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BreitBurn Energy Partners, L.P. 10-K 2007

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

x  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

or

o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-33055

BreitBurn Energy Partners L.P.

(Exact name of registrant as specified in its charter)

Delaware

 

74-3169953

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

Identification Number)

 

 

 

515 South Flower Street, Suite 4800

 

 

Los Angeles, California

 

90071

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code: (213) 225-5900

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 x

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 x

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 x     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.      o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one):

Large accelerated filer o     Accelerated filer o     Non-accelerated filer x

Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o     No x

As of April 2, 2007, there were 21,975,758 Common Units outstanding.  The aggregate market value of the Units held by non-affiliates of the registrant (31.40%) was approximately $225 million for the Common Units on March 27, 2007 based on $32.69 per unit, the last reported sales price of the units on the Nasdaq Global Select Market on such date.

Documents Incorporated By Reference: None

 




BreitBurn Energy Partners L.P. and Subsidiaries

TABLE OF CONTENTS

 

 

 

Page No.

 

 

Glossary

 

1

 

 

Cautionary Statements Relevant to Forward-Looking Information for the Purpose of “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

 

4

 

 

PART I

 

 

 

 

 

 

 

Item 1.

 

Business.

 

5

Item 1A

 

Risk Factors

 

18

Item 1B.

 

Unresolved Staff Comments

 

34

Item 2.

 

Properties.

 

34

Item 3.

 

Legal Proceedings

 

34

Item 4.

 

Submission of Matters to a Vote of Security Holders

 

34

 

 

 

 

 

 

 

PART II

 

 

 

 

 

 

 

Item 5.

 

Market For Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities.

 

35

Item 6.

 

Selected Financial Data.

 

37

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

40

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk.

 

51

Item 8.

 

Financial Statements and Supplementary Data.

 

52

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

 

52

Item 9A.

 

Controls and Procedures.

 

53

Item 9B.

 

Other Information

 

54

 

 

 

 

 

 

 

PART III

 

 

 

 

 

 

 

Item 10.

 

Directors and Executive Officers of Our General Partner.

 

54

Item 11.

 

Executive Compensation.

 

58

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

 

84

Item13.

 

Certain Relationships and Related Transactions and Director Independence.

 

85

Item 14.

 

Principal Accountant Fees and Services.

 

87

 

 

 

 

 

 

 

PART IV

 

 

 

 

 

 

 

Item 15.

 

Exhibits and Financial Statement Schedules.

 

88

 




GLOSSARY OF OIL AND GAS TERMS

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.

        Bbl:    One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

        Bcf:    One billion cubic feet.

        Boe:    One barrel of oil equivalent, determined using a 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.

        Mcf:    One thousand cubic feet.

        MMBbls:    One million barrels of crude oil or other liquid hydrocarbons.

        MMBoe:    One million barrels of oil equivalent.

        MMBtu:    One million British thermal units.

        MMcf:    One million cubic feet.

        MMMBtu:    One billion British thermal units.

        net acres or net wells:    The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

1




        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% 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.

2




GLOSSARY OF OIL AND GAS TERMS (Continued)

        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.

        workover:    Operations on a producing well to restore or increase 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 “BreitBurn Energy” 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.  References in this filing to “Provident” refer to Provident Energy Trust, the ultimate parent company of the majority owner of our general partner, and its wholly owned subsidiaries.  References in this filing to “Pro GP” refer to Pro GP Corp, BreitBurn Energy’s general 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. References in this filing to “Partnership Properties” or “our properties” refer to, as of December 31, 2006, the oil and gas properties contributed to BreitBurn Energy Partners L.P. and its subsidiaries by BreitBurn Energy Company L.P. in connection with the Partnership’s 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 the effective date of January 1, 2007, “Partnership Properties” or “our properties” include an acquisition in the Lazy JL Field in the Permian Basin in West Texas.

3




CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION

FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE

PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This cautionary note is provided pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  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” and words of similar meaning.  Examples of these types of statements include those regarding:

·                  estimates of oil and gas reserves recoverable in future years and related future net cash flows,

·                  assessments of hydrocarbon formations and potential resources,

·                  exploration, development and other plans for future operations,

·                  production rates, timing and costs and sales volumes and prices,

·                  revenues, earnings, cash flows, liabilities, capital expenditures and other financial measures,

·                  anticipated liquidity,

·                  the amount and timing of environmental and other contingent liabilities, and

·                  other statements regarding future events, conditions or outcomes.

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, for example:

·                  the volatility of oil and natural gas prices, including price discounts and differentials to NYMEX WTI;

·                  discovery, estimation, development and replacement of oil and natural gas reserves;

·                  cash flow, liquidity and financial position;

·                  unknown environmental issues;

·                  business and financial strategy;

·                  amount, nature and timing of capital expenditures, including future development costs;

·                  availability and terms of capital;

·                  timing and amount of future production of oil and natural gas;

·                  availability of drilling and production equipment;

·                  operating costs and other expenses;

·                  prospect development and property acquisitions;

·                  marketing of oil and natural gas;

·                  unexpected problems with wells or other equipment;

·                  competition in the oil and natural gas industry;

·                  the impact of weather and the occurrence of natural disasters such as fires, floods, earthquakes and other catastrophic events and natural disasters;

·                  governmental regulation of the oil and natural gas industry;

·                  developments in oil-producing and natural gas-producing countries;

·                  strategic plans, expectations and objectives for future operations; and

·                  other factors discussed in our Risk Factors section in Part I, Item 1A of this report.

Copies of our filings with the Securities and Exchange Commission (“SEC”) are available by calling us at (213) 225-5900 or from the SEC by calling (800) SEC-0330.  The reports are also available on our web site, http://www.breitburn.com/.  Alternatively, you may access these reports at the SEC’s Internet Web site: http://www.sec.gov/.  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.

