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BreitBurn Energy Partners, L.P. 10-K 2009 Documents found in this filing:
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
For the fiscal year ended December 31,
2008
or
For
the transition period from ___ to ___
Commission
File Number 001-33055
BreitBurn
Energy Partners L.P.
(Exact
name of registrant as specified in its charter)
Registrant’s
telephone number, including area code: (213) 225-5900
Securities
registered pursuant to Section 12(b) of the Act:
Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes o No þ
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Exchange
Act. Yes o No þ
Indicate
by check mark whether registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes þ No o
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the
best of registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. þ
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer, or a smaller reporting company. See
the definitions of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act. (check
one):
Indicate
by check-mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes o No þ
As of
February 27, 2009, there were 52,770,011 Common Units
outstanding. The aggregate market value of the Common Units held by
non-affiliates of the registrant (98.69 percent) was approximately
$1,124,000,000 for the Common Units on June 30, 2008 based on
$21.63 per unit, the last reported sales price of the Common Units on the
Nasdaq Global Select Market on such date. The calculation of the aggregate
market value of the Common Units held by non-affiliates of the registrant is
based on an assumption that Quicksilver Resources Inc., which owns 21,347,972
Common Units, representing 40.56 percent of the outstanding Common Units, is a
non-affiliate of the registrant.
Documents
Incorporated By Reference:
Portions
of our definitive Proxy Statement for our 2009 Annual Meeting of Unitholders are
hereby incorporated by reference into Part III hereof.
BreitBurn
Energy Partners L.P. and Subsidiaries
The
following is a description of the meanings of some of the oil and gas industry
terms that may be used in this report. The definitions of proved
developed reserves, proved reserves and proved undeveloped reserves have been
abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4)
of Regulation S-X.
API gravity
scale: a gravity scale devised by the American Petroleum
Institute.
Bbl:> One
stock tank barrel, or 42 U.S. gallons of liquid volume, of crude oil or other
liquid hydrocarbons.
Bbl/d: Bbl
per day.
Bcf: One
billion cubic feet
Boe/d: Boe
per day.
gross
acres or gross
wells:> The total acres or wells, as the case may be, in which
a working interest is owned.
MBbls: One
thousand barrels of crude oil or other liquid hydrocarbons.
MBoe: One
thousand barrels of oil equivalent.
MBoe/d: One
thousand barrels of oil equivalent per day.
Mcf: One
thousand cubic feet of natural gas.
Mcf/d: One
thousand cubic feet of natural gas per day.
MMBbls: One
million barrels of crude oil or other liquid hydrocarbons.
MMBoe: One
million barrels of oil equivalent.
MMBtu: One
million British thermal units.
MMBtu/d: One
million British thermal units per day.
MMcf: One
million cubic feet of natural gas.
net acres
or net
wells:> The sum of the fractional working interests owned in
gross acres or gross wells, as the case may be.
NYMEX: New
York Mercantile Exchange.
oil: Crude
oil, condensate and natural gas liquids.
References
in this filing to “the Partnership,” “we,” “our,” “us” or like terms refer to
BreitBurn Energy Partners L.P. and its subsidiaries. References in this filing
to “BEC” or the “Predecessor” refer to BreitBurn Energy Company L.P., our
predecessor, and its predecessors and subsidiaries. References in this filing to
“BreitBurn GP” or the “General Partner” refer to BreitBurn GP, LLC, our general
partner and our wholly owned subsidiary as of June 17, 2008. References in this
filing to “Provident” refer to Provident Energy Trust. References in this filing
to “Pro GP” refer to Pro GP Corp., BEC’s former general partner up to August 26,
2008 and indirect subsidiary of Provident. References in this filing to “Pro LP”
refer to Pro LP Corp., BEC’s former limited partner and indirect subsidiary of
Provident. References in this filing to “BreitBurn Corporation” refer to
BreitBurn Energy Corporation, a corporation owned by Randall Breitenbach and
Halbert Washburn, the co-Chief Executive Officers of our general partner.
References in this filing to “BreitBurn Management” refer to BreitBurn
Management Company, LLC, our asset manager and operator, and wholly owned
subsidiary as of June 17, 2008. References in this filing to “BOLP” or
“BreitBurn Operating” refer to BreitBurn Operating L.P., our wholly owned
operating subsidiary. References in this filing to “BOGP” refer to BreitBurn
Operating GP, LLC, the general partner of BOLP. References in this filing to
“our properties” refer to, as of December 31, 2006, the oil and gas properties
contributed to us and our subsidiaries by BEC in connection with our initial
public offering. These oil and gas properties include certain fields in the Los
Angeles Basin in California, including interests in the Santa Fe Springs,
Rosecrans and Brea Olinda Fields, and the Wind River and Big Horn Basins in
central Wyoming. As of January 1, 2007, “our properties” include any additional
properties that we have acquired since that date. References to “Quicksilver” or
“QRI” refer to Quicksilver Resources Inc. from whom we acquired oil and gas
properties and facilities in Michigan, Indiana and Kentucky on November 1, 2007.
References in this filing to “BEPI” refer to BreitBurn Energy Partners I, L.P.
References in this filing to “TIFD” refer to TIFD X-III LLC, from whom we
acquired a 99 percent limited partner interest in BEPI on May 25, 2007, which
owned interests in the Sawtelle and East Coyote oil fields located in
California.
_____________________________________ Forward-looking
statements are included in this report and may be included in other public
filings, press releases, our website and oral and written presentations by
management. Statements other than historical facts are forward- looking and may
be identified by words such as “expects,” “anticipates,” “intends,” “plans,”
“believes,” “estimates,” “forecasts,” “could,” “will,” “recommends” and words of
similar meaning. These statements are not guarantees of future performance and
are subject to certain risks, uncertainties and other factors, some of which are
beyond our control and are difficult to predict. Therefore, actual outcomes and
results may differ materially from what is expressed or forecasted in such
forward-looking statements. The reader should not place undue reliance on these
forward-looking statements, which speak only as of the date of this report.
Examples of these types of statements include those regarding:
Although
these statements are based upon our current expectations and beliefs, they are
subject to known and unknown risks and uncertainties that could cause actual
results and outcomes to differ materially from those described in, or implied
by, the forward-looking statements. In that event, our business, financial
condition, results of operations or liquidity could be materially adversely
affected and investors in our securities could lose part or all of their
investments. These risks and uncertainties include, among other things, the
following:
If one or
more of these risks or uncertainties materialize or if underlying assumptions
prove incorrect, our actual results may vary materially from those anticipated,
estimated, projected or expected. When considering these forward-looking
statements, you should keep in mind the risk factors and other cautionary
statements in this report, including those described in Part I—Item 1A
“—Risk Factors’’ in this report. The risk factors and other factors noted in
this report could cause our actual results to differ materially from those
contained in any forward-looking statement.
All
forward-looking statements, expressed or implied, included in this report and
attributable to us are expressly qualified in their entirety by this cautionary
statement. This cautionary statement should also be considered in connection
with any subsequent written or oral forward-looking statements that we or
persons acting on our behalf may issue.
We
undertake no obligation to update the forward-looking statements in this report
to reflect future events or circumstances. All such statements are expressly
qualified by this cautionary statement. Overview
We are an
independent oil and gas partnership focused on the acquisition, exploitation and
development of oil and gas properties in the United States. 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 and natural
gas reserves located in the Antrim Shale in Michigan, the Los Angeles Basin in
California, the Wind River and Big Horn Basins in central Wyoming, the Sunniland
Trend in Florida, the New Albany Shale in Indiana and Kentucky, and the Permian
Basin in West Texas.
Our
assets are characterized by stable, long-lived production and reserve life
indexes averaging greater than 16 years. Our fields generally have long
production histories, with some fields producing for over 100 years. We have
high net revenue interests in our properties.
We are a
Delaware limited partnership formed on March 23, 2006. Our general
partner is BreitBurn GP, a Delaware limited liability company, also formed on
March 23, 2006, and our wholly owned subsidiary since June 17,
2008. 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 7 to
the consolidated financial statements in this report for information regarding
our relationship with BreitBurn Management.
In connection with our initial public
offering in October 2006, BEC contributed to us certain properties, which
include fields in the Los Angeles Basin in California and the Wind River and Big
Horn Basins in central Wyoming. In 2007, we acquired the Lazy JL
Field in Texas, five fields in Florida’s Sunniland Trend, a limited partnership
interest in a partnership that owns the East Coyote and Sawtelle fields in the
Los Angeles Basin in California, and natural gas, oil and midstream assets in
Michigan, Indiana and Kentucky, including fields in the Antrim Shale in Michigan
and New Albany Shale in Indiana and Kentucky, transmission and gathering
pipelines, three gas processing plants and four NGL recovery
plants.
As of
December 31, 2008, our total estimated proved reserves were 103.6 MMBoe, of
which approximately 75 percent were natural gas and 25 percent were crude
oil. Of our total estimated proved reserves, 78 percent were located
in Michigan, 12 percent in California and 6 percent in Wyoming, with the
remaining 4 percent in Florida, Texas, Indiana and Kentucky. As of December 31,
2008, the total standardized measure of discounted future net cash flows was
$592 million.
Available
Information
Our
internet website address is www.breitburn.com. We make available,
free of charge at the “Investor Relations” portion of our website, our annual
report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K
and all amendments to those reports filed or furnished pursuant to Section 13(a)
or 15(d) of the Securities Exchange Acts of 1934, as amended, as soon
as reasonably practicable after such reports are electronically filed
with, or furnished to, the Securities and Exchange Commission
(“SEC”). The information contained on our website does not constitute
part of this report. Long
Term Business Strategy
Our goal
is to provide stability and growth in cash distributions to our
unitholders. In order to meet this objective, we plan to continue to
follow our core investment strategy, which includes the following
principles:
2009
Operating Focus
We
completed a series of significant oil and gas acquisitions during
2007. During 2008, our principal operating focus was the development
and integration of those acquired assets. In light of the current
market environment for oil and natural gas prices and the state of the financial
and capital markets, we expect 2009 to be a year of increased internal focus and
decreased acquisition activity. However, as the commodity and
financial markets eventually stabilize, we intend to increase our focus on
acquisition opportunities consistent with our core long-term
strategy.
Our goals
in 2009 are to fund our operations, capital expenditures, interest payments and
distributions to unitholders from our internally generated cash flow and to
preserve financial flexibility and liquidity to maintain our assets and
operations in anticipation of future improvement in the overall economic
environment, commodity prices and the financial markets.
In
response to the rapid and substantial decline in oil and natural gas prices, the
outlook for the broader economy and the ongoing turmoil in the financial
markets, and consistent with our goals for 2009, we have elected to
significantly reduce our capital expenditures and drilling activity in
2009. Our capital program is expected to be approximately $20 million
in 2009, compared to approximately $129 million in 2008.
Because of the reduced capital program
in 2009 and the natural decline in our production rates, we expect to produce
less oil and natural gas in 2009 than we did in 2008. If oil and natural
gas prices improve, or if operating and development costs decline, and we elect
to increase the scope of our capital program based on these or other factors, we
would expect an increase in our anticipated 2009 production rate and aggregate
volumes.
In light
of the market environment and our reduced capital program, we are focused on
substantially reducing operating and general and administrative costs in
2009. Our focus on reducing costs has included, but is not limited
to, a realignment of certain divisional operating roles to consolidate
responsibilities, negotiated reductions in fees and expenses from third party
service providers, as well as planned personnel reductions in both operations
and administrative functions.
Hedging
remains an important part of our strategy to reduce cash flow volatility. We use
swaps, collars and options for managing risk relating to commodity prices. As of
February 27, 2009, we have hedged (including physical hedges) approximately 84
percent of our 2009 expected production. In 2009, we have 47,542
MMBtu/d of natural gas and 5,778 Bbls/d of oil hedged at average prices of
approximately $8.17 and $73.12, respectively. In 2010, we have 47,275
MMBtu/d of natural gas and 6,080 Bbls/d of oil hedged at average prices of
approximately $8.26 and $82.52, respectively. In 2011, we have 41,971
MMBtu/d of natural gas and 5,603 Bbls/d of oil hedged at average prices of
approximately $8.62 and $77.60, respectively. In 2012, we have 38,257
MMBtu/d of natural gas and 5,016 Bbls/d of oil hedged at average prices of
approximately $8.93and $91.95, respectively. Ownership
and Structure
In 2006,
we completed our initial public offering of 6,000,000 common units representing
limited partner interests in us (“Common Units”) and completed the sale of an
additional 900,000 Common Units to cover over-allotments in the initial public
offering at $18.50 per unit, or $17.205 per unit after payment of the
underwriting discount. In connection with our initial public offering, BEC, our
Predecessor, contributed to us certain fields in the Los Angeles Basin in
California, including its interests in the Santa Fe Springs, Rosecrans and Brea
Olinda Fields, and the Wind River and Big Horn Basins in central
Wyoming.
On May
24, 2007, we sold 4,062,500 Common Units in a private placement at $32.00 per
unit, resulting in proceeds of approximately $130 million. The net
proceeds of this private placement were used to acquire certain interests in oil
leases and related assets from Calumet Florida L.L.C. and to reduce
indebtedness under our credit facility.
On May
25, 2007, we sold 2,967,744 Common Units in a private placement at $31.00 per
unit, resulting in proceeds of approximately $92 million. The net
proceeds of this private placement were partially used to acquire a 99 percent
limited partner interest in BEPI from TIFD and to terminate existing hedges
related to future production from BEPI.
On
November 1, 2007, we sold 16,666,667 Common Units in a third private placement
at $27.00 per unit, resulting in proceeds of approximately $450
million. The net proceeds from this private placement were used to
fund a portion of the cash consideration for the acquisition of certain assets
and equity interests in certain entities from Quicksilver (the “Quicksilver
Acquisition”). Also on November 1, 2007, we issued 21,347,972 Common Units to
Quicksilver as partial consideration for the Quicksilver
Acquisition.
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 (the “Common
Unit Purchase”). These units have been cancelled and are no longer
outstanding.
On June
17, 2008, we also purchased Provident’s 95.55 percent limited liability company
interest in BreitBurn Management, which owned the General Partner, for a
purchase price of approximately $10 million (the “BreitBurn Management
Purchase”). See Note 4 to the consolidated financial statements in
this report for the purchase price allocation for this
transaction. Also on June 17, 2008, we entered into a contribution
agreement (the “Contribution Agreement”) with the General Partner, BreitBurn
Management and BreitBurn Corporation, which is wholly owned by the Co-Chief
Executive Officers of the General Partner, Halbert S. Washburn and Randall H.
Breitenbach, 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, the economic value of which was equivalent to
the value of their combined 4.45 percent interest in BreitBurn Management, 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
and our limited partners holding Common Units were given a right to nominate and
vote in the election of directors to the Board of Directors of the General
Partner. As a result of these transactions (collectively, the
“Purchase, Contribution and Partnership Transactions”), the General Partner and
BreitBurn Management became our wholly owned subsidiaries.
On June
17, 2008, in connection with the Purchase, Contribution and Partnership
Transactions, we and our wholly owned subsidiaries entered into the First
Amendment to Amended and Restated Credit Agreement, Limited Waiver and Consent
and First Amendment to Security Agreement (“Amendment No. 1 to the Credit
Agreement”), with Wells Fargo Bank, National Association, as administrative
agent. Amendment No. 1 to the Credit Agreement increased the borrowing base
available under the Amended and Restated Credit Agreement dated November 1, 2007
from $750 million to $900 million. We used borrowings under Amendment
No. 1 to the Credit Agreement to finance the Common Unit Purchase and the
BreitBurn Management Purchase.
On June
17, 2008, in connection with the Purchase, Contribution and Partnership
Transactions, the Omnibus Agreement, dated October 10, 2006, among us, the
General Partner, Provident, Pro GP and BEC was terminated in all
respects.
