 | ) | (23,713 | ) | - | - | |||||||||||||
Net
cash provided (used) by financing activities
|
9,305 | (74,632 | ) | (23,713 | ) | - | (89,040 | ) | ||||||||||||
Increase
(decrease) in cash
|
- | 531 | (3,914 | ) | - | (3,383 | ) | |||||||||||||
Cash
beginning of period
|
2 | 200 | 5,727 | - | 5,929 | |||||||||||||||
Cash
end of period
|
$ | 2 | $ | 731 | $ | 1,813 | $ | - | $ | 2,546 |
- 47
-
Condensed
Consolidating Statements of Cash Flows
Year Ended December 31, 2007
|
||||||||||||||||||||
Thousands of dollars
|
Parent/
Co-Issuer
|
Combined
Guarantor
Subsidiaries
|
Non-
Guarantor
Subsidiary
|
Eliminations
|
Consolidated
|
|||||||||||||||
Cash
flows from operating activities
|
||||||||||||||||||||
Net
loss
|
$ | (60,234 | ) | $ | (60,207 | ) | $ | (3,159 | ) | $ | 63,334 | $ | (60,266 | ) | ||||||
Adjustments
to reconcile to cash flow from operating activities:
|
||||||||||||||||||||
Depletion,
depreciation and amortization
|
- | 27,484 | 1,938 | - | 29,422 | |||||||||||||||
Deferred
stock based compensation
|
- | 12,999 | - | - | 12,999 | |||||||||||||||
Unrealized
losses on derivative instruments
|
- | 103,862 | - | - | 103,862 | |||||||||||||||
Income
from equity affiliates, net
|
- | (28 | ) | - | - | (28 | ) | |||||||||||||
Equity
in losses of subsidiaries
|
60,207 | 3,127 | - | (63,334 | ) | - | ||||||||||||||
Deferred
income tax
|
- | (1,229 | ) | - | - | (1,229 | ) | |||||||||||||
Amortization
of intangibles
|
- | 2,174 | - | - | 2,174 | |||||||||||||||
Other
|
- | 2,182 | - | - | 2,182 | |||||||||||||||
Changes
in net assets and liablities:
|
||||||||||||||||||||
Accounts
receivable and other assets
|
- | (27,597 | ) | 2,884 | - | (24,713 | ) | |||||||||||||
Inventory
|
- | 4,829 | - | - | 4,829 | |||||||||||||||
Net
change in related party receivables and payables
|
- | (39,202 | ) | - | - | (39,202 | ) | |||||||||||||
Accounts
payable and other liabilities
|
1 | 31,728 | (1,657 | ) | - | 30,072 | ||||||||||||||
Net
cash provided (used) by operating activities
|
(26 | ) | 60,122 | 6 | - | 60,102 | ||||||||||||||
Cash
flows from investing activities
|
||||||||||||||||||||
Capital
expenditures
|
- | (22,835 | ) | (714 | ) | - | (23,549 | ) | ||||||||||||
Property
acquisitions
|
- | (996,561 | ) | - | - | (996,561 | ) | |||||||||||||
Net
cash used by investing activities
|
- | (1,019,396 | ) | (714 | ) | - | (1,020,110 | ) | ||||||||||||
Cash
flows from financing activities
|
||||||||||||||||||||
Issuance
of common units, net of discount
|
663,338 | - | - | - | 663,338 | |||||||||||||||
Repayments
of initial distributions by predecessor members
|
581 | - | - | - | 581 | |||||||||||||||
Distributions
|
(60,497 | ) | - | - | - | (60,497 | ) | |||||||||||||
Proceeds
from the issuance of long-term debt
|
- | 574,700 | - | - | 574,700 | |||||||||||||||
Repayments
of long-term debt
|
- | (205,800 | ) | - | - | (205,800 | ) | |||||||||||||
Book
overdraft
|
- | (116 | ) | - | - | (116 | ) | |||||||||||||
Long-term
debt issuance costs
|
- | (6,362 | ) | - | - | (6,362 | ) | |||||||||||||
Intercompany
activity
|
(603,397 | ) | 596,516 | 6,881 | - | - | ||||||||||||||
Net
cash provided by financing activities
|
25 | 958,938 | 6,881 | - | 965,844 | |||||||||||||||
Increase
(decrease) in cash
|
(1 | ) | (336 | ) | 6,173 | - | 5,836 | |||||||||||||
Cash
beginning of period
|
3 | 536 | (446 | ) | - | 93 | ||||||||||||||
Cash
end of period
|
$ | 2 | $ | 200 | $ | 5,727 | $ | - | $ | 5,929 |
- 48
-