4




PART I

ITEM 1.  BUSINESS.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties.  Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders.  Our assets consist primarily of producing and non-producing crude oil reserves located in the Los Angeles Basin in California, the Wind River and Big Horn Basins in central Wyoming and the Permian Basin in West Texas.  We are a Delaware limited partnership formed on March 23, 2006.  We conduct our operations through a wholly owned subsidiary, BreitBurn Operating L.P. (“OLP”) and OLP’s general partner BreitBurn Operating GP, LLC (“OGP”).  The Partnership owns directly or indirectly all of the ownership interests in its operating subsidiaries.

On October 10, 2006, we completed our initial public offering of 6,000,000 units representing limited partner interests in the Partnership at $18.50 per unit, or $17.205 per unit after payment of the underwriting discount.  On November 6, 2006, we also completed the sale of an additional 900,000 common units to cover over-allotments in the initial public offering.  The public unitholders ownership represents an aggregate 31.40% limited partner interest.

In connection with the initial public offering, BreitBurn Energy contributed to the Partnership’s 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, and the Wind River and Big Horn Basins in central Wyoming.

The Partnership’s predecessor, BreitBurn Energy, is a 95.55% owned indirect subsidiary of Provident, a publicly traded Canadian energy trust.  Provident acquired its interest in BreitBurn Energy in June 2004.  BreitBurn Corporation owns the remaining 4.45% in BreitBurn Energy.  BreitBurn Corporation, a predecessor of BreitBurn Energy, was formed in May 1988 by Randall H. Breitenbach and Halbert S. Washburn.  Messrs. Breitenbach and Washburn are the co-CEOs of our general partner.  Please read “–Our Relationship with Provident Energy Trust and BreitBurn Corporation.”

Our 2% general partner interest is held by BreitBurn GP, LLC, a Delaware limited liability company, formed on March 23, 2006.  The board of directors of our general partner has sole responsibility for conducting our business and managing our operations.

Our Relationship with Provident Energy Trust and BreitBurn Corporation

Provident, a publicly traded Canadian energy trust owns, acquires and manages oil and gas producing properties and midstream infrastructure assets.  Provident and BreitBurn Corporation have a significant interest in us through their ownership in the aggregate of 15,075,758 common units, representing a 68.60% limited partner interest and a 2% general partner interest.

We are Provident’s primary acquisition vehicle for its upstream operations in the United States.  We are pursuing strategic acquisitions independently.  We also have the opportunity to participate jointly with Provident and its subsidiaries in reviewing potential U.S. acquisitions, including transactions that we would be unable to pursue on our own.  Moreover, we have a right of first offer with respect to the sale by Provident and its affiliates of any of their upstream oil and gas properties in the United States, and we have a preferential right over Provident to acquire any third party upstream oil and gas properties in the United States.  Provident has a preferential right to acquire any third party midstream or downstream assets located in the United States and any third party upstream oil and gas properties or midstream or downstream assets outside the United States, and Provident may offer us the right to participate in any such acquisition.  These obligations run until such time as Provident and its affiliates no longer control our general partner.

5




The Partnership has no employees.  We entered into an Administrative Services Agreement with BreitBurn Management, which is owned 95.55% by Provident and 4.45% by BreitBurn Corporation, pursuant to which BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering.  All our executives are employees of BreitBurn Management and perform services for both us and BreitBurn Energy.

While our relationship with Provident and its affiliates is a significant attribute, it is also a potential source of conflicts.  We entered into an Omnibus Agreement with Provident and BreitBurn Energy, which sets forth certain agreements with respect to conflicts of interest (see Item 1A of this report – Risks Related to Our Structure).

Organizational Chart

The following diagram depicts our organizational structure as of April 2, 2007:


(1)          Provident owns its interests in us, our general partner and BreitBurn Management through wholly-owned subsidiaries.

(2)          Provident and BreitBurn Corporation own 95.55% and 4.45%, respectively, of our predecessor BreitBurn Energy, which continues to own oil and gas properties in California and other assets that were not contributed to us in connection with our initial public offering.

(3)          BreitBurn Corporation is owned by Messrs. Breitenbach and Washburn, the co-CEO’s of our general partner.

6




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:

·                  Acquire long-lived assets with low-risk exploitation and development opportunities;

·                  Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to maximize reserve recovery;

·                  Utilize the benefits of our relationship with Provident to pursue acquisitions; and

·                  Reduce cash flow volatility through commodity price derivatives.

Operations

Properties

On October 10, 2006, BreitBurn Energy contributed to us the Partnership Properties, which include 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.  The following discussion presents the Partnership Properties as if the Partnership owned the properties for the full year, which is provided for better comparability of the Properties’ operational performance.  The Partnership’s financial results reflect activity from October 10, 2006 to December 31, 2006.

As of December 31, 2006, the total estimated proved reserves attributable to the Partnership Properties were 30.7 MMBoe, of which approximately 98% were oil and 93% were classified as proved developed reserves.  Of these total estimated proved reserves 57% were located in California and 43% were located in Wyoming.

The following table summarizes reserves and production for our principal Partnership Properties within our operating regions:

 

 

At December 31, 2006

 

October 10,
2006 thru
December 31,
2006

 

 

 

Estimated Net

 

Percent

 

Estimated

 

Average

 

Average

 

 

 

Proved

 

of

 

Proved Developed

 

Daily

 

Daily

 

Field Name

 

Reserves (1)

 

Total

 

Reserves

 

Production (2)

 

Production

 

 

 

(MMBoe)

 

 

 

(MMBoe)

 

(Boe/d)

 

(Boe/d)

 

California — Los Angeles Basin

 

 

 

 

 

 

 

 

 

 

 

Santa Fe Springs

 

11.9

 

39

%

11.7

 

1,700

 

1,664

 

Rosecrans

 

2.7

 

9

%

2.7

 

392

 

374

 

Brea Olinda

 

1.9

 

6

%

1.9

 

234

 

234

 

Other

 

1.0

 

3

%

1.0

 

154

 

160

 

Wyoming — Wind River and Big Horn Basins

 

 

 

 

 

 

 

 

 

 

 

Black Mountain

 

5.3

 

17

%

4.3

 

489

 

483

 

Gebo

 

2.9

 

10

%

2.6

 

701

 

787

 

North Sunshine

 

2.8

 

9

%

2.1

 

300

 

336

 

Hidden Dome

 

1.0

 

3

%

1.0

 

184

 

181

 

Other (3)

 

1.2

 

4

%

1.1

 

326

 

353

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

30.7

 

100

%

28.4

 

4,480

 

4,572

 

 


(1)          Our estimated net proved reserves were determined using $60.85 per barrel of oil and $5.64 per MMBtu for natural gas.  For additional proved reserves details, see Note 20 of our consolidated financial statements in this report.

