Notes
to Consolidated Financial Statements
1.
Basis of Presentation
The
accompanying unaudited consolidated financial statements have been prepared
in
accordance with generally accepted accounting principles for interim financial
information and with the instructions to Form 10-Q and Article 10 of Regulation
S-X. Accordingly, they do not include all of the information and footnotes
required by generally accepted accounting principles for complete financial
statements. In the opinion of management, all adjustments (consisting of normal
recurring accruals) considered necessary for a fair presentation have been
included. Operating results for the six months period ended June 30, 2007 are
not necessarily indicative of the results that may be expected for the year
ended December 31, 2007. The consolidated balance sheet at December 31, 2006
has
been derived from the audited consolidated financial statements at that date
but
does not include all of the information and footnotes required by generally
accepted accounting principles for complete financial statements. The
Partnership follows the successful efforts method of accounting for oil and
gas
activities. Depreciation, depletion and amortization (“DD&A”) of proved oil
and gas properties is computed using the units-of-production method net of
any
estimated residual salvage values. For further information, refer to the
consolidated financial statements and footnotes thereto included in our Annual
Report on Form 10-K for the year ended December 31, 2006.
2.
Organization and description of operations
The
Partnership is a Delaware limited partnership formed on March 23, 2006 to
acquire certain oil and gas properties of BreitBurn Energy, the Predecessor.
BreitBurn GP serves as the general partner of the Partnership. The Partnership
conducts its operations through its wholly-owned subsidiaries BreitBurn
Operating L.P. (“OLP”) and OLP’s general partner BreitBurn Operating GP, LLC
(“OGP”).
On
October 10, 2006, the Partnership completed an initial public offering of
6,000,000 common units representing limited partner interests of the Partnership
(“Common Units”) at $18.50 per unit, or $17.205 per unit after payment of the
underwriting discount. Total proceeds from the sale of the Common Units in
the
initial public offering were $111 million, before underwriting discounts and
offering costs, of approximately $7.8 million and $4.1 million, respectively.
The Partnership used the net proceeds of $99.1 million to make distributions
of
$63.2 million to Provident Energy Trust (“Provident”) and BreitBurn Energy
Corporation (“BreitBurn Corporation”) and to repay $36.5 million in assumed
indebtedness. The historical relationship between the Predecessor, Provident
and
BreitBurn Corporation are further discussed under the caption “BreitBurn Energy
Company L.P.” included elsewhere in this note. On November 1, 2006,
the
underwriters
exercised their option to purchase an additional 900,000 Common Units to cover
over-allotments in the initial public offering. The sale to cover
over-allotments was at the initial public offering price of $18.50 per unit,
less the underwriting discount, and closed on November 6, 2006. The Partnership
used the net proceeds of approximately $15.5 million from the exercise of the
underwriters’ over-allotment option to redeem 900,000 Common Units in the
aggregate owned by Provident’s two indirect wholly-owned subsidiaries, Pro GP
Corp. (“Pro GP”) and Pro LP Corp. (“Pro LP”), and BreitBurn Corporation.
Following redemption, those Common Units were cancelled.
Additionally,
on October 10, 2006:
|
a)
|
The
Partnership entered into a Contribution, Conveyance and Assumption
Agreement (the “Contribution Agreement”). Immediately prior to the closing
of the initial public offering, the following transactions, among
others,
occurred pursuant to the Contribution
Agreement:
|
|
·
|
BreitBurn
Energy conveyed to OLP its interests in the Partnership Properties
along
with its stock in three subsidiaries and OLP assumed $36.5 million
of
indebtedness;
|
|
·
|
BreitBurn
Energy distributed its interest in OGP and its limited partner interest
in
OLP to Pro GP, Pro LP and BreitBurn Corporation in proportion to
their
ownership interests in BreitBurn
Energy;
|
|
·
|
Pro
GP, Pro LP and BreitBurn Corporation conveyed a 0.01%, 1.90% and
0.09%,
respectively, interest in OLP to the General Partner in exchange
for a
0.40%, 95.15% and 4.45%, respectively, member interest in the General
Partner;
|
|
·
|
The
General Partner conveyed the interest in OLP to the Partnership in
exchange for a continuation of its 2% general partner interest in
the
Partnership; and
|
|
·
|
Pro
GP, Pro LP and BreitBurn Corporation conveyed their remaining interests
in
OLP and OGP to the Partnership in exchange for (a) an aggregate of
15,975,758 Common Units representing limited partner interests, equal
to a
71.24% limited partner interest in the Partnership, and (b) received
approximately $63.2 million, as a distribution of the initial public
offering proceeds, to reimburse them for certain capital expenditures
made
directly by them or through BreitBurn
Energy.
|
The
following table presents the net assets conveyed by BreitBurn Energy to the
Partnership immediately prior to the closing of the initial public offering
including the debt assumption:
|
|
|
October 10,
|
|
|
Thousands
of dollars
|
|
2006
|
|
|
Cash
and cash equivalents
|
|
$
|
16
|
|
|
Accounts
receivable—trade
|
|
|
4,225
|
|
|
Non-hedging
derivative instruments
|
|
|
4,007
|
|
|
Prepaid
expenses and other current assets
|
|
|
459
|
|
|
Non-hedging
derivative instruments - non-current
|
|
|
1,235
|
|
|
Property
and equipment, net
|
|
|
183,456
|
|
|
Other
assets
|
|
|
174
|
|
|
Total
assets
|
|
$
|
193,572
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
897
|
|
|
Accounts
payable—affiliates
|
|
|
5,237
|
|
|
Accrued
expenses and other current liabilities
|
|
|
328
|
|
|
Long-term
debt
|
|
|
36,500
|
|
|
Deferred
income taxes
|
|
|
4,343
|
|
|
Asset
retirement obligation
|
|
|
7,456
|
|
|
Total
liabilities
|
|
$
|
54,761
|
|
|
Net
assets
|
|
$
|
138,811
|
|
The
transfer of ownership of assets from the Predecessor to the Partnership was
recorded at historical costs in accordance with Emerging Issues Task Force
(“EITF”) Issue No. 87-21, “Change in Accounting Basis in Master Limited
Partnership Transactions.”
On
May 24
and 25, 2007, the Partnership sold approximately $130 million and $92 million,
respectively, of Common Units in two private placements (see note 10) (the
“Private Placements”). The Partnership issued and sold 4,062,500 and 2,967,744
Common Units at $32.00 per unit and $31.00 per unit, respectively.
As
a
result of the transactions described above, as of June 30, 2007, Provident
and
BreitBurn Corporation collectively own 15,075,758 Common Units, representing
a
51.97% limited partner interest and a 1.52% general partner interest in the
Partnership. As of such date, the public holders own 48.03% of the Common Units.
BreitBurn
Energy Company L.P. (Predecessor)
BreitBurn
Energy, was formed on June 15, 2004 when Provident acquired BreitBurn Energy’s
former predecessor, BreitBurn Energy Company LLC, which was then converted
into
BreitBurn Energy Company L.P., a Delaware limited partnership. At June 30,
2007,
percentage interests in BreitBurn Energy are held as follows: Pro GP Corp.,
the
general partner, 0.4 percent; Pro LP Corp., a limited partner, 95.38 percent;
and BreitBurn Energy Corporation, a limited partner, 4.22 percent.
3.
Accounting Standards Not Yet Adopted
SFAS
No. 159 “The Fair Value Option for Financial Assets and Financial
Liabilities — including an amendment of FAS 115” (“SFAS No.
159”).
In
February 2007, the FASB issued SFAS No. 159 which allows entities to choose,
at
specified election dates, to measure eligible financial assets and liabilities
at fair value in situations in which they are not otherwise required to be
measured at fair value. If a company elects the fair value option for an
eligible item, changes in that item’s fair value in subsequent reporting periods
must be recognized in current earnings. The provisions of SFAS No. 159 will
be
effective for the Partnership beginning January 1, 2008. The Partnership is
evaluating the impact of adoption of SFAS No. 159 but does not currently expect
the adoption to have a material impact on its financial position, results of
operations or cash flows.
SFAS
No. 157, Fair Value Measurements.
In
September 2006, the FASB issued SFAS No. 157, which will become effective
for the Partnership on January 1, 2008. This standard defines fair value,
establishes a framework for measuring fair value and expands disclosures about
fair value measurements. The Statement does not require any new fair value
measurements but would apply to assets and liabilities that are required to
be
recorded at fair value under other accounting standards. The impact, if any,
to
the Partnership from the adoption of SFAS No. 157 in 2008 will depend on
the Partnership’s assets and liabilities at that time that are required to be
measured at fair value.
4.
Acquisitions
Second
Quarter 2007
On
May
24, 2007, OLP entered into an Amended and Restated Asset Purchase Agreement
with
Calumet Florida, L.L.C. (“Calumet”), to acquire certain interests in oil leases
and related assets located along the Sunniland Trend in South Florida through
the acquisition of a limited liability company that owned all of the purchased
assets (the “Calumet Acquisition” or “Calumet Properties”). The Calumet
Properties are comprised of five separate oil fields, one 23-mile pipeline
serving one field, one storage terminal and rights in a shipping terminal.
The
transaction closed on May 24, 2007. The purchase price was $100 million with
an
effective date of January 1, 2007. After adjustments for costs and revenues
for
the period between the effective date and the closing, including interest paid
to the seller, and after taking into account approximately 218,000 barrels
of
crude oil held in storage as of the closing date, the Partnership paid Calumet
approximately $107.4 million at closing. The acquisition was financed through
the Partnership’s sale of Common Units through a private placement (see note 10
for additional information on the private placement). The acquiring subsidiary
is a partnership and thus no deferred taxes were recognized for this
transaction. The Partnership has made a preliminary allocation of the purchase
price of $107.8 million, including approximately $0.4 million in acquisition
costs to the assets acquired and liabilities assumed as follows:
|
Thousands
of dollars
|
|
|
|
|
Inventories
|
|
$
|
10,533
|
|
|
Intangible
assets
|
|
|
3,377
|
|
|
Oil
and gas properties
|
|
|
97,792
|
|
|
Non
oil and gas assets
|
|
|
672
|
|
|
Asset
retirement obligation
|
|
|
(3,843
|
)
|
|
Other
current liabilities
|
|
|
(777
|
)
|
|
|
|
$
|
107,754
|
|
The
preliminary purchase price allocation is based on discounted cash flows, quoted
market prices and estimates made by management. The most significant assumptions
related to the estimated fair values assigned to proved oil and gas properties.