The following diagram depicts our
organizational structure as of December 31, 2008:
On February 19, 2009, 134,377 Common
Units were issued to employees under our 2006 Long-Term Incentive Plan,
increasing our outstanding Common Units to 52,770,011.
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 of 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.
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.
As of
December 31, 2008, the public unitholders, the institutional investors in our
private placements and Quicksilver owned 98.69 percent of the outstanding Common
Units. BEC owned 690,751 Common Units, representing a 1.31 percent limited
partner interest. We own 100 percent of the General Partner, BreitBurn
Management and BOLP.
Our
Predecessor BEC, was a 96.02 percent owned indirect subsidiary of Provident
until August 26, 2008, when 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 of BEC, our Predecessor. This
transaction included the acquisition of a 96.02 percent indirect interest in
BEC, previously owned by Provident, and the remaining indirect interests in BEC,
previously owned by Randall H. Breitenbach, Halbert S. Washburn and
other members of the our senior management. BEC was a separate U.S.
subsidiary of Provident and was our Predecessor.
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 a five-year Administrative Services Agreement to manage BEC's properties.
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.
Operations
Properties
BreitBurn
Management manages all of our properties. BreitBurn Management
employs production and reservoir engineers, geologists and other specialists, as
well as field personnel. On a net production basis, we operate
approximately 82 percent of our production. As operator, we design
and manage the development of wells and supervise operation and maintenance
activities on a day-to-day basis. We do not own drilling rigs or
other oilfield services equipment used for drilling or maintaining wells on
properties we operate. Independent contractors engaged by us provide
all the equipment and personnel associated with these activities.
In October 2006, certain properties,
which include fields in the Los Angeles Basin in California and the Wind River
and Big Horn Basins in central Wyoming, were contributed to us by our
Predecessor. In 2007, we acquired the Lazy JL Field in Texas, five
fields in Florida’s Sunniland Trend, a limited partnership interest in a
partnership that owns the East Coyote and Sawtelle fields in the Los Angeles
Basin in California, and natural gas, oil and midstream assets in Michigan,
Indiana and Kentucky, including fields in the Antrim Shale in Michigan and New
Albany Shale in Indiana and Kentucky, transmission and gathering pipelines,
three gas processing plants and four NGL recovery plants.
As of
December 31, 2008, our total estimated proved reserves were 103.6 MMBoe, of
which approximately 75 percent were natural gas and 25 percent were crude
oil. As of December 31, 2007, our total estimated proved reserves
were 142.2 MMBoe, of which approximately 59 percent were natural gas and 41
percent were crude oil. The decrease in reserves was primarily due to lower
commodity prices at the end of 2008 ($45 per Bbl for oil and $5.62 per Mcf for
natural gas) compared to prices at the end of 2007 ($96 per Bbl for oil and
$7.48 per Mcf for natural gas). During 2008, we added proved reserves
totalling 8.2 MMBoe from additions. This equates to 121 percent of our
production for 2008. The reserve additions were offset by negative economic and
technical revisions of 40.5 MMBoe.
Of our
total estimated proved reserves as of December 31, 2008, 78 percent were located
in Michigan, 12 percent in California and 6 percent in Wyoming, with the
remaining 4 percent in Florida, Texas, Indiana and Kentucky. As of December 31,
2008, the total standardized measure of discounted future net cash flows was
$592 million. During 2008, we filed estimates of oil and gas reserves as of
December 31, 2007 with the U.S. Department of Energy, which were consistent with
the reserve data reported for the year ended December 31, 2007 in Note 22 to the
consolidated financial statements in this report. The
following table summarizes estimated proved reserves and production for our
properties within our operating regions:
Uncertainties
are inherent in estimating quantities of proved reserves, including many factors
beyond our control. Reserve engineering is a subjective process of estimating
subsurface accumulations of oil and gas that cannot be measured in an exact
manner, and the accuracy of any reserve estimate is a function of the quality of
available data and its interpretation. As a result, estimates by
different engineers often vary, sometimes significantly. In addition,
physical factors such as the results of drilling, testing and production
subsequent to the date of an estimate, as well as economic factors such as
change in product prices or development and production expenses, may require
revision of such estimates. Accordingly, oil and gas quantities ultimately
recovered will vary from reserve estimates. See Part I—Item 1A “—Risk
Factors” in this report, for a description of some of the risks and
uncertainties associated with our business and reserves.
The information in this
report relating to our estimated oil and gas proved reserves is based upon
reserve reports prepared as of December 31, 2008. Estimates of our
proved reserves were prepared by Netherland, Sewell & Associates, Inc. and
Schlumberger Data & Consulting Services, independent petroleum engineering
firms. The reserve estimates are reviewed and approved by
senior engineering staff and management. The process performed
by Netherland, Sewell & Associates, Inc. and Schlumberger Data
& Consulting Services
to prepare reserve amounts included their estimation of reserve quantities,
future producing rates, future net revenue and the present value of such future
net revenue. Netherland, Sewell & Associates, Inc. and
Schlumberger Data & Consulting Services
also prepared estimates with respect to reserve categorization, using the
definitions for proved reserves set forth in Regulation S-X
Rule 4-10(a) and subsequent SEC staff interpretations and
guidance. In the conduct of their preparation of the reserve
estimates, Netherland, Sewell & Associates, Inc. and Schlumberger Data &
Consulting Services
did not independently verify the accuracy and completeness of information and
data furnished by us with respect to ownership interests, oil and gas
production, well test data, historical costs of operation and development,
product prices or any agreements relating to current and future operations of
the properties and sales of production. However, if in the course of
their work, something came to their attention which brought into question the
validity or sufficiency of any such information or data, they did not rely on
such information or data until they had satisfactorily resolved their questions
relating thereto.
Michigan
As of
December 31, 2008, our Michigan operations comprised approximately 78 percent of
our total estimated proved reserves. For the year ended December 31, 2008, our
average production was approximately 10.7 MBoe/d or 64 MMcfe/d. Estimated proved
reserves attributable to our Michigan properties as of December 21, 2008 were
80.9 MMBoe. Our integrated midstream assets enhance the value of our
Michigan properties as gas is sold at MichCon prices, and we have no significant
reliance on third party transportation. We have interests in 3,341
productive wells in Michigan.
During
August of 2008, we reached a peak of 6 drilling rigs running in Michigan. We
drilled a total of 116 wells in 2008 and had 106 approved drilling permits and
13 change of well status approvals for the Antrim re-entry program as of
December 31, 2008. In addition to drilling, capital was spent to
complete ten line twining projects and over 55 compression units were employed.
These projects targeted casing pressure reduction in the pressure sensitive
Antrim Shale. Line twining converts a single line gathering system, where
natural gas and water are transported from the well to the central processing
facility in one line, to a dual line system where the water and gas each have
their own line to the central processing facility. As a result, the casing
pressure at the well can be lowered thus increasing production. Our capital
spending in Michigan for the year ended December 31, 2008 was $81
million.
Antrim
Shale
The
Antrim Shale underlies a large percentage of our Michigan acreage; wells tend to
produce relatively predictable amounts of natural gas in this reservoir. Over
9,000 wells have been drilled by various companies with greater than 95 percent
drilling success over its history. On average, Antrim Shale wells have a proved
reserve life of more than 20 years. Since reserve quantities and production
levels over a large number of wells are fairly predictable, maximizing per well
recoveries and minimizing per unit production costs through a sizeable
well-engineered drilling program are the keys to profitable Antrim development.
Significant growth opportunities include infill drilling and recompletions,
horizontal drilling and bolt-on acquisitions. Our estimated proved reserves
attributable to our Antrim Shale interests as of December 31, 2008 were
72.1 MMBoe or 433 Bcfe, of which 93 percent was proved developed.
In 2008,
we drilled 90 productive development wells in the Antrim Shale, employing a
combination of vertical, high angle directional, horizontal and re-entry
horizontal techniques. We drilled no dry wells in the Antrim Shale in
2008.
Non-Antrim
Fields
Our
non-Antrim interests are located in several reservoirs including the Prairie du
Chien (“PRDC”), Richfield (“RCFD”), Detroit River Zone III (“DRRV”) and
Niagaran (“NGRN”) pinnacle reefs. Our estimated proved reserves attributable to
our non-Antrim interests as of December 31, 2008 were 8.8 MMBoe or 52.6
Bcfe.
The PRDC
will produce dry gas, gas and condensate or oil with associated gas, depending
upon the area and the particular zone. Our PRDC production is well established,
and there are numerous proved non-producing zones in existing well bores that
provide recompletion opportunities, allowing us to maintain or, in some cases,
increase production from our PRDC wells as currently producing reservoirs
deplete.
The vast
majority of our RCFD/DRRV wells are located in Kalkaska and Crawford counties in
the Garfield and Beaver Creek fields. Potential exploitation of the Garfield
RCFD/DRRV reservoirs either by secondary waterflood and/or improved oil recovery
with CO2 injection
is under evaluation; however, because this concept has not been proved, there
are no recorded reserves related to these techniques. Production from the Beaver
Creek RCFD/DRRV reservoirs consists of oil with associated natural gas. In the
fall of 2008, we received permission from the Michigan Department of
Environmental Quality to co-mingle the RCFD and DRRV formations in the Garfield
project. This co-mingling will enable us to add the DRRV formation to existing
and future RCFD wells at minimal cost as opposed to drilling a separate well for
the DRRV.
Our NGRN
wells produce from numerous Silurian-age Niagaran pinnacle reefs located in the
northern part of the lower peninsula of Michigan. Depending upon the location of
the specific reef in the pinnacle reef belt of the northern shelf area, the NGRN
pinnacle reefs will produce dry natural gas, natural gas and condensate or oil
with associated natural gas.
In 2008,
we drilled 25 productive development wells and one salt-water disposal well in
the non-Antrim fields. Of the 25 development wells, three were in PRDC, 14 were
in RCFD and eight were in DRRV. We drilled one dry development well in the
non-Antrim fields in 2008.
California
Los
Angeles Basin, California
Our
operations in California are concentrated in several large, complex oil fields
within the Los Angeles Basin. For the year ended December 31, 2008, our
California average production was approximately 3.2 MBoe/d. Estimated proved
reserves attributable to our California properties as of December 31, 2008 were
12.4 MMBoe. Our four largest fields, Santa Fe Springs, East Coyote, Rosecrans
and Sawtelle, made up 89 percent of our production in 2008 and 87 percent of our
estimated proved reserves in California as of December 31, 2008. In 2008, we
drilled four productive development wells and no dry development wells in
California. Our capital spending in California for the year ended December 31,
2008 was $20 million.
Santa Fe Springs Field – Our
largest property in the Los Angeles Basin, measured by estimated proved
reserves, is the Santa Fe Springs Field. We operate 161 active wells in the
Santa Fe Springs Field and own a 99.5 percent working interest. Santa Fe Springs
has produced to date from up to 10 productive sands ranging in depth from 3,000
feet to more than 9,000 feet. The five largest producing zones are the Bell,
Meyer, O'Connell, Clark and Hathaway. In 2008, our average production from the
Santa Fe Springs Field was approximately 1.6 MBoe/d and our estimated proved
reserves as of December 31, 2008 were 4.8 MMBoe, of which 93 percent was proved
developed.
East Coyote Field – Our
interest in this field was acquired on May 25, 2007. BEC operates 69 active
wells in the East Coyote Field. We own a 95 percent working interest. The East
Coyote Field has producing zones ranging in depth from 2,500 feet to 4,000 feet.
Our average production from the East Coyote Field for the year ended December
31, 2008 was approximately 532 Boe/d and our estimated proved reserves as of
December 31, 2008 were 3.3 MMBoe.
Sawtelle Field – Our interest
in this field was acquired on May 25, 2007. BEC operates 14 active wells in the
Sawtelle Field. We own a 93 percent working interest. The Sawtelle Field has
produced from several productive sands ranging in depth from 9,000 feet to
10,500 feet. Our average production from the Sawtelle Field was approximately
343 Boe/d and our estimated proved reserves as of December 31, 2008 were 1.6
MMBoe.
Rosecrans Field – We operate
46 active wells in the Rosecrans Field and own a 100 percent working interest.
The Rosecrans Field has produced from several productive sands ranging in depth
from 4,000 feet to 8,000 feet. The producing zones are the Padelford, Maxwell,
Hoge, Zins and the O’dea. In 2008, our average production from the Rosecrans
Field was approximately 355 Boe/d and our estimated proved reserves as of
December 31, 2008 were 1.1 MMBoe.
Other California Fields – Our
other fields include the Brea Olinda field, which has 75 active wells producing
approximately 207 net Boe/d on average in 2008 and estimated proved reserves as
of December 31, 2008 of 0.8 MMBoe; the Alamitos lease of the Seal Beach Field,
which has ten active wells producing approximately 93 net Boe/d on average in
2008 from the McGrath and Wasem formations at approximately 7,000 feet; and the
Recreation Park lease of the Long Beach Field, which has seven active wells
producing approximately 48 net Boe/d on average in 2008 from the same zones as
the Alamitos lease, but approximately 1,000 feet deeper and estimated proved
reserves as of December 31, 2008 of 0.8 MMBoe. We have a 100 percent working
interest in Brea Olinda and Alamitos and a 60 percent working interest in
Recreation Park. Wyoming
Wind
River and Big Horn Basins, Wyoming
For the
year ended December 31, 2008, our average production from our Wyoming fields was
approximately 2.2 MBoe/d and estimated proved reserves at December 31, 2008
totaled 6.2 MMBoe. Four fields, Black Mountain, Gebo, North Sunshine
and Hidden Dome, made up 83 percent of our 2008 production and 94 percent of our
2008 estimated proved reserves in Wyoming.
In 2008,
we drilled six new productive development wells, three successful developmental
deepenings of existing wells and one dry development well in Wyoming. The dry
development well was drilled in the West Oregon Basin Field. A total
of ten new wells and deepenings of existing wells were drilled in Wyoming during
2008. Additionally, a total of 19 workovers and recompletions, resulting in an
incremental 680 Boe/d of production, were performed in Wyoming during
2008. Our capital spending in Wyoming for the year ended December 31,
2008 was $11 million.
Black Mountain Field – We
operate 50 active wells in the Black Mountain Field and hold a 98 percent
working interest. Production is from the Tensleep formation with
producing zones as shallow as 2,500 feet and as deep as 3,900
feet. Our average production from the Black Mountain Field was
approximately 471 Boe/d in 2008 and our estimated proved reserves as of
December 31, 2008 were 3.3 MMBoe, of which 79 percent was proved
developed.
Gebo Field – We operate 51
active wells in the Gebo Field and hold a 100 percent working
interest. Production is from the Phosphoria and Tensleep formations
with producing zones as shallow as 4,500 feet and as deep as 5,300
feet. In 2008, our average production from the Gebo Field was
approximately 670 Boe/d and our estimated proved reserves as of
December 31, 2008 were 1.0 MMBoe.
North Sunshine Field – We
operate 32 active wells in the North Sunshine Field and hold a 100 percent
working interest. Production is from the Phosphoria at 3,000 feet and
the Tensleep at about 3,900 feet. In 2008, our average production
from the North Sunshine Field was approximately 376 Boe/d and our estimated
proved reserves as of December 31, 2008 were 0.6 MMBoe, of which 100
percent was proved developed. In 2008, we drilled three successful
crude oil wells in this field.
Hidden Dome Field – We
operate 25 active wells in the Hidden Dome Field and hold a 100 percent working
interest. Production is from the Frontier, Tensleep and Darwin
formations with the producing zones as shallow as 1,200 feet and as deep as
5,000 feet. In 2008, our average production from the Hidden Dome
Field was approximately 297 Boe/d and our estimated proved reserves as of
December 31, 2008 were 0.9 MMBoe.