(2)          Reflects average daily production for the entire year.

(3)          Includes additional Wyoming properties, one of which is outside the Wind River and Big Horn Basins.

7




Pursuant to the Administrative Services Agreement, BreitBurn Management manages all of our properties.  BreitBurn Management employs production and reservoir engineers, geologists and other specialists, as well as field personnel.  We physically operate approximately 99% of the total wells in which we have interests.  As operator, we design and manage the development of a well 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.

California

Los Angeles Basin, California

Our operations in California are concentrated in several large, complex oil fields within the Los Angeles Basin.  For the year ended December 31, 2006, our California production was approximately 2,480 Boe per day and estimated proved reserves as of December 31, 2006 were 17.5 MMBoe.  Our three largest fields, the Santa Fe Springs Field, the Rosecrans Field and the Brea Olinda Field, were acquired by BreitBurn Energy from Texaco in 1999.  These three fields make up 95% of our production and 94.5% of our estimated proved reserves in California.

Santa Fe Springs Field – Our largest property in the Los Angeles Basin measured by current production as well as by proved reserves, is the Santa Fe Springs Field.  We operate 97 active producing wells in the Santa Fe Springs Field and own on average a 99.6% working interest and a 92.9% net revenue 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 2006, net production was approximately 1,700 Boe per day and our estimated proved reserves as of December 31, 2006 were 11.9 MMBoe, of which 99% was proved developed.

Rosecrans Field – Our second largest property in the Los Angeles Basin is the Rosecrans Field.  We operate 42 wells in the Rosecrans Field and own a 99.5% working interest and a 91% net revenue interest.  The Rosecrans Field has produced from several productive sands ranging in depth from 3,700 feet to 10,000 feet.  The producing zones are the Padelford, Maxwell, Hoge, Zins and the O’dea.  In 2006, net production was approximately 392 Boe per day and our estimated proved reserves as of December 31, 2006 were 2.7 MMBoe.

Brea Olinda Field – Our third largest property in the Los Angeles Basin is the Brea Olinda Field.  We operate 75 active producing wells at the Brea Olinda property and own a 100% working and net revenue interest.  The Brea Olinda Field produces from the shallow Pliocene formations at a depth of approximately 1,000 feet to the deeper Miocene formation at up to 6,000 feet.  In 2006, net production was approximately 234 Boe per day and our estimated proved reserves as of December 31, 2006 were 1.9 MMBoe.

Other California Fields – Our other fields include the Alamitos lease of the Seal Beach Field, which has 12 wells producing approximately 62 net Boe per day from the Mcgrath and Wasem formations at approximately 7,000 feet, and the Recreation Park lease of the Long Beach Field, which has 7 wells producing approximately 49 net Boe per day from the same zones as the Alamitos lease but approximately 1,000 feet deeper.

Wyoming

Wind River and Big Horn Basins, Wyoming

Our properties in the Wind River and Big Horn Basins were acquired in March 2005, when our predecessor, BreitBurn Energy, acquired Nautilus Resources, LLC (‘‘Nautilus’’).  For the year ended December 31, 2006, net production was approximately 2,000 Boe per day and estimated proved reserves totaled 13.2 MMBoe.  Four fields, Black Mountain, Gebo, North Sunshine and Hidden Dome, made up 84% of our 2006 production and 91% of our 2006 estimated proved reserves in Wyoming.

Black Mountain Field – We operate 57 wells in the Black Mountain Field and hold a 98% working interest and 87% net revenue interest.  We currently produce from 43 active production wells.  Production is from the Tensleep, Amsden and Madison formations with the producing zones as shallow as 2,000 feet and as deep as 4,500 feet.

8




Net production was approximately 490 Boe per day in 2006 and our estimated proved reserves as of December 31, 2006 were 5.3 MMBoe, of which 80% was proved developed.

Gebo Field – We operate 71 wells in the Gebo Field and hold a 100% working interest and 86% net revenue interest.  Production is from the Tensleep formations from 3,000 to 5,000 feet deep.  In 2006, net production was approximately 700 Boe per day and our estimated proved reserves as of December 31, 2006 were 2.9 MMBoe.

North Sunshine Field – We operate 27 wells in the North Sunshine Field and hold a 100% working interest and 87% net revenue interest.  Production is from the Phosphoria at 3,000 feet and the Tensleep at about 3,500 feet.  In 2006, net production was approximately 300 Boe per day and our estimated proved reserves as of December 31, 2006 were 2.8 MMBoe, of which 75% was proved developed.  In 2006, we drilled 4 successful crude oil wells.

Hidden Dome Field – We operate 28 wells in the Hidden Dome Field and hold a 100% working interest and 90% net revenue interest.  Production is from the Frontier and Tensleep formations with the producing zones as shallow as 1,200 feet and as deep as 4,500 feet.  In 2006, net production was approximately 184 Boe per day and our estimated proved reserves as of December 31, 2006 were 1.0 MMBoe.

Other Wyoming Fields – Our other fields include the Sheldon Dome Field and Rolf Lake Fields in Fremont County, where we operate 26 wells in the Frontier to the Tensleep formations at depths up to 7,300 feet.  In 2006, our Sheldon Dome and Rolf Lake fields produced approximately 154 net Boe per day and 64 net Boe per day, respectively.  We also operate six 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 2006, net production from the Lost Dome Field was approximately 60 Boe per day.  The other two fields we operate are the West Oregon Basin and Half Moon Fields in Park County, with seven total wells with five producing wells.  We produced approximately 48 net Boe per day between the two fields from the Phosphoria formation at approximately 4,000 feet.