To estimate the fair values of these properties, estimates of oil reserves
were
prepared by management in consultation with independent engineers. We applied
estimated future prices to the estimated reserve quantities acquired, and
estimated future operating and development costs, to arrive at estimates of
future net revenues. For estimated proved reserves, the future net revenues
were
discounted using a cost of capital rate determined appropriate at the time
of
the acquisition. There were no estimated unproved reserves allocated in the
purchase price of the Calumet Acquisition. The purchase price included the
fair
value attributable to the oil inventories held in storage at the closing date.
The Partnership assumed certain crude oil sales contracts for the remainder
of
2007 and for 2008 through 2010. An intangible asset was established to value
the
crude oil contracts in the purchase price allocation. Realized gains from these
contracts will be recognized as part of oil sales and the intangible asset
will
be amortized over the life of the contracts.
The
purchase price allocation is subject to final closing adjustments and will
be
finalized within one year of the acquisition date.
On
May
25, 2007, OLP entered into a Purchase and Sale Agreement (the “Purchase and Sale
Agreement”) with TIFD X-III LLC (“TIFD”), pursuant to which it acquired TIFD’s
99% limited partner interest in BreitBurn Energy Partners I, L.P. (“BEPI”) for a
total purchase price of approximately $82 million (the “BEPI Acquisition”). BEPI
owns properties in the East Coyote and Sawtelle Fields in the Los Angeles Basin
in California. The general partner of BEPI is an affiliate of the general
partner of the Partnership in which the Partnership has no ownership interest.
As part of the transaction, BEPI distributed to an affiliate of TIFD a 1.5%
overriding royalty interest in the oil and gas produced by the partnership
from
the two fields. The 1.5% Override burden will be borne solely through the
Partnership’s interest in BEPI. In connection with the acquisition, the
Partnership also paid approximately $10.4 million to terminate existing hedge
contracts related to future production from BEPI.
The
acquisition including the termination of existing hedge contracts was financed
through the Partnership’s sale of Common Units through a private placement (see
note 10 for additional information on the private placement). The acquiring
subsidiary is a partnership and thus no deferred taxes were recognized for
this
transaction. The Partnership has made a preliminary allocation of the purchase
price of $92.4 million to the assets acquired and liabilities assumed as
follows:
|
Thousands
of dollars
|
|
|
|
|
Current
assets
|
|
$
|
2,813
|
|
|
Oil
and gas properties
|
|
|
92,916
|
|
|
Current
liabilities
|
|
|
(2,282
|
)
|
|
Asset
retirement obligation
|
|
|
(582
|
)
|
|
Other
liabilities
|
|
|
(398
|
)
|
|
|
|
$
|
92,467
|
|
The
preliminary purchase price allocation is based on discounted cash flows,
quoted
market prices and estimates made by management. The most significant assumptions
related to the estimated fair values assigned to proved oil and gas properties.
To estimate the fair values of these properties, estimates of oil reserves
were
prepared by management in consultation with independent engineers. We applied
estimated future prices to the estimated reserve quantities acquired, and
estimated future operating and development costs, to arrive at estimates
of
future net revenues. For estimated proved reserves, the future net revenues
were
discounted using a cost of capital rate determined appropriate at the time
of
the acquisition. There were no unproved properties identified with the BEPI
Acquisition. The purchase price allocation is subject to final closing
adjustments and will be finalized within one year of the acquisition
date.
In
April
2007, the Partnership also completed the purchase of interests in certain oil
and gas properties in Wyoming for approximately $0.9 million in
cash.
First
Quarter 2007
On
January 23, 2007, the Partnership completed the purchase of certain oil and
gas
properties, known as the “Lazy JL” in the Permian Basin of Texas, including
related property and equipment. The purchase price for the Lazy JL acquisition
was approximately $29.0 million in cash, and was financed through borrowings
under the Partnership’s existing revolving credit facility. The transaction was
accounted for using the purchase method in accordance with SFAS No. 141 and
was
effective January 1, 2007. The purchase price was allocated to the assets
acquired and liabilities assumed as follows:
|
Thousands
of dollars
|
|
|
|
|
Oil
and gas properties
|
|
$
|
29,309
|
|
|
Asset
retirement obligation
|
|
|
(282
|
)
|
|
Other
|
|
|
2
|
|
|
|
|
$
|
29,029
|
|
In
March
2007, the Partnership also completed the purchase of certain oil and gas
properties in California for approximately $1.0 million in
cash.
The
following unaudited pro forma financial information presents a summary of the
Partnership’s consolidated results of operations for the second quarter and six
months ended June 30, 2007 and 2006, assuming the Calumet, BEPI and Lazy JL
acquisitions had been completed as of the beginning of each period, including
adjustments to reflect the allocation of the purchase price to the acquired
net
assets. The pro forma financial information assumes that the initial public
offering that occurred in 2006 occurred January 1, 2006. As such, the 2006
results are presented on a comparable basis to the Successor and are not
presented as pro forma for the Predecessor. The pro forma financial information
also assumes the Partnership’s 2007 private placement of units (see
note 10) was completed as of the beginning of each period, since the
private placements were contingent on the two acquisitions. The revenues and
expenses of these two acquisitions are included in the consolidated results
of
the Partnership effective May 24 and May 25, 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.
|
|
|
Three
Months
|
|
Three
Months
|
|
Six
Months
|
|
Six
Months
|
|
|
|
|
Ended
June 30,
|
|
Ended
June 30,
|
|
Ended
June 30,
|
|
Ended
June 30,
|
|
|
Thousands
of dollars, except per unit amounts
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
32,763
|
|
$
|
28,797
|
|
$
|
66,616
|
|
$
|
61,696
|
|
|
Income
before cumulative effect of change in accounting principle
|
|
$
|
(2,795
|
)
|
$
|
2,475
|
|
$
|
938
|
|
$
|
10,660
|
|
|
Net
income
|
|
$
|
(2,795
|
)
|
$
|
2,475
|
|
$
|
938
|
|
$
|
11,016
|
|
|
Income
before cumulative effect of change in accounting principle per
unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.10
|
)
|
$
|
0.09
|
|
$
|
0.03
|
|
$
|
0.37
|
|
|
Diluted
|
|
$
|
(0.10
|
)
|
$
|
0.09
|
|
$
|
0.03
|
|
$
|
0.37
|
|
|
Net
income per unit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.10
|
)
|
$
|
0.09
|
|
$
|
0.03
|
|
$
|
0.38
|
|
|
Diluted
|
|
$
|
(0.10
|
)
|
$
|
0.09
|
|
$
|
0.03
|
|
$
|
0.38
|
|
5.
Income Taxes
The
Partnership and most of its subsidiaries are partnerships or limited liability
companies treated as partnerships for federal and state income tax purposes.
Essentially all of the Partnership’s 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 its members.
As
such, no federal income tax for these entities has been provided for in the
accompanying financial statements. State income taxes were immaterial. However,
the Partnership has two wholly owned subsidiaries, which are Subchapter
C-corporations, as defined in the Internal Revenue Code that are subject to
federal and state income taxes. In the second quarter of 2007
,
the
subsidiaries recorded a federal current tax expense of $0.1 million and $0.3
million tax benefit in federal deferred taxes. For the six months ended June
30,
2007, the subsidiaries recorded $0.1 million in current federal tax expense
and
$0.4 million tax benefit in federal deferred taxes. At June 30, 2007, the
Partnership’s net deferred tax liability was $3.8 million.
Effective
January 1, 2007, the Partnership implemented
FASB
Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An
Interpretation of FASB Statement No. 109
(“FIN 48”), which 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.
The
Partnership performed an evaluation as of January 1, 2007 and
concluded that there were no uncertain tax positions requiring recognition
in
its financial statements.
Th
e
adoption of this standard did not have an impact on the Partnership’s
financial
position, results of operations or cash flows.
6.
Inventory
The
Partnership, through its Calumet Acquisition (see note 4 - Acquisitions), had
oil inventories at June 30, 2007. Oil inventories are carried at the lower
of
cost to produce or market price. Inventories purchased through the acquisition
are carried in inventory based on the purchace price allocation detailed in
note
4 - Acquisitions. At May 24, 2007, we allocated $10.5 million to the inventories
purchased. After the acquisition date, the Partnership had one sale from this
purchased inventory and $5.3 million was charged to the consolidated statement
of operations as inventory cost. At June 30, 2007, the Partnership’s ending
inventory included approximately $5.1 million from the original $10.5 million.
After May 24, 2007, inventory additions were at cost and represent the
Partnership’s production costs. The Partnership matches 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. The following table
shows the detail of the inventory value reflected on the consolidated balance
sheet at June 30, 2007.
|
Thousands
of dollars
|
|
June
30, 2007
|
|
|
Acquisition
- May 24, 2007
|
|
$
|
10,533
|
|
|
Production
costs including associated DD&A
|
|
|
2,527
|
|
|
Sales
|
|
|
(5,388
|
)
|
|
|
|
|
|
|
|
Carrying
amount, end of period
|
|
$
|
7,672
|
|
7.
Related Party Transactions
The
Partnership and its subsidiaries do not have any employees. The Partnership
is
managed by its general partner, the executive officers of which are employees
of
BreitBurn Management. The Partnership’s assets are operated, and its
administrative needs are provided under its Administrative Services Agreement
with BreitBurn Management. BreitBurn Management also manages the operations
of
BreitBurn Energy, and the employees of BreitBurn Management devote a portion
of
their time to the operation of BreitBurn Energy’s business.