Other Wyoming Fields – Our
other fields include the Sheldon Dome Field and Rolff Lake Fields in Fremont
County, where we operate 17 active oil wells and four active gas wells in the
Frontier to the Tensleep formations at depths up to 7,300 feet. In
2008, our Sheldon Dome and Rolff Lake fields produced on average approximately
133 net Boe/d and 73 net Boe/d, respectively. We also operate six
active wells in the Lost Dome Field in Natrona County (outside the Wind River
and Big Horn Basin) producing from the Tensleep formation at approximately 5,000
feet. In 2008, our average production from the Lost Dome Field was
approximately 60 Boe/d. The other two fields we operate are the West
Oregon Basin and Half Moon Fields in Park County, with seven total wells with
six active oil producing wells and one active natural gas producing
well. In 2008, we produced on average approximately 99 net Boe/d
between the two fields in Park County from the Frontier and Phosphoria
formations at depths from 1,200 to 4,000 feet. Rolff Lake Fields and Lost Dome
Field had estimated proved reserves as of December 31, 2008 of 0.3 MMBoe
and 0.1 MMBoe, respectively. We hold a 90 percent working interest in
the Sheldon Dome Field and 100 percent working interests in the Rolff Lake, West
Oregon Basin and Half Moon fields.
Florida
Our five
Florida fields were acquired in May 2007. We operate 18 active wells. Production
is from the Cretaceous Sunniland Trend of the South Florida Basin at 11,500
feet. The South Florida Basin is one of the largest proven and sourced
geological basins in the United States. The Sunniland Trend has produced in
excess of 115 million barrels of oil from seven fields. Our fields are 100
percent oil and oil quality averaged 24 degrees API. As of December 31, 2008, we
had estimated proved reserves of approximately 2.0 MMBbls and a reserve life
index in excess of 15 years in these fields. In 2008, our average production
from our Florida fields was approximately 1.6 MBbls/d. Production from the
Raccoon Point field currently accounts for more than half of our Florida
production. We hold a 100 percent working interest in our Florida
fields.
In 2008,
no wells were drilled in Florida, but three permits were secured from the State
of Florida. Our capital spending in Florida for the year ended December 31, 2008
was $11 million.
Texas
The Lazy
JL Field was acquired in January 2007. The field has 50 active wells with a 100
percent working interest. Production at the Lazy JL Field comes from two zones
in the lower Spraberry formation. In 2008, our average production
from the field was approximately 219 Boe/d. The field is 97 percent oil and oil
quality averaged 38 degrees API. In the Lazy JL Field, our interest in estimated
proved reserves as of December 31, 2008 were approximately 1.2 MMBoe and the
field had a reserve life index of 13 years. We also have an overriding royalty
interest of one well in an additional field in Texas, which added average
production of 4 Boe/d in 2008. Our capital spending in Texas for the
year ended December 31, 2008 was $3 million.
Indiana/Kentucky
We
acquired our operations in the New Albany Shale of southern Indiana and northern
Kentucky in November 2007. Our operations include 21 miles of high pressure gas
pipeline that interconnects with the Texas Gas Transmission interstate pipeline.
There are significant acreage leasing opportunities adjacent to our
Indiana/Kentucky operations. The New Albany Shale has over 100 years of
production history.
We
operate 210 wells in Indiana and Kentucky and hold a 100 percent working
interest. In 2008, our production for our Indiana and Kentucky operations was
approximately 423 Boe/d and 190 Boe/d, respectively, or 2,538 Mcf/d and 1,138
Mcf/d, respectively. Our estimated proved reserves in Indiana and Kentucky as of
December 31, 2008 were 0.6 MMBoe and 0.3 MMBoe, respectively, or 3.8 Bcf
and 1.7 Bcf, respectively. Our capital spending in Indiana and Kentucky for the
year ended December 31, 2008 was $2 million.
Productive
Wells
The
following table sets forth information for our properties at December 31,
2008, relating to the productive wells in which we owned a working
interest. Productive wells consist of producing wells and wells
capable of production. Gross wells are the total number of productive
wells in which we have an interest, and net wells are the sum of our fractional
working interests owned in the gross wells.
Developed and Undeveloped
Acreage
The following table sets forth
information for our properties as of December 31, 2008 relating to our
leasehold acreage. Developed acres are acres spaced or assigned to
productive wells. Undeveloped acres are acres on which wells have not
been drilled or completed to a point that would permit the production of
commercial quantities of gas or oil, regardless of whether such acreage contains
proved reserves. A gross acre is an acre in which a working interest
is owned. The number of gross acres is the total number of acres in
which a working interest is owned. A net acre is deemed to exist when
the sum of the fractional ownership working interests in gross acres equals
one. The number of net acres is the sum of the fractional working
interests owned in gross acres expressed as whole numbers and fractions
thereof. Michigan acreage at December 31, 2008 has increased as
compared to reported acreage at December 31, 2007 due to a detailed review
during 2008 of the acreage data provided to us as part of the Quicksilver
acquisition.
The
following table lists the total number of net undeveloped acres as of December
31, 2008, the number of net acres expiring in 2009, 2010 and 2011, and, where
applicable, the number of net acres expiring that are subject to extension
options.
Drilling
Activity
Our
drilling activity and production optimization projects are on lower risk,
development properties. The following table sets forth information
for our properties with respect to wells completed during the years ended
December 31, 2008, 2007 and 2006. Productive wells are those
that produce commercial quantities of oil and gas, regardless of whether they
produce a reasonable rate of return. No exploratory wells were
drilled during the periods presented.
Of the 116 gross wells drilled in
Michigan during 2008, 44 were recompletion wells. Of the ten wells
drilled in Wyoming, three were recompletion wells. Of the four wells
drilled in California during 2008, two were recompletion wells. We
had no wells in progress as of December 31, 2008. The one well we
drilled in Texas during 2008 was a new well.
Delivery
Commitments
As of
December 31, 2008, we had no delivery commitments. Sales
Contracts
We have a
portfolio of crude oil and natural gas sales contracts with large, established
refiners and utilities. Because our products are commodity products sold
primarily on the basis of price and availability, we are not dependent upon one
purchaser or a small group of purchasers. During 2008, our largest
purchasers were ConocoPhillips in California and Michigan, which accounted for
25 percent of total net sales, Marathon Oil Company in Wyoming, which accounted
for 13 percent of total net sales, and Plains Marketing, L.P. in Florida, which
accounted for 9 percent of total net sales.
Crude
Oil and Natural Gas Prices
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. The WTI price of crude oil is a widely used benchmark in the
pricing of domestic and imported oil in the United States. The
relative value of crude oil is determined by two main factors: quality and
location. In the case of WTI pricing, the crude oil is light and
sweet, meaning that it has a higher specific gravity (lightness) measured in
degrees API (a scale devised by the American Petroleum Institute) and low sulfur
content, and is priced for delivery at Cushing, Oklahoma. In general,
higher quality crude oils (lighter and sweeter) with fewer transportation
requirements result in higher realized pricing for producers.
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 Texas
crude is of a higher quality than our Los Angeles or Wyoming crude oil and
trades at a minor discount to NYMEX crude oil prices. Our Florida
crude oil also trades at a significant discount to NYMEX primarily because of
its low gravity and other characteristics as well as its distance from a major
refining market.
In 2008,
the NYMEX WTI spot price averaged approximately $100 per barrel, compared with
about $72 a year earlier. Monthly average crude-oil prices fluctuated widely
during 2008, from a low of $41 per barrel for December to a high of $134 per
barrel for June. For the year ended December 31, 2008, the
average discount to NYMEX WTI for our California, Wyoming, Florida and Texas
crude oil was $5.15, $18.86, $14.45 and $1.63 per barrel,
respectively.
Our
Michigan properties have favorable natural gas supply/demand characteristics as
the state has been importing an increasing percentage of its natural
gas. We have entered into derivative contracts for approximately 80
percent of our current natural gas production. To the extent our production is
not hedged, we anticipate that this supply/demand situation will allow us to
sell our future natural gas production at a slight premium to industry benchmark
prices. Prices for natural gas have historically fluctuated widely
and in many regional markets are aligned with supply and demand conditions in
regional markets and with the overall U.S. market. Fluctuations in
the price for natural gas in the United States are closely associated with the
volumes produced in North America and the inventory in underground storage
relative to customer demand. U.S. natural gas prices are also typically higher
during the winter period when demand for heating is greatest. Since
January 2005, NYMEX monthly average futures price for natural gas at Henry Hub
ranged from a low of $5.22 per MMBtu for September 2006 to a high of $13.45 per
MMBtu for October 2005. During 2007, the average NYMEX wholesale natural gas
price ranged from a low of $6.14 per MMBtu for August to a high of $7.82 per
MMBtu for May. During 2008, the average NYMEX wholesale natural gas price ranged
from a low of $5.79 per MMBtu for December to a high of $12.78 per MMBtu for
June.
Our
operating expenses are sensitive to commodity prices. We experience pressure on
operating expenses that is highly correlated to commodity prices for specific
expenditures such as lease fuel, electricity, drilling services and severance
and property taxes. Derivative
Activity
Our
revenues and net income are sensitive to oil and natural gas prices, and our
operating expenses are highly correlated 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. Currently, we use a combination of fixed
price swap and option arrangements to economically hedge NYMEX crude oil and
natural gas prices. By removing the price volatility from a significant portion
of our crude oil and natural gas production, we have mitigated, but not
eliminated, the potential effects of changing crude oil and natural gas prices
on our cash flow from operations for those periods. 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. For a more
detailed discussion of our derivative activities, see Part II—Item 7
“—Management's Discussion and Analysis of Financial Condition and Results of
Operations—Overview,” Part II—Item 7A “—Quantitative and Qualitative Disclosures
About Market Risk” and Note 14 to the consolidated financial statements included
in this report.
Competition
The oil
and gas industry is highly competitive. We encounter strong competition from
other independent operators and from major oil companies in all aspects of our
business, including acquiring properties and oil and gas leases, marketing oil
and gas, contracting for drilling rigs and other equipment necessary for
drilling and completing wells and securing trained personnel. Many of these
competitors have financial and technical resources and staffs substantially
larger than ours. As a result, our competitors may be able to pay more for
desirable leases, or to evaluate, bid for and purchase a greater number of
properties or prospects than our financial or personnel resources
permit.
In
regards to the competition we face for drilling rigs and the availability of
related equipment, the oil and gas industry has experienced shortages of
drilling rigs, equipment, pipe and personnel in the past, which has delayed
development drilling and other exploitation activities and has caused
significant price increases. We are unable to predict when, or if, such
shortages may occur or how they would affect our development and exploitation
program. Competition is also strong for attractive oil and gas producing
properties, undeveloped leases and drilling rights, which may affect our ability
to compete satisfactorily when attempting to make further acquisitions. See Part
I—Item 1A “—Risk Factors” — “Risks Related to Our Business — We may be unable to
compete effectively with other companies, which may adversely affect our ability
to generate sufficient revenue to allow us to pay distributions to our
unitholders.” in this report.
Title
to Properties
As is
customary in the oil and gas industry, we initially conduct only a cursory
review of the title to our properties on which we do not have proved reserves.
Prior to the commencement of drilling operations on those properties, we conduct
a thorough title examination and perform curative work with respect to
significant defects. To the extent title opinions or other investigations
reflect title defects on those properties, we are typically responsible for
curing any title defects at our expense. We generally will not commence drilling
operations on a property until we have cured any material title defects on such
property. Prior to completing an acquisition of producing oil leases, we perform
title reviews on the most significant leases and, depending on the materiality
of properties, we may obtain a title opinion or review previously obtained title
opinions. As a result, we believe that we have satisfactory title to our
producing properties in accordance with standards generally accepted in the oil
and gas industry. Under our credit facility, we have granted the lenders a lien
on substantially all of our oil and gas properties. Our oil properties are also
subject to customary royalty and other interests, liens for current taxes and
other burdens which we believe do not materially interfere with the use of or
affect our carrying value of the properties.
Some of
our oil and gas leases, easements, rights-of-way, permits, licenses and
franchise ordinances require the consent of the current landowner to transfer
these rights, which in some instances is a governmental entity. We believe that
we have obtained sufficient third-party consents, permits and authorizations for
us to operate our business in all material respects. With respect to any
consents, permits or authorizations that have not been obtained, we believe that
the failure to obtain these consents, permits or authorizations have no material
adverse effect on the operation of our business.
Seasonal
Nature of Business
Seasonal
weather conditions, especially freezing conditions in Michigan, and lease
stipulations can limit our drilling activities and other operations in certain
of the areas in which we operate and, as a result, we seek to perform the
majority of our drilling during the summer months. These seasonal anomalies can
pose challenges for meeting our well drilling objectives and increase
competition for equipment, supplies and personnel during the spring and summer
months, which could lead to shortages and increase costs or delay our
operations.
Environmental Matters and
Regulation
General. Our operations are
subject to stringent and complex federal, state and local laws and regulations
governing environmental protection as well as the discharge of materials into
the environment. These laws and regulations may, among other
things:
These
laws, rules and regulations may also restrict the rate of oil and natural gas
production below the rate that would otherwise be possible. The regulatory
burden on the oil and gas industry increases the cost of doing business in the
industry and consequently affects profitability. Additionally, Congress and
federal and state agencies frequently revise environmental laws and regulations,
and the clear trend in environmental regulation is to place more restrictions
and limitations on activities that may affect the environment. Any changes that
result in more stringent and costly waste handling, disposal and cleanup
requirements for the oil and gas industry could have a significant impact on our
operating costs.
The
following is a summary of some of the existing laws, rules and regulations to
which our business operations are subject.
Waste Handling. The Resource
Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate
the generation, transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the federal
Environmental Protection Agency, or EPA, the individual states administer some
or all of the provisions of RCRA, sometimes in conjunction with their own, more
stringent requirements. Drilling fluids, produced waters, and most of the other
wastes associated with the exploration, development, and production of crude oil
or natural gas are currently regulated under RCRA’s non-hazardous waste
provisions. However, it is possible that certain oil and natural gas exploration
and production wastes now classified as non-hazardous could be classified as
hazardous wastes in the future. Any such change could result in an increase in
our costs to manage and dispose of wastes, which could have a material adverse
effect on our results of operations and financial position. Also, in the course
of our operations, we generate some amounts of ordinary industrial wastes, such
as paint wastes, waste solvents, and waste oils that may be regulated as
hazardous wastes.
Comprehensive Environmental
Response, Compensation and Liability Act. The Comprehensive Environmental
Response, Compensation and Liability Act, or CERCLA, also known as the Superfund
law, imposes joint and several liability, without regard to fault or legality of
conduct, on classes of persons who are considered to be responsible for the
release of a hazardous substance into the environment. These persons include the
current and past owner or operator of the site where the release occurred, and
anyone who disposed or arranged for the disposal of a hazardous substance
released at the site. Under CERCLA, such persons may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies. In addition, it is not uncommon for
neighboring landowners and other third-parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.
We
currently own, lease, or operate numerous properties that have been used for oil
and natural gas exploration and production for many years. Although we believe
that we have utilized operating and waste disposal practices that were standard
in the industry at the time, hazardous substances, wastes, or hydrocarbons may
have been released on or under the properties owned or leased by us, or on or
under other locations, including off-site locations, where such substances have
been taken for disposal. In addition, some of our properties have been operated
by third parties or by previous owners or operators whose treatment and disposal
of hazardous substances, wastes, or hydrocarbons was not under our control. In
fact, there is evidence that petroleum spills or releases have occurred in the
past at some of the properties owned or leased by us. These properties and the
substances disposed or released on them may be subject to CERCLA, RCRA, and
analogous state laws. Under such laws, we could be required to remove previously
disposed substances and wastes, remediate contaminated property, or perform
remedial plugging or pit closure operations to prevent future
contamination.
Water Discharges. The Federal
Water Pollution Control Act, or the Clean Water Act, and analogous state laws,
impose restrictions and strict controls with respect to the discharge of
pollutants, including spills and leaks of oil and other substances, into waters
of the United States. The discharge of pollutants into regulated waters is
prohibited, except in accordance with the terms of a permit issued by EPA or an
analogous state agency. The Clean Water Act also imposes spill prevention,
control, and countermeasure requirements, including requirements for appropriate
containment berms and similar structures, to help prevent the contamination of
navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or
leak. Federal and state regulatory agencies can impose administrative, civil and
criminal penalties for non-compliance with discharge permits or other
requirements of the Clean Water Act and analogous state laws and
regulations.