Productive Wells

The following table sets forth information for the Partnership Properties at December 31, 2006, 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 producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in the gross wells.

 

Oil Wells

 

Gas Wells

 

 

 

Gross

 

Net WI

 

Gross

 

Net WI

 

Operated

 

637

 

625

 

5

 

5

 

Non-operated

 

1

 

1

 

0

 

0

 

Total

 

638

 

626

 

5

 

5

 

 

Developed and Undeveloped Acreage

The following table sets forth information for the Partnership Properties as of December 31, 2006 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.

 

Developed Acreage

 

Undeveloped Acreage

 

Total Acreage

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Operated

 

13,660

 

13,292

 

5,911

 

5,911

 

19,571

 

19,203

 

Non-operated

 

 

 

 

 

 

 

Total

 

13,660

 

13,292

 

5,911

 

5,911

 

19,571

 

19,203

 

 

9




Drilling Activity

Our drilling activity and production optimization projects are on lower risk, development properties.  The following table sets forth information for the Partnership Properties with respect to wells completed during the three years ended December 31, 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.

 

2006

 

2005

 

2004

 

Gross wells:

 

 

 

 

 

 

 

Productive

 

7

 

6

 

2

 

Dry

 

0

 

1

 

0

 

 

 

7

 

7

 

2

 

Net Development wells:

 

 

 

 

 

 

 

Productive

 

7

 

6

 

2

 

Dry

 

0

 

1

 

0

 

 

 

7

 

7

 

2

 

 

We did not have any wells in process of drilling at December 31, 2006.

Delivery Commitments

We have no delivery commitments.

Sales Contracts

We have a portfolio of crude oil sales contracts with large, established refiners.  The following table sets forth our crude oil sales by purchaser for the year ended December 31, 2006:

Purchaser

 

Source of Production

 

% of Our Total
 Volumes 
Purchased

 

 

 

 

 

 

 

California:

 

 

 

 

 

ConocoPhillips

 

Santa Fe Springs

 

39

%

Paramount Petroleum

 

Rosecrans

 

9

%

Big West of California

 

Santa Fe Springs,

Rosecrans, Brea Olinda,

Seal Beach (Alamitos),

Recreation Park

 

8

%

Wyoming:

 

 

 

 

 

Marathon Oil

 

Black Mountain, Gebo,

North Sunshine, Hidden Dome,

Sheldon Dome,

Rolff Lake, West Oregon Basin, Halfmoon

 

43

%

Shell Trading (US) Company

 

Lost Dome

 

1

%

 

 

 

 

 

 

Total

 

 

 

100

%

 

10




California.  We sell our California crude oil production pursuant to short-term (one to 12 month) contracts with automatic renewal provisions.  The crude oil is priced using a basket of the monthly average refiner postings for the Buena Vista crude oil reference stream in southern California, corrected for actual quality delivered using the average of the quality scales in effect for the refiners to whom we sell.  We receive a market premium above those postings ranging from $0.10 to $0.80 per barrel.

Wyoming.  Marathon Oil purchases Wyoming crude oil from us under two contracts, one of which was entered into with Nautilus in 2003.  The crude oil is priced using a basket of the monthly average refiner postings for the Canadian Bow River heavy oil reference stream at Hardisty, Alberta, corrected for actual gravity delivered against 22 API reference quality crude oil, using ConocoPhillips’ sour gravity quality scales in effect.  We receive a market premium above these postings ranging from $0.25 to $1.81 per barrel.  Shell Trading (US) Company purchases Wyoming crude oil from us pursuant to a short-term contract with an automatic renewal provision.  The crude oil is priced using a $2.80 premium above a basket of the monthly average refiner postings for the Canadian Bow River heavy oil reference stream at Hardisty, Alberta.

Marathon Oil has a call option to purchase the oil we produce from our Black Mountain, Gebo, Hidden Dome and North Sunshine fields through May 31, 2010.  Under the terms of the call option, we may seek bids from bona fide, arm’s-length third-party purchasers.  If Marathon Oil matches the third-party bid, we are obligated to sell our production to Marathon Oil.

Crude Oil Prices

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 greater distance to market.  Our Los Angeles Basin crude is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX WTI. Our Wyoming crude, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX because of its distance from a major refining market and the fact that it is priced relative to the Bow River benchmark for Canadian heavy sour crude oil, which has historically traded at a significant discount to WTI.  For the year ended December 31, 2006, the average discount to NYMEX WTI for our California crude oil and our Wyoming crude oil was $4.06 per barrel and $20.47 per barrel, respectively.

We enter into derivative transactions to reduce the impact of crude oil price volatility on our cash flow from operations.  Currently, we use a combination of fixed price swap and option arrangements to economically hedge NYMEX crude oil prices.  By removing the price volatility from a significant portion of our crude oil production, we have mitigated, but not eliminated, the potential effects of changing crude oil prices on our cash flow from operations for those periods.  See Item 7A “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Quantitative and Qualitative Disclosure About Market Risk.”

Derivative Activity

We enter into derivative transactions with unaffiliated third parties with respect to crude oil prices in order to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in commodity prices.  For a more detailed discussion of our derivative activities, read Item 7A “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” and “—Quantitative and Qualitative Disclosures About Market Risk.”

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Recent Acquisitions

On January 23, 2007, through a wholly owned subsidiary, we completed the purchase of certain oil and gas properties including related property and equipment, known as the “Lazy JL Field” in the Permian Basin of West Texas, including related property and equipment from Voyager Gas Corporation (“Voyager”).  The purchase price for this acquisition was approximately $29.0 million in cash, and was financed through borrowings under the Partnership’s existing revolving credit facility.  The acquisition was effective as of January 1, 2007.

Lazy JL Field has total proved reserves of approximately 2 MMBOE and a reserve life index in excess of 18 years.  We have a 100% working interest in the field and a 75% net revenue interest.  Current net production is approximately 300 Bbl/d.  The field is 98% oil and oil quality averaged 38 degrees API.  We have entered into derivative transactions to cover approximately 80% of expected production at $59.25 per barrel through 2009.