Under
the
Administrative Services Agreement, the Partnership reimburses BreitBurn
Management for all direct and indirect expenses it incurs in connection with
the
services it performs for the Partnership (including salary, bonus, incentive
compensation and other amounts paid to executive officers). To the extent that
the services performed by BreitBurn Management benefit both the Partnership
and
BreitBurn Energy, each of the Partnership and BreitBurn Energy are required
to
reimburse BreitBurn Management in proportion to the benefits each of them
receives. BreitBurn Management generally allocates the costs of the services
of
BreitBurn Management personnel providing services to both entities based on
BreitBurn Management’s good-faith determination of actual time spent performing
the services, plus expenses. During 2006, if services performed by BreitBurn
Management benefiting both the Partnership and BreitBurn Energy could not be
allocated on the basis of actual time spent on each entity, then such expenses
were allocated to each entity in the same proportion as the aggregate barrels
of
oil equivalents produced by each entity related to the aggregate barrels of
oil
equivalents produced by both entities combined during the same period. For
2007,
the allocation methodology has been changed to reflect the fact that the most
intense portion of the Partnership’s initial public offering startup is now
complete and a more balanced allocation of resources between the Partnership
and
BreitBurn Energy is expected. BreitBurn Management currently allocates its
expenses between us and BreitBurn Energy on the basis of which entity received
the services to which specific expenses relate or, in instances where expenses
relate to services provided for the benefit of both entities, by allocating
51%
of such expenses to the Partnership and 49% of such expenses to BreitBurn
Energy. This allocation split for 2007 was derived from a weighted average
of
three components that were forecasted for the Partnership and BreitBurn Energy:
(i) the proportionate level of 2007 forecasted
gross
barrels of oil equivalents production; (ii) the proportionate level of 2007
forecasted operating expenses; and (iii) the proportionate level of 2007
forecasted capital expenditures. BreitBurn Management will continue from time
to
time to review the methodology utilized to allocate costs, including reviewing
the impacts of acquisitions, capital programs, and other factors, and may modify
the methodology to appropriately reflect the value attributable to the
Partnership.
During
the second quarter and first six months of 2007, the Partnership incurred
approximately $6.6 million and $14.1 million, respectively, in direct and
indirect general and administrative expenses from BreitBurn Management. The
Partnership reimbursed BreitBurn Management $5.6 million and $13.4 million
under
the Administrative Services Agreement during the second quarter and six months
periods ended June 30, 2007, respectively.
At
June
30, 2007 and December 31, 2006, the Partnership had the following receivables
and payables with the Predecessor and BreitBurn Management (“affiliated
companies”).
|
|
|
June
30,
|
|
December
31,
|
|
|
Thousands
of dollars
|
|
2007
|
|
2006
|
|
|
Related
party receivables
|
|
|
|
|
|
|
Provident
|
|
$
|
-
|
|
$
|
556
|
|
|
Affiliated
companies
|
|
|
2,301
|
|
|
5,653
|
|
|
Current
related party receivables
|
|
$
|
2,301
|
|
$
|
6,209
|
|
|
Related
party payables
|
|
|
|
|
|
|
|
|
Provident
|
|
$
|
982
|
|
$
|
280
|
|
|
Affiliated
companies
|
|
|
7,014
|
|
|
5,633
|
|
|
Current
related party payables
|
|
|
7,996
|
|
|
5,913
|
|
|
Affiliated
companies
|
|
|
1,911
|
|
|
467
|
|
|
Long
term related party payables
|
|
$
|
1,911
|
|
$
|
467
|
|
At
December 31, 2006, the receivables from affiliated companies included
receivables from the Predecessor related primarily to cash collections made
by
the Predecessor from its oil purchasers for oil and gas sales made by the
Partnership. In the first six months of 2007, the Partnership collected from
the
Predecessor these outstanding receivables. At June 30, 2007, the current
payables to affiliated companies included payables to BreitBurn Management
that
represent amounts due under the Administrative Services Agreement and
outstanding liabilities for employee related costs including equity-based
compensation accruals. The long-term payables relate to BreitBurn Management
and
represent the long-term portion of equity-based compensation
accruals.
In
connection with the BEPI acquisition, the Partnership paid approximately $10.4
million to terminate existing hedge contracts related to future production
from
BEPI. The partnership had a receivable of $0.1 million outstanding at June
30,
2007 for BEPI’s general partner share of the disposed hedge
contracts.
At
June
30, 2007 and December 31, 2006, the Partnership had a net payable to Provident
of $1.0 million and $0.3 million, respectively. The Partnership owes Provident
for insurance costs that are incurred on behalf of the Partnership. During
the
six months ended June 30, 2007, the Partnership did not make any payments to
Provident. At December 31, 2006, the Partnership was owed by Provident $0.6
million relating to the initial public offering distributions, which were
collected in the first quarter of 2007.
8.
Long-Term Debt
The
Partnership’s long-term debt balances are summarized as follows:
|
|
|
At
June 30,
|
|
At
December 31,
|
|
|
Thousands
of dollars
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
$400
million credit facility
|
|
$
|
13,500
|
|
$
|
1,500
|
|
The
credit facility’s borrowing base was $175 million at June 30, 2007, which was an
increase from $100.0 million at March 31, 2007. The credit facility will mature
in September 2010. At June 30, 2007, the interest rate was the Prime Rate of
8.5% on the Prime Debt portion of $1.5 million and the LIBOR rate of 6.6% on
the
LIBOR portion of $12.0 million. At December 31, 2006, the interest rate was
the
Prime Rate of 8.5% on the Prime Debt portion of $1.5 million.
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
in
our ability to make distributions if aggregated letters of credit and
outstanding loan amounts exceed 90% of our borrowing base); 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.
At
June
30, 2007 and December 31, 2006, the Partnership was in compliance with the
credit facility’s covenants. At June 30, 2007, the Partnership had $0.2 million
in letters of credit outstanding.
9.
Asset Retirement Obligation
The
Partnership’s asset retirement obligation is based on the Partnership’s net
ownership in wells and facilities and its estimate of the costs to abandon
and
reclaim those wells and facilities as well as its estimate of the future timing
of the costs to be incurred. On October 10, 2006, in connection with the
Partnership’s initial public offering, the Predecessor contributed certain
properties to the Partnership along with their related asset retirement
obligation (see note 2 for details on the contribution). The total undiscounted
amount of future cash flows required to settle asset retirement obligations
for
the Partnership is estimated to be $118.5 million at June 30, 2007 and $82.4
million at December 31, 2006. The increase from year-end is attributable to
various acquisitions (see note 4 -Acquisitions). Payments to settle asset
retirement obligations occur over the operating lives of the assets, estimated
to be from 3 to 50 years. Estimated cash flows have been discounted at the
Partnership’s credit adjusted risk free rate of 7% and is partially offset by an
inflation rate of 2%. The following table presents changes in the asset
retirement obligation of the Partnership and of its Predecessor:
|
|
|
Six
Months Ended
June 30,
|
|
October
10 to
December 31.
|
|
|
Thousands
of dollars
|
|
2007
|
|
2006
|
|
|
Carrying
amount, beginning of period
|
|
$
|
10,253
|
|
$
|
-
|
|
|
Contribution
from Predecessor
|
|
|
–
|
|
|
7,456
|
|
|
Revisions
(1)
|
|
|
–
|
|
|
2,633
|
|
|
Acquisitions
|
|
|
4,711
|
|
|
–
|
|
|
Accretion
expense
|
|
|
389
|
|
|
164
|
|
|
|
|
|
|
|
|
|
|
|
Carrying
amount, end of period
|
|
$
|
15,353
|
|
$
|
10,253
|
|
(1)
Increased cost estimates and revisions to reserve life.
10.
Partners’ Equity
Private
Placements
On
May
24, 2007, the Partnership sold 4,062,500 Common Units, at a negotiated purchase
price of $32.00 per unit, to certain investors (the “Purchasers”). The
Partnership 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 the Partnership’s credit facility. Most of the debt
repaid was associated with the Partnership’s first quarter 2007 acquisition of
certain properties in West Texas.
On
May
25, 2007, the Partnership sold an additional 2,967,744 Common Units to the
same Purchasers at a negotiated purchase price of $31.00 per unit. The
Partnership 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.
In
connection with the closing of these two private placements (the “Private
Placements”), the Partnership entered into agreements with the Purchasers to
file a shelf registration statement to register the Common Units sold in the
private placements and use its commercially reasonable efforts to cause the
registration statement to become effective within 275 days of the applicable
closing dates. In addition, the agreements give the Purchasers piggyback
registration rights under certain circumstances. These registration rights
are
transferable to affiliates of the Purchasers and, in certain circumstances,
to
third parties.
If
the
shelf registration statement is not effective within 275 days of the closing
date, then the Partnership must pay the Purchasers liquidated damages of 0.25%
of the product of the purchase price times the number of registrable securities
held by the Purchasers per 30-day period for the first 60 days following such
deadline. This amount will increase by an additional 0.25% of the product of
the
purchase price times the number of registrable securities held by the Purchasers
per 30-day period for each subsequent 60 days, up to a maximum of 1.0% of the
product of the purchase price times the number of registrable securities held
by
the Purchasers per 30-day period. The aggregate amount of liquidated damages
the
Partnership must pay will not exceed 10.0% of the aggregate purchase prices.
Pursuant to the Unit Purchase Agreement for both private placements, the
Partnership agreed to indemnify the Purchasers and their respective officers,
directors and other representatives against certain losses resulting from any
breach of the Partnership’s representations, warranties or covenants contained
therein. The Private Placements were made in reliance upon an exemption from
the
registration requirements of the Securities Act of 1933 pursuant to Section
4(2)
thereof.
Distributions
On
May
15, 2007, the Partnership paid a cash distribution in respect of its first
quarter of operations in 2007 of approximately $9.3 million, or $0.4125 per
Common Unit, to its general partner and common unitholders of record as of
the
close of business on May 7, 2007.