The
primary federal law for oil spill liability is the Oil Pollution Act, or OPA,
which establishes a variety of requirements pertaining to oil spill prevention,
containment, and cleanup. OPA applies to vessels, offshore facilities, and
onshore facilities, including exploration and production facilities that may
affect waters of the United States. Under OPA, responsible parties, including
owners and operators of onshore facilities, are required to develop and
implement plans for preventing and responding to oil spills and, if a spill
occurs, may be subject to oil cleanup costs and natural resource damages as well
as a variety of public and private damages that may result from the
spill.
Air Emissions. The Federal
Clean Air Act, and comparable state laws, regulate emissions of various air
pollutants through air emissions permitting programs and the imposition of other
requirements. In addition, EPA has developed, and continues to develop,
stringent regulations governing emissions of toxic air pollutants at specified
sources. States can impose air emissions limitations that are more stringent
than the federal standards imposed by EPA, and California air quality laws and
regulations are in many instances more stringent than comparable federal laws
and regulations. Federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance with air permits
or other requirements of the federal Clean Air Act and associated state laws and
regulations. Regulatory requirements relating to air emissions are particularly
stringent in Southern California.
Global Warming and Climate
Change. Recent
scientific studies have suggested that emissions of certain gases, commonly
referred to as “greenhouse gases” and including carbon dioxide and methane, may
be contributing to warming of the Earth’s atmosphere. In response to such
studies, the U.S. Congress is considering legislation to reduce emissions of
greenhouse gases and more than one-third of the states (including California),
either individually or through multi-state initiatives, already have begun
implementing legal measures to reduce emissions of greenhouse gases. Also, the
U.S. Supreme Court’s holding in its 2007 decision, Massachusetts, et al. v. EPA,
that carbon dioxide may be regulated as an “air pollutant” under the federal
Clean Air Act could result in future regulation of greenhouse gas emissions from
stationary sources, even if Congress does not adopt new legislation specifically
addressing emissions of greenhouse gases. In July 2008, EPA released an “Advance
Notice of Proposed Rulemaking” regarding possible future regulation of
greenhouse gas emissions under the Clean Air Act. Although the notice did not
propose any specific, new regulatory requirements for greenhouse gases, it
indicates that federal regulation of greenhouse gas emissions could occur in the
near future. Although it is not possible at this time to predict how legislation
or new regulations that may be adopted to address greenhouse gas emissions would
impact our business, any such future laws and regulations could result in
increased compliance costs or additional operating restrictions, and could have
an adverse effect on demand for the oil and natural gas we produce.
Pipeline Safety. Some of our
pipelines are subject to regulation by the U.S. Department of Transportation
(“DOT”) under the Pipeline Safety Improvement Act of 2002, which was
reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and
Safety Act of 2006. The DOT, through the Pipeline and Hazardous Materials Safety
Administration (“PHMSA”), has established a series of rules that require
pipeline operators to develop and implement integrity management programs for
gas, NGL and condensate transmission pipelines as well as certain low stress
pipelines and gathering lines transporting hazardous liquids, such as oil, that,
in the event of a failure, could affect “high consequence areas.” “High
consequence areas” are currently defined to include areas with specified
population densities, buildings containing populations with limited mobility,
areas where people may gather along the route of a pipeline (such as athletic
fields or campgrounds), environmentally sensitive areas, and commercially
navigable waterways. Under the DOT’s regulations, integrity management programs
are required to include baseline assessments to identify potential threats to
each pipeline segment, implementation of mitigation measures to reduce the risk
of pipeline failure, periodic reassessments, reporting and recordkeeping. Fines
and penalties may be imposed on pipeline operators that fail to comply with
PHMSA requirements, and such operators may also become subject to orders or
injunctions restricting pipeline operations.
OSHA and Other Laws and
Regulation. We are subject to the requirements of the federal
Occupational Safety and Health Act, or OSHA, and comparable state statutes.
These laws and the implementing regulations strictly govern the protection of
the health and safety of employees. The OSHA hazard communication standard, EPA
community right-to-know regulations under the Title III of CERCLA and similar
state statutes require that we organize and/or disclose information about
hazardous materials used or produced in our operations. We believe that we are
in substantial compliance with these applicable requirements and with other OSHA
and comparable requirements.
We
believe that we are in substantial compliance with all existing environmental
laws and regulations applicable to our current operations and that our continued
compliance with existing requirements will not have a material adverse impact on
our financial condition and results of operations. For instance, we did not
incur any material capital expenditures for remediation or pollution control
activities for the year ended December 31, 2008. Additionally, we are not aware
of any environmental issues or claims that will require material capital
expenditures during 2009. However, accidental spills or releases may occur in
the course of our operations, and we cannot assure you that we will not incur
substantial costs and liabilities as a result of such spills or releases,
including those relating to claims for damage to property and persons. In
addition, we expect to be required to incur remediation costs for property,
wells and facilities at the end of their useful lives. Moreover, we cannot
assure you that the passage of more stringent laws or regulations in the future
will not have a negative impact on our business, financial condition, and
results of operations or ability to make distributions to our
unitholders.
Other Regulation of the Oil and Gas
Industry
The oil
and gas industry is extensively regulated by numerous federal, state and local
authorities. Legislation affecting the oil and gas industry is under constant
review for amendment or expansion, frequently increasing the regulatory burden.
Also, numerous departments and agencies, both federal and state, are authorized
by statute to issue rules and regulations binding on the oil and gas industry
and its individual members, some of which carry substantial penalties for
failure to comply. Although the regulatory burden on the oil and gas industry
increases our cost of doing business and, consequently, affects our
profitability, these burdens generally do not affect us any differently or to
any greater or lesser extent than they affect other companies in the industry
with similar types, quantities and locations of production.
Legislation
continues to be introduced in Congress and development of regulations continues
in the Department of Homeland Security and other agencies concerning the
security of industrial facilities, including oil and gas facilities. Our
operations may be subject to such laws and regulations. Presently, it is not
possible to accurately estimate the costs we could incur to comply with any such
facility security laws or regulations, but such expenditures could be
substantial.
Production Regulation. Our
operations are subject to various types of regulation at federal, state and
local levels. These types of regulation include requiring permits for the
drilling of wells, drilling bonds and reports concerning operations. Most
states, and some counties and municipalities, in which we operate, also regulate
one or more of the following:
The
various states regulate the drilling for, and the production of, oil and natural
gas, including imposing severance taxes and requirements for obtaining drilling
permits. Wyoming currently imposes a severance tax on oil and gas
producers at the rate of 6 percent of the value of the gross product
extracted. Reduced rates may apply to certain types of wells and
production methods, such as new wells, renewed wells, stripper production and
tertiary production. Texas currently imposes a severance tax on oil
and gas producers at the rate of 4.6 percent of the value of the gross product
extracted. Michigan currently imposes a severance tax on oil
producers at the rate of 7.35 percent and on gas producers at the rate of 5.75
percent. Florida currently imposes a severance tax on oil producers
of up to 8 percent. California does not currently impose a severance
tax but attempts to impose a similar tax have been introduced in the
past.
States
also regulate the method of developing new fields, the spacing and operation of
wells and the prevention of waste of oil and natural gas
resources. States may regulate rates of production and may establish
maximum daily production allowables from oil and gas wells based on market
demand or resource conservation, or both. States do not regulate wellhead prices
or engage in other similar direct economic regulation, but there can be no
assurance that they will not do so in the future. The effect of these
regulations may be to limit the amounts of oil and natural gas that may be
produced from our wells, and to limit the number of wells or locations we can
drill. Our Los Angeles basin properties are located in urbanized
areas, and certain drilling and development activities within these fields
require local zoning and land use permits obtained from individual cities or
counties. These permits are discretionary and, when issued, usually
include mitigation measures which may impose significant additional costs or
otherwise limit development opportunities.
Gathering Pipeline
Regulation. Section 1(b) of the NGA exempts natural gas
gathering facilities from regulation by FERC as a natural gas company under the
NGA. We believe that the natural gas pipelines in our gathering systems meet the
traditional tests FERC has used to establish a pipeline’s status as a gatherer
not subject to regulation as a natural gas company. However, the distinction
between FERC-regulated transmission services and federally unregulated gathering
services is the subject of substantial, on-going litigation, so the
classification and regulation of our gathering facilities are subject to change
based on future determinations by FERC, the courts, or Congress. Natural gas
gathering may receive greater regulatory scrutiny at both the state and federal
levels. Our natural gas gathering operations could be adversely affected should
they be subject to more stringent application of state or federal regulation of
rates and services. Our natural gas gathering operations also may be or become
subject to additional safety and operational regulations relating to the design,
installation, testing, construction, operation, replacement and management of
gathering facilities. Additional rules and legislation pertaining to these
matters are considered or adopted from time to time. We cannot predict what
effect, if any, such changes might have on our operations, but the industry
could be required to incur additional capital expenditures and increased costs
depending on future legislative and regulatory changes.
Though
our natural gas gathering facilities are not subject to regulation by FERC as
natural gas companies under the NGA, our gathering facilities may be subject to
certain FERC annual natural gas transaction reporting requirements and daily
scheduled flow and capacity posting requirements depending on the volume of
natural gas transactions and flows in a given period. See below the discussion
of “FERC Market Transparency Rules.”
Our
natural gas gathering operations are subject to regulation in the various states
in which we operate. The level of such regulation varies state by state. Failure
to comply with state regulations can result in the imposition of administrative,
civil and criminal penalties.
Transportation Pipeline
Regulation. Our sole interstate pipeline is an 8.3 mile
pipeline that connects with the Texas Gas Transmission interstate pipeline. That
pipeline is subject to a limited jurisdiction FERC certificate, and we are not
currently required to maintain a tariff at FERC. Our intrastate natural gas
transportation pipelines are subject to regulation by applicable state
regulatory commissions. The level of such regulation varies state by state.
Failure to comply with state regulations can result in the imposition of
administrative, civil and criminal penalties.
Though
our natural gas intrastate pipelines are not subject to regulation by FERC as
natural gas companies under the NGA, our intrastate pipelines may be subject to
certain FERC annual natural gas transaction reporting requirements and daily
scheduled flow and capacity posting requirements depending on the volume of
natural gas transactions and flows in a given period. See below the discussion
of “FERC Market Transparency Rules.”
Natural Gas Processing Regulation. Our
natural gas processing operations are not presently subject to FERC regulation.
However, pursuant to Order No. 704, starting May 1, 2009, some of our processing
operations may be required to annually report to FERC information regarding
natural gas sale and purchase transactions depending on the volume of natural
gas transacted during the prior calendar year. See below the discussion of “FERC
Market Transparency Rules.” There can be no assurance that our processing
operations will continue to be exempt from other FERC regulation in the
future.
Our
processing facilities are affected by the availability, terms and cost of
pipeline transportation. The price and terms of access to pipeline
transportation can be subject to extensive federal and in state regulation. FERC
is continually proposing and implementing new rules and regulations affecting
the interstate transportation of natural gas, and to a lesser extent, the
interstate transportation of NGLs. These initiatives also may indirectly affect
the intrastate transportation of natural gas and NGLs under certain
circumstances. We cannot predict the ultimate impact of these regulatory changes
to our processing operations.
The
ability of our processing facilities and pipelines to deliver natural gas into
third party natural gas pipeline facilities is directly impacted by the gas
quality specifications required by those pipelines. On June 15, 2006, FERC
issued a policy statement on provisions governing gas quality and
interchangeability in the tariffs of interstate gas pipeline companies and a
separate order declining to set generic prescriptive national standards. FERC
strongly encouraged all natural gas pipelines subject to its jurisdiction to
adopt, as needed, gas quality and interchangeability standards in their FERC gas
tariffs modeled on the interim guidelines issued by a group of industry
representatives, headed by the Natural Gas Council (the “NGC+ Work Group”), or
to explain how and why their tariff provisions differ. We do not believe that
the adoption of the NGC+ Work Group’s gas quality interim guidelines by a
pipeline that either directly or indirectly interconnects with our facilities
would materially affect our operations. We have no way to predict, however,
whether FERC will approve of gas quality specifications that materially differ
from the NGC+ Work Group’s interim guidelines for such an interconnecting
pipeline.
Regulation of Sales of Natural Gas
and NGLs. The price at which we buy and sell natural gas and
NGLs is currently not subject to federal rate regulation and, for the most part,
is not subject to state regulation. However, with regard to our physical
purchases and sales of these energy commodities, and any related hedging
activities that we undertake, we are required to observe anti-market
manipulation laws and related regulations enforced by FERC and/or the Commodity
Futures Trading Commission (“CFTC”). See below the discussion of “Energy Policy
Act of 2005.” Should we violate the anti-market manipulation laws and
regulations, we could also be subject to related third party damage claims by,
among others, market participants, sellers, royalty owners and taxing
authorities.
Our sales
of natural gas and NGLs are affected by the availability, terms and cost of
pipeline transportation. As noted above, the price and terms of access to
pipeline transportation can be subject to extensive federal and state
regulation. FERC is continually proposing and implementing new rules and
regulations affecting the interstate transportation of natural gas, and to a
lesser extent, the interstate transportation of NGLs. These initiatives also may
indirectly affect the intrastate transportation of natural gas and NGLs under
certain circumstances. We cannot predict the ultimate impact of these regulatory
changes to our natural gas and NGL marketing operations, and we do not believe
that we would be affected by any such FERC action materially differently than
other natural gas and NGL marketers with whom we compete.
Energy Policy Act of 2005. On
August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy
Act of 2005, or EPAct 2005. EPAct 2005 is a comprehensive compilation of tax
incentives, authorized appropriations for grants and guaranteed loans, and
significant changes to the statutory policy that affects all segments of the
energy industry. With respect to regulation of natural gas transportation, EPAct
2005 amended the NGA and the NGPA by increasing the criminal penalties available
for violations of each Act. EPAct 2005 also added a new section to the NGA,
which provides FERC with the power to assess civil penalties of up to $1,000,000
per day for violations of the NGA and increased the FERC’s civil penalty
authority under the NGPA from $5,000 per violation per day to $1,000,000 per
violation per day. The civil penalty provisions are applicable to entities that
engage in FERC-jurisdictional transportation and the sale for resale of natural
gas in interstate commerce. EPAct 2005 also amended the NGA to add an
anti-market manipulation provision which makes it unlawful for any entity to
engage in prohibited behavior in contravention of rules and regulations to be
prescribed by FERC. On January 19, 2006, FERC issued Order No. 670, a rule
implementing the anti-market manipulation provision of EPAct 2005, and
subsequently denied rehearing. The rules make it unlawful to: (1) in connection
with the purchase or sale of natural gas subject to the jurisdiction of FERC, or
the purchase or sale of transportation services subject to the jurisdiction of
FERC, for any entity, directly or indirectly, to use or employ any device,
scheme or artifice to defraud; (2) to make any untrue statement of material fact
or omit to make any such statement necessary to make the statements made not
misleading; or (3) to engage in any act or practice that operates as a fraud or
deceit upon any person. The new anti-market manipulation rule does not apply to
activities that relate only to non-jurisdictional sales or gathering, but does
apply to activities of gas pipelines and storage companies that provide
interstate services, as well as otherwise non-jurisdictional entities to the
extent the activities are conducted “in connection with” gas sales, purchases or
transportation subject to FERC jurisdiction, which now includes the annual
reporting requirements under Order No. 704 and the daily scheduled flow and
capacity posting requirements under Order No. 720. The anti-market manipulation
rule and enhanced civil penalty authority reflect an expansion of FERC’s
enforcement authority. Additional proposals and proceedings that might affect
the natural gas industry are pending before Congress, FERC and the courts. The
natural gas industry historically has been heavily regulated. Accordingly, we
cannot assure you that present policies pursued by FERC and Congress will
continue.