This acquisition is consistent with our strategy of acquiring long-lived assets with predictable production from established fields.  By adding these properties, we geographically diversified our asset base and established a presence in the Permian Basin — an area where the Partnership sees additional consolidation opportunities.  We continue to actively pursue other attractive acquisition targets that fit our business model and which are capable of generating incremental cash flow for our unitholders.

Competition

The oil and gas industry is highly competitive.  We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment 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.

We are also affected by competition for drilling rigs and the availability of related equipment.  In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, 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.

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.  Our oil properties are 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.

The title to the Brea Olinda Field that BreitBurn Energy acquired from Texaco in 1999 is to be conveyed to us upon the execution of an official deed.  Since 1999, BreitBurn Energy has held beneficial title to the Brea Olinda Field, including the contractual right to all revenue from production.  As a precautionary step and in order to avoid being in the chain of legal title with respect to a number of surface interests previously sold by the seller (Texaco) for development but not then yet conveyed out, BreitBurn Energy required that Texaco first assign out those surface fee property interests prior to finally assigning technical legal title to the remaining oil and gas interests to BreitBurn Energy.  Those prerequisite assignments have now been made by Texaco and BreitBurn is negotiating the final conveyance language for the transfer of the remaining bare legal title to merge with its existing beneficial title.

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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.  We entered into a Surface Operating Agreement to provide that BreitBurn Energy and BreitBurn Corporation continue to be responsible for the surface operations of one property.  See “Item 13. Certain Relationships and Related Party Transactions.”

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling activities and other operations in certain areas of Wyoming 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:

·                  require the acquisition of various permits before drilling commences;

·                  enjoin some or all of the operations of facilities deemed in non-compliance with permits;

·                  restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling, production and transportation activities;

·                  limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

·                  require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

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.

13




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.  Spill prevention, control, and countermeasure requirements of federal laws require 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 addresses three principal areas of oil pollution—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, 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 oil spills.

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.

National Environmental Policy Act.  Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA.  NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment.  In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.  All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA.  This process has the potential to delay the development of oil and natural gas projects.

14




Pipeline Safety.  Some of our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”) and the California State Fire Marshal pursuant to applicable pipeline safety laws. The DOT, through the Office of Pipeline Safety, recently promulgated a series of rules which require pipeline operators to develop pipeline integrity management programs for transportation pipelines located in “high consequence areas.”  “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline.  Integrity management program elements include requirements for baseline assessments to identify potential threats to each pipeline segment, reassessments, and reporting and recordkeeping.  We currently operate pipelines located in high consequence areas and have completed baseline assessments of our oil pipelines and will complete our baseline assessment of our natural gas pipeline in the second quarter of 2007.

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.

The Kyoto Protocol to the United Nations Framework Convention on Climate Change, or the Protocol, became effective in February 2005.  Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming.  The United States is not currently a participant in the Protocol, and Congress has not actively considered recent proposed legislation directed at reducing greenhouse gas emissions.  However, the State of California recently adopted legislation, referred to as the California Global Warming Solutions Act of 2006 that requires a 25% reduction in greenhouse gas emissions by 2020.  This legislation requires the California Air Resources Board to adopt regulations by 2012 that limit emissions of greenhouse gases that are not yet already restricted, and that provide for gradual reductions in emissions until an overall reduction of 25% from all emission sources in California is achieved by 2020.  The legislation allows sources that are unable to reduce their emissions by 25% to purchase credits from sources that are able to do so.  Other states have also adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants.  The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations.  It is not possible, at this time, to estimate accurately how regulations to be adopted by the California Air Resources Board by 2012 or that may be adopted by other states to address greenhouse gas emissions would impact our business.

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, 2006.  Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2007.  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.  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.

15




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.

Oil 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 location of wells;

·                  the method of drilling and casing wells;

·                  the surface use and restoration of properties upon which wells are drilled;

·                  the plugging and abandoning of wells; and

·                  notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties.  Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases.  In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties.  In addition, some state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.  These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill.  Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Regulation.  The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission.  Federal and state regulations govern the price and terms for access to natural gas pipeline transportation.  The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation.  We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.  Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Regulation.  The various states regulate the drilling for, and the production, gathering and sale 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% 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% of the value of the gross product extracted.  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.

16




Employees

Neither we, our subsidiaries nor our general partner have employees.  Through an Administrative Services Agreement with BreitBurn Management, BreitBurn Management operates our assets and performs other administrative services for us such as accounting, finance, land, legal and engineering.  As of December 31, 2006, BreitBurn Management had approximately 150 full time employees.  BreitBurn Management provides service to us as well as our predecessor, BreitBurn Energy.  None of these employees are represented by labor unions or covered by any collective bargaining agreement.  We believe that relations with these employees are satisfactory.

Offices

BreitBurn Management currently leases approximately 27,280 square feet of office space in California at 515 S. Flower St., Suite #4800, Los Angeles, California 90071, where our principal offices are located.  The lease for the California office expires in February 2016.  In addition to the office space in Los Angeles, BreitBurn Management maintains offices in Cody, Wyoming and Houston, Texas.  We use these offices under our Administrative Services Agreement with BreitBurn Management.

17




ITEM 1A.  RISK FACTORS

Risks Related to Our Business

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.

We may not have sufficient cash flow from operations to pay quarterly distributions on our common units following establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient available cash each quarter to pay the quarterly distribution of $0.4125 per unit that we anticipated paying through September 2007 or any other amount.

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.  We intend to reserve a substantial portion of our cash generated from operations to develop our oil and gas properties and to acquire additional oil and gas properties in order to maintain and grow our level of oil and 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:

·                  the amount of oil and natural gas we produce;

·                  demand for and price of our oil and natural gas;

·                  continued development of oil and gas wells and proved undeveloped properties;

·                  the level of our operating costs, including reimbursement of expenses to our general partner;

·                  prevailing economic conditions;

·                  the level of competition we face;

·                  fuel conservation measures;

·                  alternate fuel requirements;

·                  government regulation and taxation; and

·                  technical advances in fuel economy and energy generation devices.