On
February 14, 2007, the Partnership paid a cash distribution in respect to
the period from October 4, 2006 through December 31, 2006 of approximately
$8.9
million to its general partner and common unitholders of record as of the close
of business on February 5, 2007. The distribution that was paid to
unitholders was prorated to $0.399 per Common Unit from the $0.4125 that the
Partnership anticipated to pay for the full quarter, reflecting the reduced
period of time from the first day of trading of the Partnership’s Common Units
on October 4, 2006 through December 31, 2006.
11.
Financial Instruments
Fair
Value of Financial Instruments
The
Partnership’s commodity price risk management program is intended to reduce its
exposure to commodity prices and to assist with stabilizing cash flow and
distributions. Routinely, the Partnership utilizes derivative financial
instruments to reduce this volatility. With respect to derivative financial
instruments, the Partnership could be exposed to losses if a counterparty fails
to perform in accordance with the terms of the contract. This risk is managed
by
diversifying the derivative portfolio among counterparties meeting certain
financial criteria. In addition, the derivative instruments utilized by the
Partnership are based on index prices that may and often do differ from the
actual crude oil prices realized in its operations. These variations often
result in a lack of adequate correlation to enable these derivative instruments
to qualify for cash flow hedges under SFAS No. 133. Accordingly, the Partnership
does not attempt to account for its derivative instruments as cash flow hedges
and instead recognizes changes in the fair value immediately in
earnings.
The
following tables summarize the Partnership’s results relating to its derivative
instruments:
|
|
|
Successor
|
|
Predecessor
|
|
Successor
|
|
Predecessor
|
|
|
|
|
Three
Months
|
|
Three
Months
|
|
Six
Months
|
|
Six
Months
|
|
|
|
|
Ended
June 30,
|
|
Ended
June 30,
|
|
Ended
June 30,
|
|
Ended
June 30,
|
|
|
Thousands
of dollars
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
gain (loss) on derivative instruments
|
|
$
|
822
|
|
$
|
(1,089
|
)
|
$
|
3,850
|
|
$
|
(1,937
|
)
|
|
Unrealized
loss on derivative instruments
|
|
|
(8,373
|
)
|
|
(12,636
|
)
|
|
(18,069
|
)
|
|
(17,720
|
)
|
|
Losses
on derivative instruments, net
|
|
$
|
(7,551
|
)
|
$
|
(13,725
|
)
|
$
|
(14,219
|
)
|
$
|
(19,657
|
)
|
|
|
|
Successor
|
|
Successor
|
|
|
|
|
June
30,
|
|
December
31,
|
|
|
Thousands
of dollars
|
|
2007
|
|
2006
|
|
|
Current
assets:
|
|
|
|
|
|
|
Non-hedging
derivative instruments
|
|
$
|
-
|
|
$
|
3,998
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Non-hedging
derivative instruments
|
|
$
|
(5,157
|
)
|
$
|
-
|
|
|
|
|
|
(5,157
|
)
|
|
3,998
|
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
|
Non-hedging
derivative instruments
|
|
|
(8,969
|
)
|
|
(55
|
)
|
|
|
|
|
|
|
|
|
|
|
Non-hedging
derivative instruments, net
|
|
$
|
(14,126
|
)
|
$
|
3,943
|
|
The
Partnership had the following contracts in place at June 30, 2007:
|
Year
|
|
Product
|
|
Volume
|
|
Terms
(a)
|
|
Effective
Period
|
|
2007
|
|
Crude
Oil
|
|
3,213
Bbl/d
|
|
Swaps
- average $67.69 per Bbl
|
|
July
1 - December 31
|
|
|
|
|
|
338
Bbl/d
|
|
Participating
Swap $60 per Bbl (86% participation above $60 floor)
|
|
July
1 - December 31
|
|
|
|
|
|
250
Bbl/d
|
|
Collar
$66.00 (floor)/ $69.25 (Ceiling)
|
|
July
1 - December 31
|
|
|
|
|
|
250
Bbl/d
|
|
Collar
$66.00 (floor)/$71.50 (Ceiling)
|
|
July
1 - December 31
|
|
2008
|
|
Crude
Oil
|
|
2,875
Bbl/d
|
|
Swaps
- average $67.72 per Bbl
|
|
January
1 - June 30
|
|
|
|
|
|
325
Bbl/d
|
|
Swap
- $70.37 per Bbl
|
|
January
1 - December 31
|
|
|
|
|
|
250
Bbl/d
|
|
Swap
$71.24 per Bbl
|
|
July
1 - September 30
|
|
|
|
|
|
525
Bl/d
|
|
Swaps
- average $64.68 per Bbl
|
|
July
1 - December 31
|
|
|
|
|
|
750
Bbl/d
|
|
Swaps
- average $70.49 per Bbl
|
|
October
1 - December 31
|
|
|
|
|
|
250
Bbl/d
|
|
Collar
$66.00 (floor)/ $69.25 (Ceiling)
|
|
January
1 - June 30
|
|
|
|
|
|
250
Bbl/d
|
|
Collar
$66.00 (floor)/$71.50 (Ceiling)
|
|
January
1 - June 30
|
|
|
|
|
|
425
Bbl/d
|
|
Participating
Swap $60 per Bbl (76% participation above $60 floor)
|
|
January
1 - December 31
|
|
|
|
|
|
2,500
Bbl/d
|
|
Participating
Swap $60 per Bbl (53.3% participation above $60 floor)
|
|
July
1 - September 30
|
|
|
|
|
|
2,000
Bbl/d
|
|
Participating
Swap $60 per Bbl (59% participation above $60 floor)
|
|
October
1 - December 31
|
|
2009
|
|
Crude
Oil
|
|
250
Bbl/d
|
|
Swap
$71.18 per Bbl
|
|
January
1 - March 31
|
|
|
|
|
|
500
Bbl/d
|
|
Swaps
- average $70.92 per Bbl
|
|
January
1 - March 31
|
|
|
|
|
|
785
Bbl/d
|
|
Swaps
- average $65.52 per Bbl
|
|
January
1 - December 31
|
|
|
|
|
|
250
Bbl/d
|
|
Swap
$70.00 per Bbl
|
|
October
1 - December 31
|
|
|
|
|
|
210
Bbl/d
|
|
Collar
$66.00 (floor)/$79.50 (Ceiling)
|
|
January
1 - December 31
|
|
|
|
|
|
410
Bbl/d
|
|
Participating
Swap $60 per Bbl (68% participation above $60 floor)
|
|
January
1 - December 31
|
|
|
|
|
|
500
Bbl/d
|
|
Participating
Swap $60 per Bbl (55.5% participation above $60 floor)
|
|
January
1 - September 30
|
|
|
|
|
|
1,500
Bbl/d
|
|
Participating
Swap $60 per Bbl (59.7% participation above $60 floor)
|
|
January
1 - September 30
|
|
2010
|
|
Crude
Oil
|
|
500
Bbl/d
|
|
Swaps
- average $69.75 per Bbl
|
|
January
1 - March 31
|
|
|
|
|
|
183
Bbl/d
|
|
Swap
- $69.59 per Bbl
|
|
January
1 - December 31
|
|
|
|
|
|
183
Bbl/d
|
|
Collar
$66.00 (floor)/$79.25 (Ceiling)
|
|
January
1 - December 31
|
|
|
|
|
|
933
Bbl/d
|
|
Participating
Swap $60 per Bbl (59% participation above $60 floor)
|
|
January
1 - December 31
|
|
2011
|
|
Crude
Oil
|
|
1,377
Bbl/d
|
|
Participating
Swap $60 per Bbl (53% participation above $60 floor)
|
|
January
1 - December 31
|
|
|
|
|
|
177
Bbl/d
|
|
Swap
- $69.15 per Bbl
|
|
January
1 - December 31
|
|
|
|
|
|
177
Bbl/d
|
|
Collar
$66.00 (floor)/$77.60 (Ceiling)
|
|
January
1 - December 31
|
(a)
A
participating swap is a single instrument which combines a swap and a call
option with the same strike price.
While
the
Partnership’s commodity price risk management program is intended to reduce its
exposure to commodity prices and assist with stabilizing cash flow and
distributions, to the extent the Partnership has hedged a significant portion
of
its expected production and the cost for goods and services increase, the
Partnership’s margins would be adversely affected.
12.
Stock and Other Valuation-Based Compensation Plans
Effective
January 1, 2006, the Predecessor adopted the fair value recognition provisions
of SFAS No. 123(R),
Share-Based
Payments
.
SFAS
No. 123(R) requires that the compensation expense relating to share-based
payment transactions be recognized in financial statements. BreitBurn Management
as successor is following the same method as BreitBurn Energy, the Predecessor.
In 2006, the cumulative effect of adoption of SFAS No. 123(R) was a benefit
of
approximately $0.6 million.
Stock-based
compensation expense for the second quarter and six months ended June 30, 2007,
was $4.1 million and $7.7 million, respectively. The amount of stock-based
compensation included in general and administrative expenses (“G&A”) was
$3.9 million and $7.3 million for the second quarter and six months periods,
respectively. The remaining amount of stock-based compensation was included
in
operating costs. Stock-based compensation expense for the Predecessor was $2.5
million and $4.3 million for the second quarter and six months ended June 30,
2006, respectively.
During
the first six months of 2007, the Partnership granted 90,156 Partnership based
performance and restricted trust units under the Partnership’s 2006 Long-Term
Incentive Plan. In addition, the Partnership granted 17,447 Partnership
performance units to the non-employee directors of its general
partner.
For
detailed information on the Partnership’s various compensation plans, see the
Partnership’s 2006 Annual Report on Form 10-K.
13.
Commitments and Contingencies
The
Partnership is involved in various lawsuits, claims and inquiries, most of
which
are routine to the nature of its business. In the opinion of the Management,
the
resolution of these matters will not have a material effect on the Partnership’s
financial position, results of operations or liquidity.
