BreitBurn Energy Partners, L.P. 10-K 2009
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended December 31, 2008
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
Bcfe:> One billion cubic feet equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.
Boe:> One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil.
Boe/d: Boe per day.
Btu:> British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
development well:> A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
dry hole or well:> A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
exploitation:> A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
exploratory well:> A well drilled to find and produce oil and gas reserves that is not a development well.
field:> An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
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.
Mcfe:> One thousand cubic feet of natural gas equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.
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.
MMcfe:> One million cubic feet of natural gas equivalent, determined using the ratio of one Bbl of crude oil to six Mcf of natural gas.
MMcfe/d:> One million cubic feet of natural gas equivalent per day, determined using the ratio of one Bbl of crude oil to six Mcf 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.
NGLs:> The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
oil: Crude oil, condensate and natural gas liquids.
productive well:> A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
proved developed reserves:> Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
proved reserves:> The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
proved undeveloped reserves or PUDs:> Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
recompletion:> The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
reserve:> That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination.
reservoir:> A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
standardized measure:> The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10 percent per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions.
undeveloped acreage:> Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
West Texas Intermediate (“WTI”):> Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude oil.
working interest:> The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
As of December 31, 2008, we had no delivery commitments.
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.
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.
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.
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.
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.
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.
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.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
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