In addition, the actual amount of cash that we will have available for distribution will depend on other factors, including:

·                  the level of our capital expenditures;

·                  our ability to make borrowings under our credit facility to pay distributions;

·                  sources of cash used to fund acquisitions;

·                  debt service requirements and restrictions on distributions contained in our credit facility or future debt agreements;

·                  fluctuations in our working capital needs;

·                  general and administrative expenses, including expenses we incur as a result of being a public company;

·                  cash settlement of hedging positions;

·                  timing and collectibility of receivables; and

·                  the amount of cash reserves, which we expect to be substantial, established by our general partner for the proper conduct of our business.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

18




We are unlikely to be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base.  If we do not set aside sufficient cash reserves or make sufficient cash 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 our asset base decreases and we do not reduce our distributions, 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.

Producing oil and 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, 2006 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 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 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 substantial amounts of 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.

If our reserves decrease and we do not reduce our distribution, then a portion of the distribution 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.

To fund our growth 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.

Use of cash generated from operations 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 may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by 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.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

The amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items.  As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

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Oil and gas prices are very volatile.  A decline in commodity prices will cause a decline in our cash flow from operations, which may force us to reduce our distributions or cease paying distributions altogether.  Price differentials between NYMEX WTI prices and what we actually receive are also historically very volatile.

The oil and gas markets are very volatile, and we cannot predict future oil and gas prices.  Prices for oil and gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

·                  domestic and foreign supply of and demand for oil and gas;

·                  market prices of oil and gas;

·                  level of consumer product demand;

·                  weather conditions;

·                  overall domestic and global economic conditions;

·                  political and economic conditions in oil and gas producing countries, including those in the Middle East and South America;

·                  actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;

·                  impact of the U.S. dollar exchange rates on oil and gas prices;

·                  technological advances affecting energy consumption;

·                  domestic and foreign governmental regulations and taxation;

·                  the impact of energy conservation efforts;

·                  the proximity, capacity, cost and availability of oil and gas pipelines and other transportation facilities; and

·                  the price and availability of alternative fuels.

In the past, prices of oil and gas have been extremely volatile, and we expect this volatility to continue.  For example, during the year ended December 31, 2006, the NYMEX WTI price ranged from a high of $77.03 per barrel to a low of $55.81 per barrel, while the Henry Hub natural gas price ranged from a high of $9.92 per MMBtu to a low of $3.67 per MMBtu.  For the year ended December 31, 2005, the NYMEX WTI oil price ranged from a high of $70.50 per barrel to a low of $41.60 per barrel, while the NYMEX Henry Hub natural gas price ranged from a high of $15.52 per MMBtu to a low of $5.17 per MMBtu.

Price discounts or differentials between NYMEX WTI prices and what we actually receive are also historically very volatile.  For instance, during calendar year 2006, the price discount from NYMEX WTI applicable to us or BreitBurn Energy for Wyoming production varied from $11.38 to $31.87 per barrel.  This represented a percentage of the total price per barrel ranging from 16% to 51%.  For California crude oil, the discount varied from $2.99 to $4.53, which was 5% to 7% of the total price per barrel.

Our revenue, profitability and cash flow depend upon the prices and demand for oil and 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 the value of our reserves, because declines in oil and gas prices would reduce the amount of oil and gas that we can produce economically;

·                  reduce the amount of cash flow available for capital expenditures;

·                  limit our ability to borrow money or raise additional capital; and

·                  impair our ability to pay distributions.

If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during subsequent periods of lower commodity prices.

Future price declines may result in a write-down of our asset carrying values.

Declines in oil and gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves.  If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and 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 require a write-down.

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We 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 achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we currently and may in the future enter into derivative arrangements for a significant portion of our oil and gas production that could result in both realized and unrealized hedging losses.

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 based on NYMEX WTI prices, which may differ significantly from the actual crude oil 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.  Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk.”

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 of our 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:

·                  a counterparty may not perform its obligation under the applicable derivative instrument;

·                  there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

·                  the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

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 gas and assumptions concerning future oil and gas prices, production levels, and operating and development costs.  In estimating our level of oil and gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:

·                  future oil and gas prices;

·                  production levels;

·                  capital expenditures;

·                  operating and development costs;

·                  the effects of regulation;

·                  the accuracy and reliability of the underlying engineering and geologic data; and

·                  availability of funds.

If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and 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.

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For example, if oil prices at December 31, 2006 had been $5.00 less per barrel, then the standardized measure of our estimated proved reserves as of December 31, 2006 would have decreased by $52.6 million, from $312.5 million to $259.9 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 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 estimate.  However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:

·                  the actual prices we receive for oil and gas;

·                  our actual operating costs in producing oil and gas;

·                  the amount and timing of actual production;

·                  the amount and timing of our capital expenditures;

·                  supply of and demand for oil and gas; and

·                  changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and 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% discount factor we use when calculating discounted future net cash flows in compliance with the Financial Accounting Standards Board’s Statement of Financial Accounting Standards No. 69 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 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 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:

·                  high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;

·                  unexpected operational events and drilling conditions;

·                  reductions in oil and gas prices;

·                  limitations in the market for oil and gas;

·                  adverse weather conditions;

·                  facility or equipment malfunctions;

·                  equipment failures or accidents;

·                  title problems;

·                  pipe or cement failures;

·                  casing collapses;

·                  compliance with environmental and other governmental requirements;

·                  environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

·                  lost or damaged oilfield drilling and service tools;

·                  unusual or unexpected geological formations;

·                  loss of drilling fluid circulation;

·                  pressure or irregularities in formations;

·                  fires;

·                  natural disasters;

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·                  blowouts, surface craterings and explosions; and

·                  uncontrollable flows of oil, gas or well fluids.

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.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.

Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit.  We may be unable to make such acquisitions because we are:

·                  unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;

·                  unable to obtain financing for these acquisitions on economically acceptable terms; or

·                  outbid by competitors.