For
our
newly acquired 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 the Partnership
having to find transportation alternatives, increased transportation costs,
or
involuntary curtailment of its oil production in Florida, which could have
a
negative impact on its future consolidated financial position, results of
operations or cash flows.
In
connection with the recent private placements of Common Units to finance the
Calumet Acquisition and the BEPI Acquisition, the Partnership agreed to file
a
shelf registration statement to register the Common Units it sold. If the shelf
registration statement is not effective within 275 days after the closing of
such private placements, then the Partnership must pay the Purchasers liquidated
damages. The Partnership also agreed to indemnify the Purchasers and their
respective officers, directors and other representatives against certain losses
resulting from any breach of the Partnership’s representations, warranties or
covenants contained in the purchase agreements for such sales. The Partnership
believes that it will be able to meet these requirements and does not expect
to
incur any damages. See the discussion under note 10 regarding the Partnership’s
responsibilities pertaining to the sale of its Common Units in the private
placements.
14.
Supplemental Cash Flow Data
Supplemental
cash flows and non-cash transactions were as follows:
|
|
|
Successor
|
|
Predecessor
|
|
Successor
|
|
Predecessor
|
|
|
|
|
Three
Months
|
|
Three
Months
|
|
Six
Months
|
|
Six
Months
|
|
|
|
|
Ended
June 30,
|
|
Ended
June 30,
|
|
Ended
March 31,
|
|
Ended
March 31,
|
|
|
Thousands
of dollars
|
|
2007
|
|
2006
|
|
2007
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
information relating to Consolidated Statement of Cash
Flows
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for interest
|
|
$
|
844
|
|
$
|
731
|
|
$
|
959
|
|
$
|
1,600
|
|
15.
Minority Interests
The
Partnership, through the BEPI Acquisition (see note 4 - Acquisitions) acquired
the limited partner interest (99%) of BEPI. As such, the Partnership is fully
consolidating the results of BEPI and thus is recognizing a minority interest
liability representing the book value of the general partner’s interests. At
June 30, 2007, the amount of this minority interest liability was $0.5 million.
The general partner of BEPI holds a 35% reversionary interest under the existing
limited partnership agreement applicable to the properties. This reversionary
interest is expected to occur at a defined payout, which currently is estimated
to occur in 2015 based on current price and cost projections.
A
wholly
owned subsidiary of the Predecessor and an unrelated real estate development
company formed a limited liability company to conduct a feasibility study for
a
residential and commercial real estate project on lands owned by the
Predecessor. The limited liability company remains wholly owned by the
Predecessor and as such is not reflected in the Partnership’s balance sheet. For
more detailed information on the Predecessor’s ownership and consolidation of
this limited liability company, see the minority interest note in the
consolidated financial statements of the Partnership’s 2006 Annual Report on
Form 10-K.
16.
Subsequent Event
On
August
14, 2007, the Partnership paid a cash distribution of approximately $9.3 million
in respect of it second quarter of operations in 2007 to its general partner
and
common unitholders of record as of the close of business on August 7, 2007.
The
distribution that was paid to unitholders was $0.4225 per Common
Unit.
Item
2.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations
You
should read the following discussion and analysis in conjunction with
Management’s Discussion and Analysis in Item 7 of our 2006 Annual Report on Form
10-K and the consolidated financial statements and related notes therein and
Item 2 of our Quarterly Report on Form 10-Q for the period ending March 31,
2007
and the consolidated financial statements and related notes therein. Our 2006
Annual Report on Form 10-K contains a discussion of other matters not included
herein, such as disclosures regarding critical accounting policies and estimates
and contractual obligations. You should also read the following discussion
and
analysis together with the cautionary statement regarding forward-looking
statements on page 1 of this report.
Overview
We
are an
independent oil and gas partnership focused on the acquisition, exploitation
and
development of oil and gas properties. Our objective is to manage our oil and
gas producing properties for the purpose of generating cash flow and making
distributions to our unitholders. Our assets consist primarily of producing
and
non-producing crude oil reserves located in the Los Angeles Basin in California,
the Wind River and Big Horn Basins in central Wyoming, the Permian Basin of
West
Texas and the Sunniland Trend in South Florida.
Our
Predecessor, BreitBurn Energy, is a 95.78% owned indirect subsidiary of
Provident, a publicly traded Canadian energy trust. Provident acquired its
interest in BreitBurn Energy in June 2004 with the intent to use BreitBurn
Energy as the primary acquisition vehicle to grow its upstream energy business
in the United States. BreitBurn Energy Corporation (“BreitBurn Corporation”)
owns the remaining 4.22% in BreitBurn Energy. In October 2004, BreitBurn Energy
acquired the Orcutt Hills Oil Field in California and in March 2005, it acquired
Nautilus Resources, LLC (‘‘Nautilus’’), a privately held company with assets in
the Wind River and Big Horn Basins in central Wyoming.
On
October 10, 2006, we completed our initial public offering of 6,000,000 Common
Units representing limited partner interests in the Partnership at $18.50 per
unit, or $17.205 per unit after payment of the underwriting discount. On
November 6, 2006, we also completed the sale of an additional 900,000 Common
Units to cover over-allotments in the initial public offering.
On
May 24
and 25, 2007, we sold approximately $130 million and $92 million, respectively,
of Common Units in two private placements (see note 10 to the consolidated
financial statements included in this report for additional information on
the
private placements). We issued and sold 4,062,500 and 2,967,744 Common Units
at
$32.00 per unit and $31.00 per unit, respectively.
As
a
result of the transactions described above as of June 30, 2007, Provident and
BreitBurn Corporation collectively own 15,075,758 Common Units, representing
a
51.97% limited partner interest and a 1.52% general partner interest in us.
As
of such date, the public holders own 48.03% of the limited partner Common Units.
Our
business strategy includes acquiring long-lived assets with low-risk
exploitation and development opportunities; using our technical expertise and
state-of-the-art technologies to identify and implement successful exploitation
techniques to maximize reserve recovery; utilizing the benefits of our
relationship with Provident to pursue acquisitions; and reducing cash flow
volatility through commodity price derivatives.
Significant
Acquisitions
Second
Quarter 2007
On
May
24, 2007, we completed the Calumet Acquisition (see note 4 to the consolidated
financial statements included in this report for further details) to acquire
certain interests in oil leases and related assets located along the Sunniland
Trend in South Florida. The Calumet Properties are comprised of five separate
oil fields, one 23-mile pipeline serving one field, one storage terminal and
rights in a shipping terminal. After adjusting for costs and revenues for the
period between the effective date of January 1, 2007 and the closing date,
including interest paid to the seller and after taking into account more than
218,000 barrels of crude oil held in storage as of the closing date, we paid
approximately $107 million. The acquisition was financed by the sale of Common
Units through a private placement. This acquisition added 9.5 MMBbls to our
total estimated proved reserves, of which approximately 100% was oil and 90%
was
classified as proved developed reserves.
On
May
25, 2007, we completed the BEPI Acquisition (see note 4 to the consolidated
financial statements included in this report for further details) to purchase
the limited partner interest in BEPI for a total purchase price of approximately
$82 million. BEPI owns properties in the East Coyote and Sawtelle Fields in
the
Los Angeles Basin in California. The general partner of BEPI is an affiliate
of
our general partner but in which we have no ownership interest. As part of
the
transaction, BEPI distributed a 1.5% override on the oil and gas royalties
in
the two fields to the seller. The 1.5% override burden will be borne solely
through our interest in BEPI. In connection with the acquisition, we also
terminated existing hedge contracts related to future production from BEPI
for
approximately $10.4 million. The acquisition was financed by the sale of Common
Units through a private placement. This acquisition added 6.5 MMBoe to our
total
estimated proved developed reserves, of which approximately 99% was
oil.
First
Quarter 2007
On
January 23, 2007, we completed the purchase of certain oil and gas properties
known as the “Lazy JL Field” in the Permian Basin of Texas and related property
and equipment from Voyager Gas Corporation. The purchase was made pursuant
to
the terms and conditions of a Purchase and Sale Agreement with Voyager entered
into on January 22, 2007 and was effective January 1, 2007. The purchase price
for the Lazy JL Field properties was approximately $29.0 million in cash, which
we financed through borrowings under our existing revolving credit facility.
The
Lazy JL Field added 2.0 MMBoe to our total estimated proved reserves, of which
approximately 98% was oil and 69% was classified as proved developed
reserves.
These
acquisitions are consistent with our strategy of acquiring long-lived assets
with predictable production from established fields. By adding these properties,
we diversified our asset base and established a presence in two new geographic
areas. We continue to actively pursue other attractive acquisition targets
that
fit our business model and are capable of generating incremental cash flow
for
our unitholders.
Initial
Public Offering
In
connection with our 2006 initial public offering, BreitBurn Energy contributed
to us properties, which included certain fields in the Los Angeles Basin in
California, including its interests in the Santa Fe Springs, Rosecrans and
Brea
Olinda Fields, and in the Wind River and Big Horn Basins in central Wyoming.
BreitBurn Management operates approximately 99% of the total wells in which
we
have interests. We conduct our operations through subsidiaries that own the
operating assets. We own directly or indirectly all of the ownership interests
in our operating subsidiaries.
BreitBurn
Management
We
have
no employees. BreitBurn Management, a majority owned subsidiary of Provident
operates our assets and performs other administrative services for us such
as
accounting, corporate development, finance, land, legal and engineering pursuant
to the terms of an Administrative Services Agreement. BreitBurn Management
also
manages the operations of BreitBurn Energy, and the employees of BreitBurn
Management devote a portion of their time to the operation of BreitBurn Energy’s
business.