FERC Market Transparency
Rules. On December 26, 2007, FERC issued a final rule on the annual
natural gas transaction reporting requirements, as amended by subsequent orders
on rehearing (“Order No. 704”). Under Order No. 704, wholesale buyers and
sellers of more than 2.2 million MMBtu of physical natural gas in the previous
calendar year, including interstate and intrastate natural gas pipelines,
natural gas gatherers, natural gas processors, natural gas marketers, and
natural gas producers, are now required to report, on May 1 of each year,
beginning in 2009, aggregate volumes of natural gas purchased or sold at
wholesale in the prior calendar year. It is the responsibility of the reporting
entity to determine which individual transactions should be reported based on
the guidance of Order No. 704. Order No. 704 also requires market participants
to indicate whether they report prices to any index publishers, and if so,
whether their reporting complies with FERC’s policy statement on price
reporting.
On
November 20, 2008, FERC issued a final rule on the daily scheduled flow and
capacity posting requirements (“Order No. 720”). Under Order No. 720, major
non-interstate pipelines, defined as certain non-interstate pipelines
delivering, on an annual basis, more than an average of 50 million MMBtu of
natural gas over the previous three calendar years, are required to post daily
certain information regarding the pipeline’s capacity and scheduled flows for
each receipt and delivery point that has a design capacity equal to or greater
than 15,000 MMBtu/d. Requests for clarification and rehearing of Order No. 720
have been filed at FERC and a decision on those requests is
pending.
Employees
BreitBurn
Management, our wholly owned subsidiary, 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. As of December
31, 2008, BreitBurn Management had 395 full time employees. BreitBurn Management
provides services to us as well as our Predecessor, BEC. None of our employees
are represented by labor unions or covered by any collective bargaining
agreement. We believe that relations with our employees are
satisfactory.
Offices
BreitBurn
Management currently leases approximately 27,280 square feet of office space in
California at 515 S.
Flower St., Suite 4800, Los Angeles, California 90071, where our principal
offices are located. The lease for the California office expires in February
2016. BreitBurn Management has leased approximately 29,300 square feet of office
space located on the 48th floor
of the JP Morgan Chase Tower at 600 Travis Street, Houston, Texas. BreitBurn
Management has significantly expanded its presence in Houston. In addition to
the offices in Los Angeles and Houston, BreitBurn Management maintains offices
in Gaylord, Michigan and Cody, Wyoming.
Financial
Information
Information regarding our revenues from
external customers, profit or loss and total assets is presented in Part II—Item
8 “—Financial Statements and Supplementary Data” in this
report. An
investment in our securities is subject to certain risks described below. We
also face other risks and uncertainties beyond what we have described below. If
any of these risks were actually to occur, our business, financial condition or
results of operations could be materially adversely affected. In that case, we
might not be able to pay the distributions on our Common Units, the trading
price of our Common Units could decline and you could lose part or all of your
investment.
Risks
Related to Our Business
We
may not be able to pay quarterly distributions on our Common Units because we do
not have sufficient cash flow from operations following establishment of cash
reserves and payment of fees and expenses.
We may
not have sufficient available cash each quarter to pay quarterly distributions
on our Common Units. Under the terms of our partnership agreement,
the amount of cash otherwise available for distribution will be reduced by our
operating expenses and the amount of any cash reserve amounts that our general
partner establishes to provide for future operations, future capital
expenditures, future debt service requirements and future cash distributions to
our unitholders. In the future we may reserve a substantial portion of our cash
generated from operations to develop our oil and natural gas properties and to
acquire additional oil and natural gas properties in order to maintain and grow
our level of oil and natural gas reserves.
The
amount of cash we actually generate will depend upon numerous factors related to
our business that may be beyond our control, including among other
things:
In
addition, the actual amount of cash that we will have available for distribution
will depend on other factors, including:
For a
description of additional restrictions and factors that may affect our ability
to make cash distributions, please read Part II—Item 7 “—Management's Discussion
and Analysis of Financial Condition and Results of Operations—Liquidity and
Capital Resources.”
Oil
and natural gas prices and differentials are volatile. Recent declines in
commodity prices have adversely affected, and in the future will adversely
affect, our financial condition and results of operations, cash flow, access to
the capital markets and ability to grow. A decline in our cash flow
from operations may force us to reduce our distributions or cease paying
distributions altogether.
The oil
and natural gas markets are very volatile, and we cannot predict future oil and
natural gas prices. Prices for oil and natural gas may fluctuate widely in
response to relatively minor changes in the supply of and demand for oil and
natural gas, market uncertainty and a variety of additional factors that are
beyond our control, such as:
Oil
prices and natural gas prices do not necessarily fluctuate in direct
relationship to each other. Because natural gas accounted for approximately 75
percent of our estimated proved reserves as of December 31, 2008 and is a
substantial portion of our current production on an Mcfe basis, our financial
results will be more sensitive to movements in natural gas prices.
In the
past, prices of oil and natural gas have been extremely volatile, and we expect
this volatility to continue. For example, during the year ended December 31,
2008, the monthly average NYMEX WTI price ranged from a high of $134 per barrel
for June to a low of $41 per barrel for December, while the monthly average
Henry Hub natural gas price ranged from a high of $12.78 per MMBtu for June to a
low of $5.79 per MMBtu for December.
Price
discounts or differentials between NYMEX WTI prices and what we actually receive
are also historically very volatile. For instance, during calendar
year 2008, the average quarterly price discount from NYMEX WTI for our Wyoming
production varied from $16.44 to $20.09 per barrel. This represented
a percentage of the total price per barrel ranging from 14 percent to 30
percent. For California crude oil, our average quarterly discount
from NYMEX WTI varied from $4.38 to $6.19, which was four percent to 11 percent
of the total price per barrel. Our crude oil produced from our
Florida properties also trades at a significant discount to NYMEX WTI primarily
because of its low gravity and other characteristics as well as its distance
from a major refining market. For Florida crude oil, our average quarterly
discount to NYMEX WTI varied from $13.72 to $14.78 including transportation
expenses of approximately $4.00 per barrel, which represented 12 percent to 25
percent of the total price per barrel.
Our
revenue, profitability and cash flow depend upon the prices and demand for oil
and natural gas, and a drop in prices can significantly affect our financial
results and impede our growth. In particular, declines in commodity prices will
negatively impact:
Historically,
higher oil and natural gas prices generally stimulate increased demand and
result in increased prices for drilling equipment, crews and associated
supplies, equipment and services. Although commodity prices have steeply
declined recently, we believe that the costs associated with drilling have not
declined as rapidly. Accordingly, continued high costs could
adversely affect our ability to pursue our drilling program and our results of
operations.
In the
past, we have raised our distribution levels on our Common Units in response to
increased cash flow during periods of relatively high commodity
prices. However, we may not be able to sustain those distribution
levels during subsequent periods of lower commodity prices. For
example, our initial distribution rate was $1.65 on an annual basis for the
fourth quarter of 2006. The distribution made to our unitholders on
February 13, 2009 for the fourth quarter of 2008 was $2.08 on an annual
basis. With the rapid decrease in commodity prices since July 2008,
there is a substantial risk that we may not be able to maintain the current
level of our distribution and that we may have to reduce or suspend our
distributions.
The
continuing financial crisis, the rapid decline in commodity prices and
uncertainties raised by litigation may limit our ability to obtain funding in
the capital markets on terms we find acceptable, obtain additional or continued
funding under our current credit facility or obtain funding at all.
Global
financial markets and economic conditions have been, and continue to be,
disrupted and volatile. In addition, the debt and equity capital markets have
been exceedingly distressed. These issues, along with significant write-offs in
the financial services sector, the re-pricing of credit risk and the current
weak economic conditions have made, and will likely continue to make,
it difficult to obtain funding in the capital markets. In
particular, the cost of raising money in the debt and equity capital markets has
increased substantially while the availability of funds from those markets
generally has diminished significantly. Also, as a result of concerns about the
stability of financial markets generally and the solvency of counterparties
specifically, the cost of obtaining money from the credit markets generally has
increased as many lenders and institutional investors have increased interest
rates, enacted tighter lending standards, refused to refinance existing debt at
maturity at all or on terms similar to our current debt and reduced and, in some
cases, ceased to provide any new funding.
Historically,
we have used our cash flow from operations, borrowings under our credit facility
and issuance of additional partnership units to fund our capital expenditures
and acquisitions. A continuation of the economic crisis could result
in further reduced demand for oil and natural gas and keep downward pressure on
the prices for oil and natural gas, which have fallen dramatically since
reaching historic highs in July 2008. These price declines have
negatively impacted our revenues and cash flows. In addition, as
discussed in “–Risks Related to Quicksilver Lawsuit” and Part I—Item 3 – “Legal
Proceedings” within this
report, Quicksilver
has filed a lawsuit against us alleging a number of claims. Such
actions, regardless of their merit, make access to debt or equity more difficult
as a result of the inherent uncertainty in all litigated matters.
These
events affect our ability to access capital in a number of ways, which include
the following:
· Our
ability to access new debt or credit markets on acceptable terms is currently
extremely limited or non-existent and this condition may last for an unknown
period of time.
· Our
current credit facility limits the amounts we can borrow to a borrowing base
amount, determined by the lenders in their sole discretion based on their valuation
of our proved reserves and their internal criteria.
· We
may be unable to obtain adequate funding under our current credit facility
because our lenders may simply be unwilling or unable to meet their funding
obligations given current market conditions.
· The
operating and financial restrictions and covenants in our credit facility limit
(and any future financing agreements likely will limit) our ability to finance
future operations or capital needs or to engage, expand or pursue our business
activities or to pay distributions.
Due to
these factors, we cannot be certain that funding will be available if needed and
to the extent required, on acceptable terms. If funding is not
available when needed, or if funding is available only on unfavorable terms, we
may be unable to meet our obligations as they come due or be required to post
collateral to support our obligations, or we may be unable to implement our
development plans, enhance our existing business, complete acquisitions or
otherwise take advantage of business opportunities or respond to competitive
pressures, any of which could have a material adverse effect on our production,
revenues, results of operations, financial condition or ability to pay
distributions. Moreover, if we are unable to obtain funding to make acquisitions
of additional properties containing proved oil or natural gas reserves, our
total level of proved reserves may decline as a result of our production, and we
may be limited in our ability to maintain our level of cash
distributions.
Our
credit facility has substantial restrictions and financial covenants that may
restrict our business and financing activities and our ability to pay
distributions.
As of
February 27, 2009, we had approximately $714 million in borrowings outstanding
under our credit facility. Our credit facility limits the amounts we
can borrow to a borrowing base amount, determined by the lenders in their sole
discretion based on their valuation of our proved reserves and their internal
criteria. Our current borrowing base is $900 million. The borrowing base is
redetermined semi-annually and the available borrowing amount could be decreased
as a result of such redeterminations. Decreases in the available borrowing
amount could result from declines in oil and natural gas prices, operating
difficulties or increased costs, declines in reserves, lending requirements or
regulations or certain other circumstances. Our next semi-annual redetermination
is scheduled in April 2009. As a result of the steep decline in oil and natural
gas prices, we expect that the lenders under our credit facility will
redetermine our borrowing base and decrease the available borrowing
amount. The decrease in our borrowing base could be substantial and
could be to a level below our outstanding borrowings. Outstanding borrowings in
excess of the borrowing base are required to be repaid, or we are required to
pledge other oil and natural gas properties as additional collateral, within 30
days following notice from the administrative agent of the new or adjusted
borrowing base. If
we do not have sufficient funds on hand for repayment, we may be required to
seek a waiver or amendment from our lenders, refinance our credit facility or
sell assets or debt or Common Units. We may not be able obtain such
financing or complete such transactions on terms acceptable to us, or at
all. Failure to make the required repayment could result in a default
under our credit facility, which could adversely affect our business, financial
condition and results or operations.
The
operating and financial restrictions and covenants in our credit facility
restrict and any future financing agreements likely will restrict our ability to
finance future operations or capital needs or to engage, expand or pursue our
business activities or to pay distributions. Our credit facility restricts and
any future credit facility likely will restrict our ability to:
Our
credit facility restricts our ability to make distributions to unitholders or
repurchase units if aggregated letters of credit and outstanding loan amounts
exceed 90 percent of our borrowing base. In the event of a
substantial reduction in our borrowing base at the time of a borrowing base
redetermination, this restriction may prevent us from making distributions to
unitholders.
We also
are required to comply with certain financial covenants and ratios. Our ability
to comply with these restrictions and covenants in the future is uncertain and
will be affected by the levels of cash flow from our operations and events or
circumstances beyond our control. In light of the current weak economic
conditions and the deterioration of oil and natural gas prices, our ability to
comply with these covenants may be impaired. If we violate any of the
restrictions, covenants, ratios or tests in our credit facility, a significant
portion of our indebtedness may become immediately due and payable, our ability
to make distributions will be inhibited and our lenders’ commitment to make
further loans to us may terminate. We might not have, or be able to obtain,
sufficient funds to make these accelerated payments. In addition, our
obligations under our credit facility are secured by substantially all of our
assets, and if we are unable to repay our indebtedness under our credit
facility, the lenders can seek to foreclose on our assets. See Part II—Item 7
“—Management's Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources” for a discussion of our credit
facility covenants.
Our debt levels may limit our
flexibility to obtain additional financing and pursue other business
opportunities.
Our
existing and future indebtedness could have important consequences to us,
including:
Our
ability to service our indebtedness will depend upon, among other things, our
future financial and operating performance, which will be affected by prevailing
economic conditions and financial, business, regulatory and other factors, some
of which are beyond our control. If our operating results are not sufficient to
service our current or future indebtedness, we will be forced to take actions
such as reducing distributions, reducing or delaying business activities,
acquisitions, investments and/or capital expenditures, selling assets,
restructuring or refinancing our indebtedness, or seeking additional equity
capital or bankruptcy protection. We may not be able to effect any of these
remedies on satisfactory terms or at all.
To
fund our capital expenditures, we will be required to use cash generated from
our operations, additional borrowings or the issuance of additional partnership
interests, or some combination thereof.
In 2009,
our capital program is expected to be approximately $20 million. In 2008, we
spent approximately $129 million on capital expenditures. Our 2009
capital budget reflects our intent to finance our capital expenditures with cash
generated from our operations. Our planned reduction of capital
expenditures in 2009, compared to 2008, reflects our expectations of lower
commodity prices in the future and declining oil field equipment, drilling and
other service costs. Use of cash generated from operations to fund
future capital expenditures will reduce cash available for distribution to our
unitholders. Our ability to obtain bank financing or to access the capital
markets for future equity or debt offerings to fund future capital expenditures
has been limited over the last six months because of the continuing credit
crisis and turmoil in the financial markets. In the future, our
ability to borrow and to access the capital markets may be limited by our
financial condition at the time of any such financing or offering and the
covenants in our debt agreements, as well as by oil and natural gas prices, the
value and performance of our equity securities, and adverse market conditions
resulting from, among other things, general economic conditions and
contingencies and uncertainties that are beyond our control. Our failure to
obtain the funds for necessary future capital expenditures could have a material
adverse effect on our business, results of operations, financial condition and
ability to pay distributions. Even if we are successful in obtaining the
necessary funds, the terms of such financings could limit our ability to pay
distributions to our unitholders. In addition, incurring additional debt may
significantly increase our interest expense and financial leverage, and issuing
additional partnership interests may result in significant unitholder dilution
thereby increasing the aggregate amount of cash required to maintain the
then-current distribution rate, which could have a material adverse effect on
our ability to pay distributions at the then-current distribution
rate.
Our
inability to replace our reserves could result in a material decline in our
reserves and production, which could adversely affect our financial
condition. We are unlikely to be able to sustain or increase our
current level of distributions without making accretive acquisitions or capital
expenditures that maintain or grow our asset base.