If we are unable to acquire properties containing proved reserves, our total level of proved reserves may decline as a result of our production, and we may be limited in our ability to increase or possibly even to maintain our level of cash distributions.

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

If we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit.  Any acquisition involves potential risks, including, among other things:

·                  the validity of our assumptions about reserves, future production, revenues and costs, including synergies;

·                  an inability to integrate successfully the businesses we acquire;

·                  a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

·                  a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

·                  the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

·                  the diversion of management’s attention from other business concerns;

·                  an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

·                  the incurrences of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;

·                  unforeseen difficulties encountered in operating in new geographic areas; and

·                  customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential.  Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

If our acquisitions do not generate expected increases in available cash per unit, our ability to increase or possibly even to maintain our level of cash may be adversely affected.

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Many of our leases are in mature fields that have produced large quantities of oil and gas to date.

Our assets are located in established fields in the Los Angeles Basin in California, the Wind River and Big Horn Basins in Wyoming and Permian Basin in West Texas.  As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil and gas to date.  As such, the primary risk to infill development drilling is partial depletion by offsetting wells.

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

We rely exclusively on sales of oil and gas that we produce.  Furthermore, all of our assets are located in California, Wyoming and Texas.  Due to our lack of diversification in asset type and location, an adverse development in the oil and gas business of these geographic areas would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse assets and locations.

We depend on two customers for a substantial amount of our sales.  If these customers reduce the volumes of oil and gas 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 2006, Marathon Oil accounted for approximately 43% of sales volumes from Partnership Properties, and ConocoPhillips accounted for approximately 39% of sales volumes from Partnership Properties.  The 2006 amounts represent sales to these customers from Partnership Properties, as if these properties were owned by the Partnership for the whole year.  For the year ended December 31, 2005, ConocoPhillips accounted for approximately 50% of total sales volumes, and Marathon Oil accounted for approximately 38% of our total sales volumes.

We may be unable to compete effectively with larger 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 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.  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.  These larger 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.  Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

We may incur substantial additional debt to enable us to pay our quarterly distributions, which may negatively affect our ability to execute on our business plan.

Our business requires a significant amount of capital expenditures to maintain and grow production levels.  In addition, volatility in commodity prices or other factors may reduce the amount of cash we actually generate in any particular quarter. As a consequence, we may be unable to pay a distribution at the initial distribution rate or the then-current distribution rate without borrowing under our credit facility.

When we borrow to pay distributions, we are distributing more cash than we are generating from our operations on a current basis.  This means that we are using a portion of our borrowing capacity under our credit facility to pay distributions rather than to maintain or expand our operations.  If we use borrowings under our credit facility to pay distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business.  Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to pay these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations.  If we borrow to pay distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.

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Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Our future indebtedness could have important consequences to us, including:

·                  our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisition or other purposes may be impaired or such financing may not be available on favorable terms;

·                  covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

·                  we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

·                  our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

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.

Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

The operating and financial restrictions and covenants in our credit facility restricts and any future financing agreements likely would 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 would restrict our ability to:

·                  incur indebtedness;

·                  grant liens;

·                  make certain acquisitions and investments;

·                  lease equipment;

·                  make capital expenditures above specified amounts;

·                  redeem or prepay other debt;

·                  make distributions to unitholders or repurchase units if aggregated letters of credit and outstanding loan amounts exceed 90% of our borrowing base;

·                  enter into transactions with affiliates; and

·                  enter into a merger, consolidation or sale of assets.

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.  If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.  If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, 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 agreement are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit agreement, the lenders can seek to foreclose on our assets.

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Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion.  Outstanding borrowings in excess of the borrowing base are required to be repaid immediately, or we are required to pledge other oil and gas properties as additional collateral.

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, 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, business interruption and general liability insurance at levels we believe are appropriate; however, 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.

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 and production 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 and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

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 “Business—Operations—Environmental Matters and Regulation” and “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.

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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 “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 maintain no 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.

Our Long-Term Incentive Compensation Plans can result in significant cash payments in the event that our unit price increases significantly during the calendar year.

Our expense incurred for management incentive plans can result in the Partnership recognizing significant compensation expense if the Partnership’s units also significantly increase in value.  We estimate that each $1.00 increase in the trading price of our common units above $24.10 (which was our closing unit price for the last trading day of 2006) would increase the amount of our compensation expense for 2007 by approximately $0.9 million.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.  As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public partnership.  Without effective internal controls, we cannot be certain that our efforts to ensure our financial processes and reporting in the future will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002.  Pursuant to transitional rules implemented by the SEC, we are not yet required to provide in this report a report of management’s assessment regarding internal control over financial reporting or an attestation report by the Partnership’s registered public accounting firm.

We have identified a material weakness in our internal control over financial reporting which has led our management to conclude that our disclosure controls and procedures are ineffective.  See Item 9A included in this report for further discussion of this material weakness.

In the future, any failure to develop or maintain effective internal controls, including the identification of the material weakness in our internal control over financial reporting or the potential identification of further material weaknesses, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations.  Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

The amount of cash distributions that we will be able to distribute to you will be reduced by the costs associated with being a public company, other general and administrative expenses, and reserves that our general partner believes prudent to maintain for the proper conduct of our business and for future distributions.

Before we can pay distributions to our unitholders, we must first pay or reserve cash for our expenses, including capital expenditures and the costs of being a public company and other operating expenses, and we may reserve cash for future distributions during periods of limited cash flows.

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Risks Related to Our Structure

Our general partner and its affiliates own a controlling interest in us and may have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to your detriment.  Our partnership agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.

Affiliates of Provident and BreitBurn Corporation control our general partner, which controls us.  The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Provident.  Furthermore, certain directors and officers of our general partner may be directors or officers of affiliates of our general partner, including Provident.  Conflicts of interest may arise between Provident and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand.  As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.  Please read “—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.”  These potential conflicts include, among others, the following situations:

·                  We have agreed that Provident and its affiliates will have a preferential right to acquire any third party midstream or downstream assets located in the United States and any third party upstream oil and gas properties or midstream or downstream assets outside the United States.