Under
the
Administrative Services Agreement, we reimburse BreitBurn Management for all
direct and indirect expenses it incurs in connection with the services it
performs for us (including salary, bonus, incentive compensation and other
amounts paid to executive officers). To the extent that the services performed
by BreitBurn Management benefit both us and BreitBurn Energy, we each are
required to reimburse BreitBurn Management in proportion to the benefits each
of
us receives. BreitBurn Management generally allocates the costs of the services
of BreitBurn Management personnel providing services to both entities based
on
BreitBurn Management’s good-faith determination of actual time spent performing
the services, plus expenses. During 2006, if services performed by BreitBurn
Management benefiting both the Partnership and BreitBurn Energy could not be
allocated on the basis of actual time spent on each entity, then such expenses
were allocated to each entity in the same proportion as the aggregate barrels
of
oil equivalents produced by each entity related to the aggregate barrels of
oil
equivalents produced by both entities combined during the same period. For
2007,
the allocation methodology has been changed to reflect the fact that the most
intense portion of the Partnership’s initial public offering startup is now
complete and a more balanced allocation of resources between the Partnership
and
BreitBurn Energy is expected. BreitBurn Management currently allocates its
expenses between us and BreitBurn Energy on the basis of which entity received
the services to which specific expenses relate or, in instances where expenses
relate to services provided for the benefit of both entities, by allocating
51%
of such expenses to the Partnership and 49% of such expenses to BreitBurn
Energy. This allocation split for 2007 was derived from a weighted average
of
three components that were forecasted for the Partnership and BreitBurn Energy:
(i) the proportionate level of 2007 forecasted
gross
barrels of oil equivalents production; (ii) the proportionate level of 2007
forecasted operating expenses; and (iii) the proportionate level of 2007
forecasted capital expenditures. BreitBurn Management will continue from time
to
time to review the methodology utilized to allocate costs, including reviewing
the impacts of acquisitions, capital programs, and other factors, and may modify
the methodology to appropriately reflect the value attributable to
us.
Outlook
Oil
prices have increased significantly since the beginning of 2004. We anticipate
a
continued favorable commodity price environment in 2007. Significant factors
that will impact near-term commodity prices include political developments
in
Iraq, Iran and other oil producing countries, the extent to which members of
the
OPEC and other oil exporting nations are able to manage oil supply through
export quotas and variations in key North American natural gas and refined
products supply and demand indicators. A substantial portion of our estimated
production is currently covered through derivative transactions through 2011,
and we intend to continue to enter into commodity derivative transactions to
mitigate the impact of price volatility on our oil and gas
revenues.
During
2006, industry price levels for WTI averaged $66 per barrel. In the second
quarter 2007, WTI averaged $65 per barrel, compared with about $70 a year
earlier. The average price for WTI for the first six months of 2007 was $62
per
barrel compared with about $67 per barrel a year earlier. While lower than
a
year earlier, crude-oil prices have remained strong due mainly to increasing
demand in growing economies, the heightened level of geopolitical uncertainty
in
some areas of the world and supply concerns in other key producing regions.
The
price for WTI at the end of July 2007 was approximately $78 per
barrel.
The
increase in commodity prices in recent years has resulted in increased drilling
activity and demand for drilling and operating services and equipment in North
America. We anticipate drilling service and labor costs, as well as costs of
equipment and raw materials, to remain at or exceed the levels experienced
in
2006. While our commodity price risk management program is intended to reduce
our exposure to commodity prices and assist with stabilizing cash flow and
distributions, to the extent we have hedged a significant portion of our
expected production and the cost for goods and services increase, our margins
would be adversely affected.
We
analyze the prices we realize from sales of our oil and gas production and
the
impact on those prices of differences in market-based index prices and the
effects of our derivative activities. We market our oil and natural gas
production to a variety of purchasers based on regional pricing. Crude oil
produced in the Los Angeles Basin of California and Wind River and Big Horn
Basins of central Wyoming typically sells at a discount to NYMEX WTI crude
oil
due to, among other factors, its relatively heavier grade and/or relative
distance to market. Our Los Angeles Basin crude oil is generally medium gravity
crude. Because of its proximity to the extensive Los Angeles refinery market,
it
trades at only a minor discount to NYMEX WTI. Our Wyoming crude oil, while
generally of similar quality to our Los Angeles Basin crude oil, trades at
a
significant discount to NYMEX WTI because of its distance from a major refining
market and the fact that it is priced relative to the Bow River benchmark for
Canadian heavy sour crude oil, which has historically traded at a significant
discount to NYMEX WTI. Our newly acquired Florida crude oil also trades at
a
significant discount to NYMEX primarily because of its low gravity and other
quality characteristics as well as its distance from a major refining market.
Our revenues and net income are sensitive to oil and natural gas prices. We
enter into various derivative contracts intended to achieve more predictable
cash flow and to reduce our exposure to adverse fluctuations in the prices
of
oil and natural gas. We currently maintain derivative arrangements for a
significant portion of our oil and gas production. See ‘‘Item 3. Quantitative
and Qualitative Disclosure About Market Risk” and note 11 in the consolidated
financial statements included in this report for more detail on our derivative
activities.
Results
of Operations
The
table
below summarizes certain of the results of operations and period-to-period
comparisons attributable to our operations for the periods indicated. These
results are presented for illustrative purposes only and are not indicative
of
our future results. The current year data reflects our results as they are
presented in our consolidated financial statements under the “Successor”
columns. The prior year data reflects only those properties that were owned
by
the Predecessor when it contributed properties to us in the initial public
offering. The prior year data does not correspond to the financial statements
included elsewhere in this report for the Predecessor and represents only a
subset of those financial statements.
|
|
|
Quarter
Ended
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
|
|
|
|
|
June
30,
|
|
|
|
|
|
June
30,
|
|
|
|
|
|
|
Thousands
of dollars, except as indicated
|
|
2007
|
|
2006
|
|
Inc
/ (dec)
|
|
2007
|
|
2006
|
|
Inc
/ (dec)
|
|
|
Total
Production (MBoe)
|
|
|
536
|
|
|
407
|
|
|
129
|
|
|
32
|
%
|
|
969
|
|
|
805
|
|
|
164
|
|
|
20
|
%
|
|
Average
daily production (Boe/d)
|
|
|
5,889
|
|
|
4,473
|
|
|
1,416
|
|
|
32
|
%
|
|
5,354
|
|
|
4,448
|
|
|
906
|
|
|
20
|
%
|
|
Sales
volumes (Mboe)
|
|
|
587
|
|
|
407
|
|
|
180
|
|
|
44
|
%
|
|
1,021
|
|
|
805
|
|
|
216
|
|
|
27
|
%
|
|
Average
realized sales price (a)
|
|
$
|
54.40
|
|
$
|
60.79
|
|
$
|
(6.39
|
)
|
|
-11
|
%
|
$
|
52.15
|
|
$
|
55.21
|
|
$
|
(3.06
|
)
|
|
-6
|
%
|
|
NYMEX
WTI Spot Prices
|
|
$
|
64.97
|
|
$
|
70.46
|
|
$
|
(5.49
|
)
|
|
-8
|
%
|
$
|
61.55
|
|
$
|
66.89
|
|
$
|
(5.34
|
)
|
|
-8
|
%
|
|
Average
price differentials
|
|
$
|
10.57
|
|
$
|
9.67
|
|
$
|
0.90
|
|
|
9
|
%
|
$
|
9.40
|
|
$
|
11.68
|
|
$
|
(2.28
|
)
|
|
-20
|
%
|
|
Oil,
natural gas and natural gas liquid sales
|
|
$
|
32,413
|
|
$
|
24,808
|
|
$
|
7,605
|
|
|
31
|
%
|
$
|
53,802
|
|
$
|
44,575
|
|
$
|
9,227
|
|
|
21
|
%
|
|
Realized
gains (losses) on derivative instruments
|
|
|
822
|
|
|
530
|
|
|
292
|
|
|
-55
|
%
|
|
3,850
|
|
|
-
|
|
|
3,850
|
|
|
n/a
|
|
|
Unrealized
losses on derivative instruments
|
|
|
(8,373
|
)
|
|
(13,697
|
)
|
|
(5,324
|
)
|
|
39
|
%
|
|
(18,069
|
)
|
|
(16,875
|
)
|
|
1,194
|
|
|
-7
|
%
|
|
Other
revenues, net
|
|
|
237
|
|
|
267
|
|
|
(30
|
)
|
|
-11
|
%
|
|
478
|
|
|
537
|
|
|
(59
|
)
|
|
-11
|
%
|
|
Total
revenues
|
|
$
|
25,099
|
|
$
|
11,908
|
|
$
|
13,191
|
|
|
111
|
%
|
$
|
40,061
|
|
$
|
28,237
|
|
$
|
11,824
|
|
|
42
|
%
|
|
Lease
operating expenses
|
|
$
|
10,711
|
|
$
|
6,273
|
|
$
|
4,438
|
|
|
71
|
%
|
$
|
19,322
|
|
$
|
12,809
|
|
$
|
6,513
|
|
|
51
|
%
|
|
Transportation
expenses
|
|
|
409
|
|
|
-
|
|
|
409
|
|
|
n/a
|
|
|
409
|
|
|
-
|
|
|
409
|
|
|
n/a
|
|
|
Purchases
|
|
|
69
|
|
|
66
|
|
|
3
|
|
|
5
|
%
|
|
150
|
|
|
134
|
|
|
16
|
|
|
12
|
%
|
|
Change
in inventory
|
|
|
3,415
|
|
|
0
|
|
|
3,415
|
|
|
n/a
|
|
|
3,415
|
|
|
-
|
|
|
3,415
|
|
|
n/a
|
|
|
Total
Operating Costs
|
|
$
|
14,604
|
|
$
|
6,339
|
|
$
|
8,265
|
|
|
130
|
%
|
$
|
23,296
|
|
$
|
12,943
|
|
$
|
10,353
|
|
|
80
|
%
|
|
Lease
operating expenses per Boe (b)
|
|
$
|
19.98
|
|
$
|
15.41
|
|
$
|
4.57
|
|
|
30
|
%
|
$
|
19.94
|
|
$
|
15.91
|
|
$
|
4.03
|
|
|
25
|
%
|
|
Depletion,depreciation
& amortization
|
|
$
|
4,511
|
|
$
|
2,336
|
|
$
|
2,175
|
|
|
93
|
%
|
$
|
7,598
|
|
$
|
4,630
|
|
$
|
2,968
|
|
|
64
|
%
|
|
DD&A
per Boe (b)
|
|
$
|
8.42
|
|
$
|
5.74
|
|
$
|
2.68
|
|
|
47
|
%
|
$
|
7.84
|
|
$
|
5.75
|
|
$
|
2.09
|
|
|
36
|
%
|
(a)
Realized prices = (Oil and gas sales - Transportation - Purchases ) / Sales
volumes
(b)
Lease
operating expenses per Boe and DD&A per Boe are calculated using total
production volumes.