As a
result of the significant decline in commodity prices and the impact of the
credit crisis on available credit and access to capital, we expect that our
ability to make acquisitions will be limited in 2009. We also believe
that our reduced capital program in 2009 will not be sufficient to offset
production declines.
Producing
oil and natural gas reservoirs are characterized by declining production rates
that vary based on reservoir characteristics and other factors. The rate of
decline of our reserves and production included in our reserve report at
December 31, 2008 will change if production from our existing wells
declines in a different manner than we have estimated and may change when we
drill additional wells, make acquisitions and under other circumstances. Our
future oil and natural gas reserves and production and our cash flow and ability
to make distributions depend on our success in developing and exploiting our
current reserves efficiently and finding or acquiring additional recoverable
reserves economically. We may not be able to develop, find or acquire additional
reserves to replace our current and future production at acceptable costs, which
would adversely affect our business, financial condition and results of
operations and reduce cash available for distribution.
We are
unlikely to be able to sustain or increase our current level of distributions
without making accretive acquisitions or capital expenditures that maintain or
grow our asset base. We will need to make substantial capital expenditures to
maintain and grow our asset base, which will reduce our cash available for
distribution. Because the timing and amount of these capital expenditures
fluctuate each quarter, we expect to reserve cash each quarter to finance these
expenditures over time. We may use the reserved cash to reduce indebtedness
until we make the capital expenditures.
Over a
longer period of time, if we do not set aside sufficient cash reserves or make
sufficient expenditures to maintain our asset base, we will be unable to pay
distributions at the current level from cash generated from operations and would
therefore expect to reduce our distributions. If we do not make sufficient
growth capital expenditures, we will be unable to sustain our business
operations and therefore will be unable to maintain our proposed or current
level of distributions. With our reserves decreasing, if we do not
reduce our distributions, then a portion of the distributions may be considered
a return of part of your investment in us as opposed to a return on your
investment. Also, if we do not make sufficient growth capital expenditures, we
will be unable to expand our business operations and will therefore be unable to
raise the level of future distributions.
Price
declines have resulted in and may in the future result in a write-down of our
asset carrying values.
Declines in oil and natural gas prices
over the past 180 days have resulted in our having to make substantial downward
adjustments to our estimated proved reserves resulting in increased
depletion and depreciation charges. Accounting rules require us to write
down, as a non-cash charge to earnings, the carrying value of our oil and
natural gas properties for impairments. We are required to perform impairment
tests on our assets periodically and whenever events or changes in circumstances
warrant a review of our assets. To the extent such tests indicate a reduction of
the estimated useful life or estimated future cash flows of our assets, the
carrying value may not be recoverable and therefore requires a write-down. For example, as a result
of the dramatic declines in oil and gas prices in the second half of 2008 and
related reserve reductions, we recorded non-cash charges of approximately $51.9
million for total impairments and $34.5 million for price related
adjustments to depletion and depreciation expense for the year ended December
31, 2008. We also may incur impairment charges in the future, which
could have a material adverse effect on our results of operations in the period
incurred and on our ability to borrow funds under our credit facility, which in
turn may adversely affect our ability to make cash distributions to our
unitholders.
Our
derivative activities could result in financial losses or could reduce our
income, which may adversely affect our ability to pay distributions to our
unitholders. To the extent we have hedged a significant portion of our expected
production and actual production is lower than expected or the costs of goods
and services increase, our profitability would be adversely
affected.
To
achieve more predictable cash flow and to reduce our exposure to adverse
fluctuations in the prices of oil and natural gas, we currently and may in the
future enter into derivative arrangements for a significant portion of our
expected oil and natural gas production that could result in both realized and
unrealized hedging losses. As of February 27, 2009, we had hedged, through
swaps, options (including collar instruments) and physical contracts,
approximately 84 percent of our 2009 production.
The
extent of our commodity price exposure is related largely to the effectiveness
and scope of our derivative activities. For example, the derivative instruments
we utilize are primarily based on NYMEX WTI and Mich Con City-Gate-Inside FERC
prices, which may differ significantly from the actual crude oil and natural gas
prices we realize in our operations. Furthermore, we have adopted a policy that
requires, and our credit facility also mandates, that we enter into derivative
transactions related to only a portion of our expected production volumes and,
as a result, we will continue to have direct commodity price exposure on the
portion of our production volumes not covered by these derivative
transactions.
Our
actual future production may be significantly higher or lower than we estimate
at the time we enter into derivative transactions for such period. If the actual
amount is higher than we estimate, we will have greater commodity price exposure
than we intended. If the actual amount is lower than the nominal amount that is
subject to our derivative financial instruments, we might be forced to satisfy
all or a portion of our derivative transactions without the benefit of the cash
flow from our sale or purchase of the underlying physical commodity, resulting
in a substantial diminution in our profitability and liquidity. As a result of
these factors, our derivative activities may not be as effective as we intend in
reducing the volatility of our cash flows, and in certain circumstances may
actually increase the volatility of our cash flows.
In
addition, our derivative activities are subject to the following
risks:
As of
February 27, 2009, our derivative counterparties were Barclays Bank PLC,
Bank of Montreal, Citibank, N.A, Credit Suisse International, Credit Suisse
Energy LLC, Union Bank of California, 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 periodically obtain credit default swap information on
our counterparties. As of December 31, 2008, each of these financial
institutions carried an S&P credit rating of A or above. 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 default. As
of December 31, 2008, our largest derivative net asset balances were with JP
Morgan Chase Bank N.A., Credit Suisse Energy LLC and Wells Fargo Bank N.A.
These counterparties accounted for 55 percent, 18 percent and 16 percent
of derivative net asset balances, respectively, as of December 31,
2008.
Our
estimated proved reserves are based on many assumptions that may prove to be
inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present value of our
reserves.
It is not
possible to measure underground accumulations of oil or natural gas in an exact
way. Oil and gas reserve engineering requires subjective estimates of
underground accumulations of oil and natural gas and assumptions concerning
future oil and natural gas prices, production levels, and operating and
development costs. In estimating our level of oil and natural gas reserves, we
and our independent reserve engineers make certain assumptions that may prove to
be incorrect, including assumptions relating to:
If these
assumptions prove to be incorrect, our estimates of reserves, the economically
recoverable quantities of oil and natural gas attributable to any particular
group of properties, the classifications of reserves based on risk of recovery
and our estimates of the future net cash flows from our reserves could change
significantly. For example, if oil and gas prices at December 31,
2008 had been, respectively, $10.00 less per Bbl and $1.00 less per MMBtu, then
the standardized measure of our estimated proved reserves as of
December 31, 2008 would have decreased by $257 million, from
$592 million to $335 million.
Our
standardized measure is calculated using unhedged oil prices and is determined
in accordance with the rules and regulations of the SEC. Over time, we may make
material changes to reserve estimates to take into account changes in our
assumptions and the results of actual drilling and production.
The
reserve estimates we make for fields that do not have a lengthy production
history are less reliable than estimates for fields with lengthy production
histories. A lack of production history may contribute to inaccuracy in our
estimates of proved reserves, future production rates and the timing of
development expenditures.
The
present value of future net cash flows from our estimated proved reserves is not
necessarily the same as the current market value of our estimated proved oil and
natural gas reserves. We base the estimated discounted future net cash flows
from our estimated proved reserves on prices and costs in effect on the day of
the estimate. However, actual future net cash flows from our oil and natural gas
properties also will be affected by factors such as:
The
timing of both our production and our incurrence of expenses in connection with
the development and production of oil and natural gas properties will affect the
timing of actual future net cash flows from proved reserves, and thus their
actual present value. In addition, the 10 percent discount factor we use when
calculating discounted future net cash flows in compliance with Statement of
Financial Accounting Standards (“SFAS”) No. 69 – “Disclosures about Oil and Gas
Producing Activities” may not be the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with us
or the oil and gas industry in general.
Drilling
for and producing oil and natural gas are costly and high-risk activities with
many uncertainties that could adversely affect our financial condition or
results of operations and, as a result, our ability to pay distributions to our
unitholders.
The cost
of drilling, completing and operating a well is often uncertain, and cost
factors can adversely affect the economics of a well. Our efforts will be
uneconomical if we drill dry holes or wells that are productive but do not
produce enough oil and natural gas to be commercially viable after drilling,
operating and other costs. Furthermore, our drilling and producing operations
may be curtailed, delayed or canceled as a result of other factors,
including:
If any of
these factors were to occur with respect to a particular field, we could lose
all or a part of our investment in the field, or we could fail to realize the
expected benefits from the field, either of which could materially and adversely
affect our revenue and profitability. For example, on November 15, 2008, there
was a brush fire at our Brea Olinda field in California that destroyed the
electrical infrastructure there and resulted in an estimated loss of production
of 5,000 Bbl for the fourth quarter 2008. Also, on December 1, 2008, there was a
fire at our Seal Beach Field in California which resulted in a brief shutdown of
the field and the gas plant located there.
In
2008, we depended on three customers for a substantial amount of our sales. If
these customers reduce the volumes of oil and natural gas that they purchase
from us, our revenue and cash available for distribution will decline to the
extent we are not able to find new customers for our production. In addition, if
the parties to our purchase contracts default on these contracts, we could be
materially and adversely affected.
In 2008,
three customers accounted for approximately 47 percent of our total sales
volumes. If these customers reduce the volumes of oil and natural gas that they
purchase from us and we are not able to find new customers for our production,
our revenue and cash available for distribution will decline. In 2008,
ConocoPhillips accounted for approximately 25 percent of our total sales
volumes, Marathon Oil accounted for approximately 13 percent of our total sales
volumes, and Plains Marketing accounted for approximately 9 percent of our total
sales volumes. For the year ended December 31, 2007, Marathon Oil accounted for
approximately 24 percent of our total sales volumes, ConocoPhillips accounted
for approximately 20 percent of our total sales volumes and Plains Marketing
accounted for approximately 15 percent of our total sales volumes.
Natural
gas purchase contracts account for a significant portion of revenues relating to
our Michigan, Indiana and Kentucky properties. We cannot assure you that the
other parties to these contracts will continue to perform under the contracts.
If the other parties were to default after taking delivery of our natural gas,
it could have a material adverse effect on our cash flows for the period in
which the default occurred. A default by the other parties prior to taking
delivery of our natural gas could also have a material adverse effect on our
cash flows for the period in which the default occurred depending on the
prevailing market prices of natural gas at the time compared to the contractual
prices.
We
may be unable to compete effectively with other companies, which may adversely
affect our ability to generate sufficient revenue to allow us to pay
distributions to our unitholders.
The oil
and gas industry is intensely competitive with respect to acquiring prospects
and productive properties, marketing oil and natural gas and securing equipment
and trained personnel, and we compete with other companies that have greater
resources. Many of our competitors are major and large independent oil and gas
companies, and possess and employ financial, technical and personnel resources
substantially greater than ours. Those companies may be able to develop and
acquire more prospects and productive properties than our financial or personnel
resources permit. Our ability to acquire additional properties and to discover
reserves in the future will depend on our ability to evaluate and select
suitable properties and to consummate transactions in a highly competitive
environment. Factors that affect our ability to acquire properties include
availability of desirable acquisition targets, staff and resources to identify
and evaluate properties and available funds. Many of our larger competitors not
only drill for and produce oil and gas but also carry on refining operations and
market petroleum and other products on a regional, national or worldwide basis.
These companies may be able to pay more for oil and gas properties and evaluate,
bid for and purchase a greater number of properties than our financial or human
resources permit. In addition, there is substantial competition for investment
capital in the oil and gas industry. Other companies may have a greater ability
to continue drilling activities during periods of low oil and gas prices and to
absorb the burden of present and future federal, state, local and other laws and
regulations. As a result of the significant decline in commodity prices and the
impact of the credit crisis on available credit and access to capital, we expect
that our ability to make accretive acquisitions will be limited in 2009. Our
inability to compete effectively with other companies could have a material
adverse effect on our business activities, financial condition and results of
operations.
We have limited
control over the activities on properties we do not operate.>
On a net
production basis, we operate approximately 82 percent of our production. We have
limited ability to influence or control the operation or future development of
the non-operated properties in which we have interests or the amount of capital
expenditures that we are required to fund for their operation. The success and
timing of drilling development or production activities on properties operated
by others depend upon a number of factors that are outside of our control,
including the timing and amount of capital expenditures, the operator's
expertise and financial resources, approval of other participants, and selection
of technology. Our dependence on the operator and other working interest owners
for these projects and our limited ability to influence or control the operation
and future development of these properties could have a material adverse effect
on the realization of our targeted returns on capital or lead to unexpected
future costs.
Our
operations are subject to operational hazards and unforeseen interruptions for
which we may not be adequately insured.
There are
a variety of operating risks inherent in our wells, gathering systems, pipelines
and other facilities, such as leaks, explosions, fires, mechanical problems and
natural disasters including earthquakes and tsunamis, all of which could cause
substantial financial losses. Any of these or other similar occurrences could
result in the disruption of our operations, substantial repair costs, personal
injury or loss of human life, significant damage to property, environmental
pollution, impairment of our operations and substantial revenue losses. The
location of our wells, gathering systems, pipelines and other facilities near
populated areas, including residential areas, commercial business centers and
industrial sites, could significantly increase the level of damages resulting
from these risks.
We
currently possess property and general liability insurance at levels, which we
believe are appropriate; however, we are not fully insured for these items and
insurance against all operational risk is not available to us. We are not fully
insured against all risks, including drilling and completion risks that are
generally not recoverable from third parties or insurance. In addition,
pollution and environmental risks generally are not fully insurable.
Additionally, we may elect not to obtain insurance if we believe that the cost
of available insurance is excessive relative to the perceived risks presented.
Losses could, therefore, occur for uninsurable or uninsured risks or in amounts
in excess of existing insurance coverage. Moreover, insurance may not be
available in the future at commercially reasonable costs and on commercially
reasonable terms. Changes in the insurance markets subsequent to the terrorist
attacks on September 11, 2001 and the hurricanes in 2005 have made it more
difficult for us to obtain certain types of coverage. There can be no assurance
that we will be able to obtain the levels or types of insurance we would
otherwise have obtained prior to these market changes or that the insurance
coverage we do obtain will not contain large deductibles or fail to cover
certain hazards or cover all potential losses. Losses and liabilities from
uninsured and underinsured events and delay in the payment of insurance proceeds
could have a material adverse effect on our business, financial condition,
results of operations and ability to make distributions to you.
If
third-party pipelines and other facilities interconnected to our well and
gathering and processing facilities become partially or fully unavailable to
transport natural gas, oil or NGLs, our revenues and cash available for
distribution could be adversely affected.
We depend
upon third party pipelines and other facilities that provide delivery options to
and from some of our wells and gathering and processing facilities. Since we do
not own or operate these pipelines or other facilities, their continuing
operation in their current manner is not within our control. If any of these
third-party pipelines and other facilities become partially or fully unavailable
to transport natural gas, oil or NGLs, or if the gas quality specifications for
the natural gas gathering or transportation pipelines or facilities change so as
to restrict our ability to transport natural gas on those pipelines or
facilities, our revenues and cash available for distribution could be adversely
affected.
For
example, in Florida, there are a limited number of alternative methods of
transportation for our production, and 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 us having to find transportation
alternatives, increased transportation costs, or involuntary curtailment of our
oil production in Florida, which could have a negative impact on its future
consolidated financial position, results of operations or cash
flows.
We
are subject to complex federal, state, local and other laws and regulations that
could adversely affect the cost, manner or feasibility of conducting our
operations.
Our oil
and natural gas exploration, production, gathering and transportation operations
are subject to complex and stringent laws and regulations. In order to conduct
our operations in compliance with these laws and regulations, we must obtain and
maintain numerous permits, approvals and certificates from various federal,
state and local governmental authorities. We may incur substantial costs in
order to maintain compliance with these existing laws and regulations. In
addition, our costs of compliance may increase if existing laws, including tax
laws, and regulations are revised or reinterpreted, or if new laws and
regulations become applicable to our operations. For example, in November 2008,
the Governor of California proposed a tax increase which included a 9.9 percent
severance tax on all oil production in California. Although the proposal was not
passed by the California Legislature as part of the approved State budget in
2009, the financial crisis in the State of California could lead to a severance
tax on oil being imposed in the future. We have significant oil production in
California and while we cannot predict the impact of such a tax without having
more specifics, the imposition of such a could have severe negative impacts on
both our willingness and ability to incur capital expenditures in California to
increase production, could severely reduce or completely eliminate our
California profit margins and would result in lower oil production in our
California properties due to the need to shut-in wells and facilities made
uneconomic either immediately or at an earlier time than would have previously
been the case.
A change
in the jurisdictional characterization of our gathering assets by federal, state
or local regulatory agencies or a change in policy by those agencies with
respect to those assets may result in increased regulation of those
assets.
Our
business is subject to federal, state and local laws and regulations as
interpreted and enforced by governmental authorities possessing jurisdiction
over various aspects of the exploration for, and production of, oil and natural
gas. Failure to comply with such laws and regulations, as interpreted and
enforced, could have a material adverse effect on our business, financial
condition, results of operations and ability to make distributions to you.
Please read Part I—Item 1 “—Business—Operations—Environmental Matters and
Regulation” and Part I—Item 1 “—Business—Operations—Other Regulation of the Oil
and Gas Industry” for a description of the laws and regulations that affect
us.
Our
operations expose us to significant costs and liabilities with respect to
environmental and operational safety matters.
We may
incur significant costs and liabilities as a result of environmental and safety
requirements applicable to our oil and natural gas exploration and production
activities. These costs and liabilities could arise under a wide range of
federal, state and local environmental and safety laws and regulations,
including regulations and enforcement policies, which have tended to become
increasingly strict over time. Failure to comply with these laws and regulations
may result in the assessment of administrative, civil and criminal penalties,
imposition of cleanup and site restoration costs and liens, and to a lesser
extent, issuance of injunctions to limit or cease operations. In addition,
claims for damages to persons or property may result from environmental and
other impacts of our operations.
Strict,
joint and several liability may be imposed under certain environmental laws,
which could cause us to become liable for the conduct of others or for
consequences of our own actions that were in compliance with all applicable laws
at the time those actions were taken. New laws, regulations or enforcement
policies could be more stringent and impose unforeseen liabilities or
significantly increase compliance costs. If we are not able to recover the
resulting costs through insurance or increased revenues, our ability to make
distributions to you could be adversely affected. Please read Part I—Item 1
“—Business—Operations—Environmental Matters and Regulation” for more
information.
We
depend on our general partner's Co-Chief Executive Officers, who would be
difficult to replace.
We depend
on the performance of our general partner's Co-Chief Executive Officers, Randall
Breitenbach and Halbert Washburn. We do not maintain key person insurance for
Mr. Breitenbach or Mr. Washburn. The loss of either or both of our general
partner's Co-Chief Executive Officers could negatively impact our ability to
execute our strategy and our results of operations. Risks
Related to Quicksilver Lawsuit
We are subject to a lawsuit brought by
Quicksilver. Because this lawsuit is at an early stage, we cannot predict the
manner and timing of the resolution of the lawsuit or its outcome, or estimate a
range of possible losses, if any, that could result in the event of an adverse
verdict in the lawsuit. The defense of this lawsuit may be costly and may result
in the diversion of the attention of our management from the operation of our
business.
On
October 31, 2008, Quicksilver instituted a lawsuit in the District Court of
Tarrant County, Texas naming the Partnership as a defendant along with BreitBurn
GP, BOGP, BOLP, Randall H. Breitenbach, Halbert S. Washburn, Gregory J. Moroney,
Charles S. Weiss, Randall J. Findlay, Thomas W. Buchanan, Grant D. Billing and
Provident. On December 12, 2008, Quicksilver filed an Amended Petition and
asserted twelve separate counts against the various defendants.
The
primary claims are as follows: Quicksilver alleges that BreitBurn Operating
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 alleges 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
units in the Partnership. Finally, Quicksilver alleges claims for breach of our
partnership agreement and other common law claims relating to certain
transactions and an amendment to the partnership agreement that occurred in June
2008. Quicksilver seeks a temporary and 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.
We intend
to defend ourselves vigorously in connection with the allegations in the
petition. However, because this lawsuit is at an early stage, we cannot predict
the manner and timing of the resolution of the lawsuit or its outcome, or
estimate a range of possible losses, if any, that could result in the event of
an adverse verdict in the lawsuit. In addition, the defense of this lawsuit may
be costly and may result in the diversion of the attention of our management
from the operation of our business.
Risks
Related to Our Structure
We
may issue additional Common Units without your approval, which would dilute your
existing ownership interests.
We may
issue an unlimited number of limited partner interests of any type, including
Common Units, without the approval of our unitholders. For example, in 2007, we
issued a total of 45 million Common Units (or 67 percent of our outstanding
Common Units) in connection with our acquisitions of oil and natural gas
properties.
The
issuance of additional Common Units or other equity securities may have the
following effects:
Our
partnership agreement limits our general partner's fiduciary duties to
unitholders and restricts the remedies available to unitholders for actions
taken by our general partner that might otherwise constitute breaches of
fiduciary duty.
Our
partnership agreement contains provisions that reduce the standards to which our
general partner would otherwise be held by state fiduciary duty law. For
example, our partnership agreement:
Unitholders
are bound by the provisions of our partnership agreement, including the
provisions described above.
Certain
of the directors and officers of our General Partner, including our
Co-Chief Executive Officers and other members of our senior management, own
interests in BEC, which is managed by our subsidiary, BreitBurn Management.
Conflicts of interest may arise between BEC, on the one hand, and us and our
unitholders, on the other hand. Our partnership agreement limits the
remedies available to you in the event you have a claim relating to conflicts of
interest.
Certain
of the directors and officers of our General Partner, including our
Co-Chief Executive Officers, own interests in BEC, which is managed by our
subsidiary, BreitBurn Management. Conflicts of interest may arise between BEC,
on the one hand, and us and our unitholders, on the other hand. We have
entered into an Omnibus Agreement with BEC to address certain of these
conflicts. However, these persons may face other conflicts between their
interests in BEC and their positions with us. These potential conflicts include,
among others, the following situations:
Our
partnership agreement limits the liability and reduces the fiduciary duties of
our General Partner and its directors and officers, while also
restricting the remedies available to our unitholders for actions that, without
these limitations, might constitute breaches of fiduciary duty. By purchasing
Common Units, unitholders will be deemed to have consented to some actions and
conflicts of interest that might otherwise constitute a breach of fiduciary or
other duties under applicable law.
Our
partnership agreement restricts the voting rights of unitholders owning 20
percent or more of our Common Units. Our unitholder rights plan would
cause extreme dilution to any person or group that attempts to acquire a
significant interest in the Partnership without advance approval of our General
Partners’ board of directors.
Our
partnership agreement restricts unitholders’ voting rights by providing that any
units held by a person that owns 20 percent or more of any class of units then
outstanding, other than our general partner, its affiliates, their transferees
and persons who acquired such units with the prior approval of the board of
directors of our general partner, cannot vote on any matter. In addition, solely
with respect to the election of directors, our partnership agreement provides
that (x) our general partner and the Partnership will not be entitled to vote
their units, if any, and (y) if at any time any person or group beneficially
owns 20 percent or more of the outstanding Partnership securities of any class
then outstanding and otherwise entitled to vote, then all Partnership securities
owned by such person or group in excess of 20 percent of the outstanding
Partnership securities of the applicable class may not be voted, and in each
case, the foregoing units will not be counted when calculating the required
votes for such matter and will not be deemed to be outstanding for purposes of
determining a quorum for such meeting. Such common units will not be treated as
a separate class of Partnership securities for purposes of our partnership
agreement. Notwithstanding the foregoing, the board of directors of our general
partner may, by action specifically referencing votes for the election of
directors, determine that the limitation set forth in clause (y) above will not
apply to a specific person or group. Our partnership agreement also contains
provisions limiting the ability of unitholders to call meetings or to acquire
information about our operations, as well as other provisions limiting
unitholders’ ability to influence the manner or direction of
management.
The board
of directors of our General Partner has adopted a unitholder rights plan. If
activated, this plan would cause extreme dilution to any person or group that
attempts to acquire a 20 percent or greater interest in the Partnership without
advance approval of our General Partner’s board of directors.
Unitholders
who are not “Eligible Holders” will not be entitled to receive distributions on
or allocations of income or loss on their Common Units and their Common Units
will be subject to redemption.
In order
to comply with U.S. laws with respect to the ownership of interests in oil and
gas leases on federal lands, we have adopted certain requirements regarding
those investors who may own our Common Units. As used herein, an Eligible Holder
means a person or entity qualified to hold an interest in oil and gas leases on
federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of
the United States; (2) a corporation organized under the laws of the United
States or of any state thereof; or (3) an association of United States citizens,
such as a partnership or limited liability company, organized under the laws of
the United States or of any state thereof, but only if such association does not
have any direct or indirect foreign ownership, other than foreign ownership of
stock in a parent corporation organized under the laws of the United States or
of any state thereof. For the avoidance of doubt, onshore mineral leases or any
direct or indirect interest therein may be acquired and held by aliens only
through stock ownership, holding or control in a corporation organized under the
laws of the United States or of any state thereof and only for so long as the
alien is not from a country that the United States federal government regards as
denying similar privileges to citizens or corporations of the United States.
Unitholders who are not persons or entities who meet the requirements to be an
Eligible Holder, will not receive distributions or allocations of income and
loss on their units and they run the risk of having their units redeemed by us
at the lower of their purchase price cost or the then-current market price. The
redemption price will be paid in cash or by delivery of a promissory note, as
determined by our general partner.
We
have a holding company structure in which our subsidiaries conduct our
operations and own our operating assets, which may affect our ability to make
distributions to you.
We are a
partnership holding company and our operating subsidiaries conduct all of our
operations and own all of our operating assets. We have no significant assets
other than the ownership interests in our subsidiaries. As a result, our ability
to make distributions to our unitholders depends on the performance of our
subsidiaries and their ability to distribute funds to us. The ability of our
subsidiaries to make distributions to us may be restricted by, among other
things, the provisions of existing and future indebtedness, applicable state
partnership and limited liability company laws and other laws and
regulations.
Unitholders
may not have limited liability if a court finds that unitholder action
constitutes control of our business.
The
limitations on the liability of holders of limited partner interests for the
obligations of a limited partnership have not been clearly established in some
of the states in which we do business. You could have unlimited liability for
our obligations if a court or government agency determined that:
Unitholders
may have liability to repay distributions.
Under
certain circumstances, unitholders may have to repay amounts wrongfully returned
or distributed to them. Under Section 17-607 of the Delaware Revised Uniform
Limited Partnership Act (the “Delaware Act”), we may not make a distribution to
you if the distribution would cause our liabilities to exceed the fair value of
our assets. Liabilities to partners on account of their partnership interests
and liabilities that are non-recourse to the partnership are not counted for
purposes of determining whether a distribution is permitted.
Delaware
law provides that for a period of three years from the date of an impermissible
distribution, limited partners who received the distribution and who knew at the
time of the distribution that it violated Delaware law will be liable to the
limited partnership for the distribution amount. A purchaser of Common Units who
becomes a limited partner is liable for the obligations of the transferring
limited partner to make contributions to the partnership that are known to such
purchaser of units at the time it became a limited partner and for unknown
obligations if the liabilities could be determined from our partnership
agreement.
The
market price of our Common Units could be adversely affected by sales of
substantial amounts of our Common Units, including sales by our existing
unitholders.
As of
February 27, 2009, we had 52,770,011 Common Units outstanding. We completed
three private offerings to institutional investors of an aggregate of 23,696,911
Common Units in 2007. The institutional investors that are not affiliates of the
Partnership currently may sell their Common Units pursuant to Rule 144 under the
Securities Act of 1933 (the “Securities Act”). Rule 144 under the Securities Act
provides that after a holding period of six months, non-affiliates may resell
restricted securities of reporting companies including the Partnership, provided
that current public information is available relating to the Partnership. After
a holding period of one year, non-affiliates may resell without restriction, and
affiliates may resell in compliance with the volume, current public information
and manner of sale requirements of Rule 144.
As
partial consideration for the Quicksilver Acquisition, we issued 21,347,972
Common Units to Quicksilver in a private placement on November 1, 2007. A
registration statement covering the resale of those Common Units has been filed
with the SEC and declared effective. Prior to May 1, 2009, Quicksilver may sell
only up to fifty percent of the Common Units that it acquired in the private
placement without restriction in the open market. After such date, Quicksilver
may resell any remaining Common Units that it holds without restriction in the
open market.
Sales by
any of our existing unitholders of a substantial number of our Common Units, or
the perception that such sales might occur, could have a material adverse effect
on the price of our Common Units or could impair our ability to obtain capital
through an offering of equity securities.
In recent
years, the securities market has experienced extreme price and volume
fluctuations. This volatility has had a significant effect on the market price
of securities issued by many companies for reasons unrelated to the operating
performance of these companies. Future market fluctuations may result in a lower
price of our Common Units.
Tax
Risks to Unitholders
Our
tax treatment depends on our status as a partnership for federal income tax
purposes, as well as our not being subject to entity-level taxation by
individual states. If we were to be treated as a corporation for federal income
tax purposes or we were to become subject to entity-level taxation for state tax
purposes, taxes paid, if any, would reduce the amount of cash available for
distribution.
The
anticipated after-tax economic benefit of an investment in our Common Units
depends largely on us being treated as a partnership for federal income tax
purposes. We have not requested, and do not plan to request, a ruling from the
IRS on this or any other tax matter that affects us.
Despite
the fact that we are a limited partnership under Delaware law, it is possible in
certain circumstances for a partnership such as ours to be treated as a
corporation for federal income tax purposes. Although we do not believe based
upon our current operations that we are so treated, a change in our business (or
a change in current law) could cause us to be treated as a corporation for
federal income tax purposes or otherwise subject us to taxation as an
entity.
If we
were treated as a corporation for federal income tax purposes, we would pay
federal income tax on our taxable income at the corporate tax rates, currently
at a maximum rate of 35 percent, and would likely pay state income tax at
varying rates. Distributions to you would generally be taxed again as corporate
distributions, and no income, gain, loss, deduction or credit would flow through
to you. Because a tax would be imposed on us as a corporation, our cash
available for distribution to our unitholders could be reduced. Therefore,
treatment of us as a corporation could result in a material reduction in the
anticipated cash flow and after-tax return to our unitholders and, therefore,
result in a substantial reduction in the value of our units.
Current
law or our business may change so as to cause us to be treated as a corporation
for federal income tax purposes or otherwise subject us to entity-level
taxation. In addition, because of widespread state budget deficits, several
states are evaluating ways to subject partnerships and limited liability
companies to entity-level taxation through the imposition of state income,
franchise or other forms of taxation. Imposition of such a tax on us by any such
state will reduce the cash available for distribution to the
unitholder.
Our
partnership agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation for federal, state
or local income tax purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the impact of that law on
us.
The
tax treatment of publicly traded partnerships or an investment in our Common
Units could be subject to potential legislative, judicial or administrative
changes and differing interpretations, possibly on a retroactive
basis.
The
present U.S. federal income tax treatment of publicly traded partnerships,
including us, or an investment in our Common Units may be modified by
administrative, legislative or judicial interpretation at any time. For example,
members of Congress have considered substantive changes to the existing U.S.
federal income tax laws that would have affected publicly traded partnerships.
Any modification to the U.S. federal income tax laws and interpretations thereof
may or may not be applied retroactively. Although the legislation considered
would not have appeared to affect our tax treatment as a partnership, we are
unable to predict whether any of these changes, or other proposals, will be
reconsidered or will ultimately be enacted. Any such changes could negatively
impact the value of an investment in our Common Units.