Comparison
of Results of the Partnership for the Quarter and Six Months Ended June 30,
2007
and 2006
The
variance in the results of the Partnership was due to the following
components:
Production
For
the
second quarter ended June 30, 2007, production volumes increased by 129 MBoe,
or
32%, as compared to the same period a year ago. The increase was primarily
due
to acquisitions that added 120 MBoe of production during the current period.
Our
Wyoming production was 29 MBoe higher in the second quarter of 2007 compared
to
the same period a year ago, primarily due to successful optimization and
drilling projects. These increases were partially offset by lower production
due
to natural field declines in our California properties.
For
the
six months ended June 30, 2007 as compared to the same period a year ago,
production volumes increased by 164 MBoe, or 20%. The increase was primarily
due
to acquisitions that added 156 MBoe in the first six months of 2007. Our Wyoming
production was 44 MBoe higher in the first six months of 2007 compared to the
same period a year ago due to successful optimization and drilling projects.
These increases were offset by lower production due to natural field declines
primarily in our California properties.
Revenues
Total
revenues increased by $13.2 million in the second quarter of 2007 as compared
to
the same period a year ago. Sales volumes in the current quarter were 180 MBoe,
or 44%, higher than the prior year quarter. This increase was primarily from
acquisitions that added 166 MBoe of sales in the current period. Our Florida
operations had 110 MBoe of sales volume that was sold from inventory purchased
in the Calumet Acquisition. In addition, our sales volumes included 22 MBoe
related to our Texas operations and 34 MBoe from the BEPI Acquisition, both
of
which were acquisitions in 2007. The second quarter of 2007 included $5.3
million in lower unrealized losses from derivative instruments as compared
to
the second quarter of 2006. Realized gains from derivative instruments during
the current quarter were $0.3 million higher than the comparable quarter a
year
ago.
Total
revenues increased by $11.8 million in the first six months of 2007 as compared
to the same period of 2006. Sales volumes in the first six months of 2007 were
216 MBoe, or 27%, higher than the same period a year ago. This increase was
primarily from acquisitions that added 193 MBoe of sales in the period. Our
sales volumes included 110 MBoe from our Florida operations, 49 MBoe from our
Texas operations and 34 MBoe from the BEPI Acquisition. The first six months
of
2007 included $1.2 million in higher unrealized losses from derivative
instruments. Realized gains from derivative instruments during the first six
months of 2007 were $3.9 million versus zero during the comparable period of
2006.
Lease
operating expenses
Lease
operating expenses for the current quarter of 2007 totaled $10.7 million, or
$19.98 per Boe, 30% higher than the same period a year ago. Lease operating
expenses for the first six months of 2007 totaled $19.3 million, or $19.94
per
Boe, 25% higher than the same period a year ago. The higher per Boe amounts
are
primarily attributable to the effects of industry-wide service and material
cost
increases, especially in California, in addition to higher maintenance related
expenditures.
Transportation
costs
In
our
acquisition in Florida, our crude oil sales are transported from the field
to
the sale point by trucks and barge. Transportation costs incurred in connection
with such operations are reflected as an operating cost. In the second quarter
of 2007, we recorded one sale from our Florida operations as discussed in the
revenues section above and had transportation costs of approximately $0.4
million associated with that sale.
Depletion,
depreciation and amortization
Depletion,
depreciation and amortization (“DD&A”) expense totaled $4.5 million, or
$8.42 per Boe, in the second quarter of 2007, which was an increase of
approximately 47% per Boe from the same period a year ago. DD&A expense
totaled $7.6 million, or $7.84 per Boe, in the first six months of 2007, which
was an increase of approximately 36% per Boe from the same period a year ago.
The increase in DD&A rates was due to the capital investments from our
recently completed acquisitions. Under the successful efforts method of
accounting, we calculate DD&A on an individual producing field basis.
Changes in reserve estimates and in the timing and amount of abandonment cost
estimates as well as changes in the timing and amount of development projects
of
one or two fields can cause variations in the aggregate DD&A rate. The
aggregate DD&A rate is also impacted by acquisitions which where purchased
at market values.
General
and Administrative Expenses for the Quarter and Six Months Ended June 30,
2007
Our
general and administrative expenses totaled $6.6 million and $14.1 million
for
the second quarter and six months ended June 30, 2007, respectively. This
included $3.9 million and $7.3 million in stock-based compensation expense
related to management incentive plans for the second quarter and six months
ended June 30, 2007, respectively, reflecting an approximate 40% increase in
the
price of our Common Units during the first six months of 2007. General and
administrative expenses other than stock-based compensation were $2.8 million
and $6.8 million for the second quarter and six months ended June 30, 2007,
respectively. The second quarter expenditures were $1.2 million lower than
the
first quarter of 2007, which included approximately $1.0 million in audit,
tax
preparation and legal professional fees attributable to year-end compliance
costs.
Results
of Operations - For the Partnership’s Predecessor for the quarter and six months
ended June 30, 2006
The
results of operations presented below primarily covers the historical results
of
BreitBurn Energy. Because the historical results of BreitBurn Energy include
combined information for both the properties conveyed to us in connection with
our initial public offering and the properties retained by BreitBurn Energy,
we
do not consider these historical results of BreitBurn Energy for operations
and
period-to-period comparisons of our results as indicative of our future results.
Nevertheless, they are presented here to provide a possible context for our
current operations.
BreitBurn
Energy - Quarter and Six Months Ended June 30, 2006
Second
Quarter Ended June 30, 2006
Net
revenue for BreitBurn Energy was $24.4 million in the second quarter of 2006,
which included unrealized losses on derivative instruments of $12.6 million
and
realized losses on derivative instruments of $1.1 million. The revenues from
the
properties conveyed to us represented approximately 49 percent of the total
BreitBurn Energy total revenues.
Operating
costs for BreitBurn Energy were $10.9 million in the second quarter of 2006.
The
operating costs of the properties conveyed to us represented approximately
58
percent of the total BreitBurn Energy total operating costs.
General
and administrative expenses for BreitBurn Energy were $7.9 million in the second
quarter of 2006. Our current levels of general and administrative expenses
are
not comparable with its Predecessor due to higher expenses from being a publicly
traded enterprise.
DD&A
expenses for BreitBurn Energy were $3.5 million in the second quarter of 2006.
The DD&A of the properties conveyed to us represented approximately 66
percent of the total BreitBurn Energy DD&A expense.
Six
Months Ended June 30, 2006
Net
revenue for BreitBurn Energy was $50.3 million in the six months ended June
30,
2006, which included unrealized losses on derivative instruments of $17.7
million and realized losses on derivative instruments of $1.9 million. The
revenues from the properties conveyed to us represented approximately 56 percent
of the total BreitBurn Energy total revenues.
Operating
costs for BreitBurn Energy were $22.2 million in the six months ended June
30,
2006. The operating costs of the properties conveyed to us represented
approximately 58 percent of the total BreitBurn Energy total operating
costs.
General
and administrative expenses for BreitBurn Energy were $12.2 million in the
six
months ended June 30, 2006. Our current levels of general and administrative
expenses are not comparable to those of our Predecessor due to our higher
expenses from being a publicly traded enterprise.
DD&A
expenses for BreitBurn Energy were $7.0 million in the six months ended June
30,
2006. The DD&A of the properties conveyed to us represented approximately 66
percent of the total BreitBurn Energy DD&A expense.
Liquidity
and Capital Resources
Our
cash
flow from operating activities for the six months ended June 30, 2007 was $26.9
million. The current year results include collections of approximately $3.4
million for certain receivables from our Predecessor that were not collected
at
December 31, 2006. In addition, the 2007 results included stock compensation
payments of $7.6 million.
During
2007, we completed acquisitions totaling approximately $230 million. The Calumet
Acquisition totaled approximately $108 million, the BEPI Acquisition totaled
approximately $92 million and the Lazy JL acquisition totaled $29 million.
Our
capital expenditures in the first six months of 2007 were $10.4
million.
Our
primary sources of liquidity are cash generated from operations, amounts
available under our revolving credit facility and funds that were raised through
our recent Private Placements or may be raised through possible future private
or public equity and debt offerings. We raised approximately $222 million by
selling approximately seven million Common Units in two Private Placements
which
funded the Calumet Acquisition and the BEPI Acquisition and were used to repay
some of our outstanding borrowings under our credit facility. In the first
six
months of 2007, our cash distributions totaled approximately $18.2 million.
Our
cash distribution in the second quarter of 2007 was $0.4225 per unit, or $1.69
per unit on an annualized basis.
We
had
outstanding borrowings under our credit facility of $13.5 million at June 30,
2007 and $1.5 million at December 31, 2006. During 2007, we borrowed $76.5
million and repaid $64.5 million under the credit facility.
The
Partnership plans to make substantial capital expenditures in the future for
the
acquisition, exploitation and development of oil and natural gas properties.
The
Partnership intends to finance its acquisition and future development and
exploitation activities with a combination of cash flow from operations and
issuances of debt and equity.