If
the IRS contests the federal income tax positions we take, the market for our
Common Units may be adversely impacted and the cost of any IRS contest will
reduce our cash available for distribution to you.
We have
not requested a ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes or any other matter affecting us.
The IRS may adopt positions that differ from the positions we take. It may be
necessary to resort to administrative or court proceedings to sustain some or
all of the positions we take. A court may not agree with some or all of the
positions we take. Any contest with the IRS may materially and adversely impact
the market for our Common Units and the price at which they trade. In addition,
our costs of any contest with the IRS will be borne indirectly by our
unitholders and our general partner because the costs will reduce our cash
available for distribution.
You
may be required to pay taxes on income from us even if you do not receive any
cash distributions from us.
You will
be required to pay federal income taxes and, in some cases, state and local
income taxes on your share of our taxable income, whether or not you receive
cash distributions from us. You may not receive cash distributions from us equal
to your share of our taxable income or even equal to the actual tax liability
that results from your share of our taxable income.
Tax
gain or loss on the disposition of our Common Units could be more or less than
expected because prior distributions in excess of allocations of income will
decrease your tax basis in your Common Units.
If you
sell any of your Common Units, you will recognize gain or loss equal to the
difference between the amount realized and your tax basis in those Common Units.
Prior distributions to you in excess of the total net taxable income you were
allocated for a Common Unit, which decreased your tax basis in that Common Unit,
will, in effect, become taxable income to you if the Common Unit is sold at a
price greater than your tax basis in that Common Unit, even if the price you
receive is less than your original cost. A substantial portion of the amount
realized, whether or not representing gain, may be ordinary income to you. In
addition, if you sell your units, you may incur a tax liability in excess of the
amount of cash you receive from the sale.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning our Common
Units that may result in adverse tax consequences to them.
Investment
in units by tax-exempt entities, including employee benefit plans and individual
retirement accounts (known as IRAs), and non-U.S. persons raises issues unique
to them. For example, virtually all of our income allocated to organizations
exempt from federal income tax, including individual retirement accounts and
other retirement plans, will be unrelated business taxable income and will be
taxable to such a unitholder. Our partnership agreement generally prohibits
non-U.S. persons from owning our units. However, if non-U.S. persons own our
units, distributions to such non-U.S. persons will be reduced by withholding
taxes imposed at the highest effective applicable tax rate, and such non-U.S.
persons will be required to file United States federal income tax returns and
pay tax on their share of our taxable income. If you are a tax exempt entity or
a non-U.S. person, you should consult your tax advisor before investing in our
common units.
We
will treat each purchaser of our units as having the same tax benefits without
regard to the Common Units purchased. The IRS may challenge this treatment,
which could adversely affect the value of the Common Units.
Because
we cannot match transferors and transferees of Common Units, we will adopt
depreciation and amortization positions that may not conform with all aspects of
existing Treasury Regulations. A successful IRS challenge to those positions
could adversely affect the amount of tax benefits available to our unitholders.
It also could affect the timing of these tax benefits or the amount of gain on
the sale of Common Units and could have a negative impact on the value of our
Common Units or result in audits of and adjustments to our unitholders’ tax
returns.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our Common Units each month based upon the ownership of our
Common Units on the first day of each month, instead of on the basis of the date
a particular Common Unit is transferred. The IRS may challenge this treatment,
and, if successful, we would be required to change the allocation of items of
income, gain, loss and deduction among our unitholders.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our Common Units each month based upon the ownership of our
Common Units on the first day of each month, instead of on the basis of the date
a particular Common Unit is transferred. The use of this proration method may
not be permitted under existing Treasury regulations. If the Internal Revenue
Service, or IRS, were to successfully challenge this method or new Treasury
Regulations were issued, we could be required to change the allocation of items
of income, gain, loss and deduction among our unitholders.
A
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of those units. If so, he would no
longer be treated for tax purposes as a partner with respect to those units
during the period of the loan and may recognize gain or loss from the
disposition.
Because a
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of the loaned units, he may no longer
be treated for tax purposes as a partner with respect to those units during the
period of the loan to the short seller and the unitholder may recognize gain or
loss from such disposition. Moreover, during the period of the loan to the short
seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by
the unitholder as to those units could be fully taxable as ordinary income.
Unitholders desiring to assure their status as partners and avoid the risk of
gain recognition from a loan to a short seller are urged to modify any
applicable brokerage account agreements to prohibit their brokers from borrowing
their units.
We
may adopt certain valuation methodologies that could result in a shift of
income, gain, loss and deduction between the general partner and the
unitholders. The IRS may successfully challenge this treatment, which could
adversely affect the value of the Common Units.
When we
issue additional units or engage in certain other transactions, we will
determine the fair market value of our assets and allocate any unrealized gain
or loss attributable to our assets to the capital accounts of our unitholders
and our general partner. Our methodology may be viewed as understating the value
of our assets. In that case, there may be a shift of income, gain, loss and
deduction between certain unitholders and the general partner, which may be
unfavorable to such unitholders. Moreover, under our valuation methods,
subsequent purchasers of Common Units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets
and a lesser portion allocated to our intangible assets. The IRS may challenge
our valuation methods, or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and allocations of income,
gain, loss and deduction between the general partner and certain of our
unitholders.
A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our unitholders. It also
could affect the amount of gain from our unitholders’ sale of Common Units and
could have a negative impact on the value of the Common Units or result in audit
adjustments to our unitholders’ tax returns without the benefit of additional
deductions.
The
sale or exchange of 50 percent or more of our capital and profits interests
during any twelve-month period will result in the termination of our partnership
for federal income tax purposes.
We will
be considered terminated for federal income tax purposes if there is a sale or
exchange of 50 percent or more of the total interests in our capital and profits
within a twelve-month period. For purposes of determining whether the 50 percent
threshold has been met, multiple sales of the same interest are counted only
once. Although Provident in June 2008 completed a transaction disposing of its
approximate 22 percent limited partner interest in us, because such transaction
was structured as a redemption of Provident's interest in us, it should not be
aggregated with any other sales or exchanges within a twelve-month period for
purposes of determining if the 50 percent threshold has been met. Our
termination would, among other things, result in the closing of our taxable year
for all unitholders, which would result in us filing two tax returns (and our
unitholders could receive two Schedules K-1) for one fiscal year and could
result in a significant deferral of depreciation deductions allowable in
computing our taxable income. In the case of a unitholder reporting on a taxable
year other than a fiscal year ending December 31, the closing of our taxable
year may also result in more than twelve months of our taxable income or loss
being includable in such unitholder’s taxable income for the year of
termination. Our termination currently would not affect our classification as a
partnership for federal income tax purposes, but instead, we would be treated as
a new partnership for tax purposes. If treated as a new partnership, we must
make new tax elections and could be subject to penalties if we are unable to
determine that a termination occurred.
You
may be subject to state and local taxes and return filing
requirements.
In
addition to federal income taxes, you will likely be subject to other taxes,
including state and local taxes, unincorporated business taxes and estate,
inheritance or intangible taxes that are imposed by the various jurisdictions in
which we conduct business or own property now or in the future, even if you do
not reside in any of those jurisdictions. You will likely be required to file
foreign, state and local income tax returns and pay state and local income taxes
in some or all of these jurisdictions. Further, you may be subject to penalties
for failure to comply with those requirements. We currently conduct business and
own property in California, Florida, Indiana, Kentucky, Michigan, Texas, and
Wyoming. Each of these states other than Wyoming, Texas and Florida currently
imposes a personal income tax on individuals, and all of these states impose an
income tax on corporations and other entities. As we make acquisitions or expand
our business, we may do business or own assets in other states in the future.
Some of the states may require us, or we may elect, to withhold a percentage of
income from amounts to be distributed to a common unitholder who is not a
resident of the state. Withholding, the amount of which may be greater or less
than a particular common unitholder's income tax liability to the state,
generally does not relieve a nonresident common unitholder from the obligation
to file an income tax return. Amounts withheld may be treated as if distributed
to common unitholders for purposes of determining the amounts distributed by us.
It is the responsibility of each unitholder to file all United States federal,
foreign, state and local tax returns that may be required of such
unitholder. None.
The
location and character of our crude oil and natural gas properties are described
above under Part I—Item 1 “—Business” in this report. Information required by
the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas
Operations”) is also contained in Part I—Item 1 “—Business” and on pages F-1 to
F-47 of the consolidated financial statements in this report.
On
October 31, 2008, Quicksilver, an owner of 40.56 percent of our Common Units,
instituted a lawsuit in the District Court of Tarrant County, Texas naming us as
a defendant along with BreitBurn GP, BOLP, BOGP, Randall H. Breitenbach, Halbert
S. Washburn, Gregory J. Moroney, Charles S. Weiss, Randall J. Findlay, Thomas W.
Buchanan, Grant D. Billing and Provident. On December 12, 2008, Quicksilver
filed an Amended Petition and asserted twelve different counts against the
various defendants. The primary claims are as follows: Quicksilver alleges 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 alleges 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
our Common Units in us. Finally, Quicksilver alleges 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 seeks a temporary and 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. The parties to the
lawsuit are engaged in discovery pursuant to an agreed scheduling order. On
February 17, 2009, we filed a motion for partial summary judgment which is
scheduled to be heard on March 26, 2009. A hearing on Quicksilver’s request for
a temporary injunction is scheduled for April 6, 2009.
We are
defending ourselves vigorously in connection with the allegations in the
lawsuit. Because this lawsuit still is at an early stage, we cannot predict the
manner and timing of the resolution of the lawsuit or its outcome, or estimate a
range of possible losses, if any, that could result in the event of an adverse
verdict in the lawsuit.
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 as mentioned above. 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 statutes to which we are subject.
No matter
was submitted to a vote of security holders during the fourth quarter of
2008. Our
Common Units began trading on the NASDAQ Global Select Market under the symbol
“BBEP” on October 4, 2006 in connection with our initial public offering. At
December 31, 2008, based upon information received from our transfer agent and
brokers and nominees, we had 9,374 common unitholders, including beneficial
owners of Common Units held in street name. The following table sets forth the
range of the daily intraday high and low sales prices per Common Unit and cash
distributions to common unitholders for the periods indicated. The last reported
sales price for our Common Units on the NASDAQ on February 27, 2009 was $6.25
per unit.
We intend
to make cash distributions to unitholders on a quarterly basis, although there
is no assurance as to the future cash distributions since they are dependent
upon future earnings, cash flows, capital requirements, financial condition and
other factors. Our credit agreement prohibits us from making cash distributions
if aggregated letters of credit and outstanding loan amounts exceed 90 percent
of our borrowing base. See Item 7 “—Management's Discussion and Analysis of
Financial Condition and Results of Operations—Liquidity and Capital
Resources—Credit Facility” and Note 11 to the consolidated financial statements
in this report.
Cash
distributions are made within 45 days after the end of each quarter to
unitholders of record on the applicable record date. Available cash, as defined
in our partnership agreement is all cash on hand, including cash from
borrowings, at the end of the quarter after the payment of our expenses and the
establishment of reserves for future capital expenditures and operational
needs.
A number
of factors have the potential to negatively impact us, and there is substantial
risk that the Board may in future quarters determine to reduce or suspend our
distributions. These factors include: a significant reduction in our
existing bank credit agreement borrowing base; certain covenants contained
in our existing bank credit agreement; unexpected defense and other costs
associated with our ongoing litigation with Quicksilver Resources, Inc.;
decreases in oil and natural gas prices; a decline in production due to
decreased capital spending; and the issues identified under “Cautionary
Statement Relevant to Forward – Looking Information” and in Part I—Item 1A
“—Risk Factors” in this report. Equity
Compensation Plan Information
The
following table sets forth certain information with respect to our equity
compensation plans as of December 31, 2008.
Unregistered
Sales of Equity Securities and Use of Proceeds
There
were no unregistered sales of equity securities during the fourth quarter of
2008.
Purchases
of Equity Securities by the Issuer and Affiliated Purchasers
There
were no purchases of our Common Units by us or any affiliated purchasers during
the fourth quarter of 2008. Common
Unit Performance Graph
The graph below compares our cumulative
total unitholder return on their Common Units from the period October 4, 2006 to
December 31, 2008, with the cumulative total returns over the same period of the
Russell 2000 index and a customized peer group that includes: Atlas Energy
Resources, LLC, Constellation Energy Partners LLC, Encore Energy Partners LP, EV
Energy Partners, L.P., Legacy Reserves LP, Linn Energy, LLC, Pioneer Southwest
Energy Partners L.P., Quest Energy Partners, L.P. and Vanguard Natural
Resources, LLC. The graph assumes that the value of the investment in our Common
Units, in the Russell 2000 index, and in the peer group index was $100 on
October 4, 2006. Cumulative return is computed assuming reinvestment of
dividends.
 The information in this report
appearing under the heading “Common Unit Performance Graph” is being furnished
pursuant to Item 2.01(e) of Regulation S-K and shall not be deemed to be
“soliciting material” or to be “filed” with the SEC or subject to Regulation 14A
or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the
liabilities of Section 18 of the Securities Exchange Act of 1934, as
amended.
Set forth
below is summary historical consolidated financial data for us, BEC and
BreitBurn Energy Company LLC, the predecessors of BreitBurn Energy Partners
L.P., as of the dates and for the periods indicated.
The
selected consolidated financial data presented as of and for the year ended
December 31, 2008, the year ended December 31, 2007 and the period from October
10, 2006 to December 31, 2006 is from our audited financial statements. The
selected historical consolidated financial data presented as of and for the
period from January 1, 2004 to June 15, 2004, the period from June 16, 2004 to
December 31, 2004, the year ended December 31, 2005, and the period from January
1, 2006 to October 9, 2006 is from the audited consolidated financial statements
of BEC and its predecessors. In connection with the initial public offering, BEC
contributed to our wholly owned subsidiaries certain fields in the Los Angeles
Basin in California, including its interests in the Santa Fe Springs, Rosecrans
and Brea Olinda Fields, substantially all of its oil and gas assets, liabilities
and operations located in the Wind River and Big Horn Basins in central Wyoming
and certain other assets and liabilities. We conduct our operations through our
wholly owned subsidiaries BreitBurn Operating L.P. (“BOLP”) and BOLP’s general
partner BreitBurn Operating GP, LLC (“BOGP”). BEC’s historical results of
operations include combined information for us and BEC, and thus may not be
indicative of our future results. In 2007, we completed a total of seven
acquisitions totaling approximately $1.7 billion, the largest of which was the
Quicksilver Acquisition for approximately $1.46 billion. In 2008, we acquired
Provident’s interest in BreitBurn Management, BreitBurn Corporation contributed
its interest in BreitBurn Management to us, and BreitBurn Management contributed
its interest in the General Partner to us, resulting in BreitBurn Management and
the General Partner becoming our wholly owned subsidiaries.
You
should read the following summary financial data in conjunction with Item 7
“—Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and our consolidated financial statements and related notes
appearing elsewhere in this report.
The
selected financial data table presents a non-GAAP financial measure, “Adjusted
EBITDA,” which we use in our business. This measure is not calculated or
presented in accordance with generally accepted accounting principles, or GAAP.
We explain this measure below and reconcile it to the most directly comparable
financial measure calculated and presented in accordance with GAAP. We define
Adjusted EBITDA 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. This definition is
different than the EBITDAX definition in our credit facility, as the Adjusted
EBITDAX attributable to our BEPI limited partner interest is excluded and is
instead substituted by the cash distribution received from BEPI.
We
believe the presentation of Adjusted EBITDA provides useful information to
investors to evaluate the operations of our business excluding certain items and
for the reasons set forth below. Adjusted EBITDA should not be considered an
alternative to net income, operating income, cash flow from operating activities
or any other measure of financial performance presented in accordance with GAAP.
Our Adjusted EBITDA may not be comparable to similarly titled measures of
another company because all companies may not calculate Adjusted EBITDA in the
same manner.
We use
Adjusted EBITDA to assess:
Selected
Financial Data
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