If
cash
flow from operations does not meet our expectations, we may reduce the expected
level of capital expenditures and/or borrow a portion of the funds under the
credit facility, issue debt or equity securities or obtain additional capital
from other sources. Funding our capital program from sources other than cash
flow from operations could limit our ability to make acquisitions. In the event
we make one or more acquisitions and the amount of capital required is greater
than the amount we have available for acquisitions at that time, we could reduce
our expected level of capital expenditures in other areas and/or seek additional
capital. If we seek additional capital for that or other reasons, we may do
so
through traditional reserve base borrowings, joint venture partnerships,
production payment financings, asset sales, offerings of debt or equity
securities or other means. We cannot be sure that needed capital will be
available on acceptable terms or at all. Our ability to raise funds through
the
incurrence of additional indebtedness will be limited by covenants in our credit
facility agreement. If we are unable to obtain funds when needed or on
acceptable terms, we may not be able to complete acquisitions that may be
favorable to us or finance the capital expenditures necessary to replace our
reserves and, in certain circumstances, may elect or be required to reduce
the
level of our quarterly distributions.
Credit
Facility
Our
wholly owned subsidiary, BreitBurn Operating L.P., as borrower, and we and
our
operating subsidiaries, as guarantors, have a $400.0 million revolving credit
facility with Wells Fargo Bank, N.A., as lead arranger, administrative agent
and
issuing lender, and a syndicate of banks. The current borrowing base of this
credit facility was increased to $175 million from $100 million during the
second quarter of 2007. On June 1 and December 1 of each calendar year, the
lenders redetermine the borrowing base based primarily upon the loan collateral
value assigned to the properties that we own. The credit facility will mature
in
September 2010, and borrowings bear interest at a rate per annum equal to the
lesser of (i) the LIBOR or the Base Rate, as the case may be, plus the
Applicable Margin (LIBOR, Base Rate and Applicable Margin are each defined
in
the credit facility), or (ii) the Highest Lawful Rate (as defined in the credit
facility).
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
in
our ability to make distributions if aggregated letters of credit and
outstanding loan amounts exceed 90% of our borrowing base); 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.
The
credit facility requires us to maintain a leverage ratio (defined as the ratio
of total debt to EBITDA) as of the last day of each quarter, on a last twelve
month basis, of not more than 3.50 to 1.00. In addition, the credit facility
requires us to maintain a current ratio as of the last day of each quarter,
of
not less than 1.10 to 1.00. We are required to maintain an interest coverage
ratio (defined as the ratio of EBITDA to consolidated interest expense) as
of
the last day of each quarter, of not less than 2.75 to 1.00. As of June 30,
2007, we were in compliance with these covenants.
Accounting
Standards Not Yet Adopted
SFAS
No. 159 “The Fair Value Option for Financial Assets and Financial
Liabilities — including an amendment of FAS 115” (“SFAS No.
159”).
In
February 2007, the FASB issued SFAS No. 159 which allows entities to choose,
at
specified election dates, to measure eligible financial assets and liabilities
at fair value in situations in which they are not otherwise required to be
measured at fair value. If a company elects the fair value option for an
eligible item, changes in that item’s fair value in subsequent reporting periods
must be recognized in current earnings. The provisions of SFAS No. 159 will
be
effective for us beginning January 1, 2008. We are evaluating the impact of
adoption of SFAS No. 159 but do not currently expect the adoption to have a
material impact on our financial position, results of operations or cash
flows.
SFAS
No. 157, Fair Value Measurements.
In
September 2006, the FASB issued SFAS No. 157, which will become effective
for us on January 1, 2008. This standard defines fair value, establishes a
framework for measuring fair value and expands disclosures about fair value
measurements. The Statement does not require any new fair value measurements
but
would apply to assets and liabilities that are required to be recorded at fair
value under other accounting standards. The impact to us from the adoption
of
SFAS No. 157 in 2008 will depend on our assets and liabilities at that time
that they are required to be measured at fair value.
Item
3.
Quantitative
and Qualitative Disclosure About Market Risk
The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from adverse
changes in oil and gas prices and interest rates. The disclosures are not meant
to be precise indicators of expected future losses, but rather indicators of
reasonably possible losses. This forward-looking information provides indicators
of how we view and manage our ongoing market risk exposures. All of our market
risk sensitive instruments were entered into for purposes other than speculative
trading.
Due
to
the historical volatility of crude oil and natural gas prices, we have entered
into various derivative instruments to manage exposure to volatility in the
market price of crude oil. We intend to use options (including collars) and
fixed price swaps for managing risk relating to commodity prices. All contracts
are settled with cash and do not require the delivery of physical volumes to
satisfy settlement. While this strategy may result in us having lower revenues
than we would otherwise have if we had not utilized these instruments in times
of higher oil and natural gas prices, management believes that the resulting
reduced volatility of prices and cash flow is beneficial. While our commodity
price risk management program is intended to reduce our exposure to commodity
prices and assist with stabilizing cash flow and distributions, to the extent
we
have hedged a significant portion of our expected production and the cost for
goods and services increases, our margins would be adversely
affected.
Commodity
Price Risk
Our
derivative contracts as of June 30, 2007, for 2007 through 2011, are summarized
in the table presented in note 11 in the consolidated financial statements
included in this report.
Location
and quality discounts or differentials attributable to our production are not
reflected in the prices listed in note 11. The agreements provide for monthly
settlement based on the differential between the agreement price and the actual
NYMEX crude oil price. Our Los Angeles Basin crude is generally medium gravity
crude. Because of its proximity to the extensive Los Angeles refinery market,
it
trades at only a minor discount to NYMEX. Our Wyoming crude, while generally
of
similar quality to our Los Angeles Basin crude oil, trades at a significant
discount to NYMEX because of its distance from a major refining market and
the
fact that it is priced relative to the Bow River benchmark for Canadian heavy
sour crude oil, which has historically traded at a significant discount to
WTI.
Our Texas crude is of a higher quality than our Los Angeles or Wyoming crude
oil
and trades at prices substantially equal to NYMEX crude oil prices. Our Florida
crude also trades at a significant discount to NYMEX primarily because of its
low gravity and other quality characteristics as well as its distance from
a
major refining market.
All
derivative instruments are recorded on the balance sheet at fair value. Fair
value is generally determined based on the difference between the fixed contract
price and the underlying market price at the determination date, and/or
confirmed by the counterparty. Changes in the fair value of derivatives that
do
not qualify as a hedge or are not designated as a hedge are recorded in
commodity derivative income (loss) on the statement of operations.
The
fair
value of our outstanding oil commodity derivative instruments at June 30, 2007
was approximately a liability of $14 million. With a $5.00 per barrel increase
or decrease in the price of oil, the fair value of our outstanding oil commodity
derivative instruments would have increased or decreased our liability by $23
million, respectively.
Item
4.
Controls
and Procedures.
Controls
and Procedures
We
maintain disclosure controls and procedures that are designed to ensure that
information required to be disclosed in the reports that we file or submit
under
the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), is
recorded, processed, summarized and reported within the time periods specified
in the SEC's rules and forms, and that such information is accumulated and
communicated to management, including our principal executive officers and
principal financial officer, as appropriate, to allow timely decisions regarding
required disclosures. Our general partner’s Chief Executive Officers and Chief
Financial Officer, after evaluating the effectiveness of our “disclosure
controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) under the
Exchange Act), as of June 30, 2007, concluded that our disclosure controls
and
procedures were not effective because a “material weakness” in our internal
control over financial reporting continues to exist. In the process of
finalizing the audit of our financial statements for the period ended December
31, 2006, management identified deficiencies in our internal control over
financial reporting with regard to our valuation of certain derivative
instruments and the completeness of production and property taxes which
constitute a material weakness. We did not maintain effective internal controls
over:
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·
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Valuation
of derivative instruments that BreitBurn Energy, our predecessor,
transferred to us on October 10, 2006, and instead valued the derivatives
as of October 1, 2006. Specifically, the failure to record those
transferred derivatives at the October 10
th
fair value resulted in an understatement of the derivatives receivable
contributed to us and an overstatement of the unrealized gain on
derivative instruments during the period from October 10 to December
31,
2006 due to the decrease in commodity prices that occurred between
October
1 and October 10, 2006.
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|
·
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The
completeness of production and property taxes relating to the properties
transferred to us on October 10, 2006. Specifically, the failure
to record
these taxes resulted in an understatement of the “accounts payable -
affiliates” assumed by us and an understatement of operating costs during
the period from October 10 to December 31,
2006.
|
These
control deficiencies resulted in audit adjustments to our consolidated financial
statements as of and for the period ended December 31, 2006.
To
address the material weakness in our internal control over financial reporting
and prevent any similar event from occurring, management designed a remediation
plan to enhance the process in place
for
management’s review of the preliminary draft financials and variance analyses.
We previously had utilized a process involving a detailed primary review of
the
preliminary financials that was followed by a high level secondary review.
The
secondary review ensures all actions from the primary review were effectively
addressed before the financials are finalized. In the second quarter of 2007,
management conducted both the primary and secondary review at the same detailed
level of review to provide a more rigorous variance analysis of financial
statement account fluctuations. In addition, accounting errors identified in
the
primary review were documented and evidence of correction of those items was
confirmed during the secondary review prior to the issuance of the final
financial statements. Additional technical financial resources are being added
to conduct the secondary review and more experienced accounting staff was added
to ensure that material misstatements do not occur in the future.
Before
concluding that the material weakness has been remediated, the new internal
controls should be implemented and remain operational for a sufficient period
of
time to demonstrate that the controls are operating effectively.
Changes
in Internal Control Over Financial Reporting
Other
than as discussed above, there were no changes in our internal control over
financial reporting that occurred during the period ended June 30, 2007 that
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting.
PART
II. OTHER INFORMATION
Item
1.
Legal Proceedings.
None.
Item
1A.
Risk
Factors.
There
have been no material changes to the Risk Factors disclosed in our 2006 Annual
Report on Form 10-K.
Item
2.
Unregistered Sales of Equity Securities and Use of
Proceeds.
Unregistered
Sales of Equity Securities
The
information required by this item is included in our Current Reports on Form
8-K
dated May 29, 2007 and May 31, 2007.
Item 3.
Defaults
Upon Senior Securities.
None.
Item 4.
Submission
of Matters to a Vote of Security Holders.
None.