·                  Neither our partnership agreement nor any other agreement requires Provident or its affiliates (other than our general partner) to pursue a business strategy that favors us.  Directors and officers of Provident and its affiliates have a fiduciary duty to make decisions in the best interest of its unitholders, which may be contrary to our interests.

·                  Our general partner is allowed to take into account the interests of parties other than us, such as Provident and its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

·                  Some officers of our general partner who provide services to us devote time to affiliates of our general partner and are compensated for services rendered to such affiliates.

·                  Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, 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 general partner determines the amount and timing of, asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities, cash reserves and expenses (and reviews expenses allocated to us by BreitBurn Management), each of which can affect the amount of cash that is available for distribution to our unitholders.

·                  In some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions.

·                  BreitBurn Management determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us and which are reimbursable by BreitBurn Energy.  These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf or for BreitBurn Energy or on its behalf.  BreitBurn Management is entitled to determine in good faith the expenses that are allocable to us.  BreitBurn Management could in the future utilize a different approach or approaches and may determine that its exercise of good faith requires it to change its allocation of such expenses.  Thus, there can be no assurance that BreitBurn Management will continue to follow a specific approach to allocating its expenses between us and BreitBurn Energy.  Our general partner has limited rights to negotiate any changes to that allocation.

·                  We entered into an Administrative Services Agreement with BreitBurn Management pursuant to which BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering.  We reimburse BreitBurn Management for its costs in performing these services, plus related expenses.

·                  Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf, and provides for reimbursement to our general partner for such amounts as are deemed fair and reasonable to us.

28




·                  Our general partner limits its liability regarding our contractual obligations and has an incentive to make any of our debt or other contractual obligations non-recourse to it.

·                  Our general partner may exercise its rights to call and purchase all of our common units if at any time it and its affiliates own more than 80% of the outstanding common units.

·                  Our general partner controls the enforcement of obligations owed to us by it and its affiliates.

·                  Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Item 13 Certain Relationships and Related Party Transactions and Director Independence”

A subsidiary of Provident, as our controlling unitholder and the controlling owner of our general partner, has the power to appoint and remove our directors and management.

Since a subsidiary of Provident owns a controlling interest in our general partner, it has the ability to elect all the members of the board of directors of our general partner.  Our general partner has control over all decisions related to our operations.  Since a subsidiary of Provident also holds a majority of our common units, the public unitholders do not have an ability to influence any operating decisions and are not able to prevent us from entering into any transactions.  Furthermore, the goals and objectives of Provident and its subsidiary relating to us may not be consistent with those of a majority of the public unitholders.

We do not have any officers or employees and rely solely on officers of our general partner and employees of BreitBurn Management and Provident and its affiliates.

None of the officers of our general partner are employees of our general partner.  We entered into an Administrative Services Agreement with BreitBurn Management, pursuant to which BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land, legal and engineering.  Affiliates of our general partner and BreitBurn Management conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to BreitBurn Energy.  There could be material competition for the time and effort of the officers and employees who provide services to our general partner, BreitBurn Management and their affiliates.  If the officers of our general partner and the employees of BreitBurn Management and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

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.

The issuance of additional common units or other equity securities may have the following effects:

·                  your proportionate ownership interest in us may decrease;

·                  the amount of cash distributed on each common unit may decrease;

·                  the relative voting strength of each previously outstanding common unit may be diminished;

·                  the market price of the common units may decline; and

·                  the ratio of taxable income to distributions may increase.

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:

·                  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner.

29




Decisions made by our general partner in its individual capacity will be made by a majority of the owners of our general partner, and not by the board of directors of our general partner.  Examples include the exercise of its limited call rights, its rights to vote and transfer the units it owns and its registration rights and the determination of whether to consent to any merger or consolidation of the partnership;

·                  provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the partnership;

·                  generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

·                  provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

·                  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors or initially to remove our general partner without its consent, which could lower the trading price of our common units.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.  Unitholders have no right to elect our general partner or its board of directors on an annual or other continuing basis.  The board of directors of our general partner is chosen entirely by Provident and BreitBurn Corporation and not by the unitholders.  Furthermore, even if our unitholders are dissatisfied with the performance of our general partner, they, practically speaking, have no ability to remove our general partner.  As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a control premium in the trading price.

Our unitholders are not able to remove our general partner without Provident’s consent because Provident owns a sufficient number of units to prevent removal of our general partner.  The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove our general partner.  As of March 31, 2007, Provident and BreitBurn Corporation owned 68.60% of our common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% 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.  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.

30




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; (3) a public body, including a municipality; or (4) 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.  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:

·                  we were conducting business in a state but had not complied with that particular state’s partnership statute; or

·                  your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted ‘control’ of our business.

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.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders.  Furthermore, there is no restriction in our partnership agreement on the ability of Provident to transfer its equity interest in our general partner to a third party.  The new equity owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to influence the decisions taken by the board of directors and officers of our general partner.

31




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.

We have 21,975,758 common units outstanding and all of our common units that were outstanding prior to our initial public offering are subject to resale restrictions under 180-day lock-up agreements with our underwriters (which will expire on April 4, 2007).  Each of the lock-up arrangements with the underwriters may be waived in the discretion of RBC Capital Markets Corporation and Citigroup Global Markets Inc.  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 addition, our general partner has agreed to provide registration rights to these holders, subject to certain limitations.  Under our partnership agreement, our general partner and its affiliates have registration rights relating to the offer and sale of any common units that they hold, subject to certain limitations.

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.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks.  In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly-traded limited partnership interests.  Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

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 treatedas 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.

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%, 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. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.

32




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.

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 conclusions of our counsel or from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take.  A court may not agree with some or all of our counsel’s conclusions or 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.

Tax-exempt entities and foreign 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.

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.

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.

The sale or exchange of 50% 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 to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period.  Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

33




You may be subject to state and local taxes and return filing requirements.

In addition to federal income taxes, you may 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 do business or own property now or in the future, even if you do not reside in any of those jurisdictions.  You may 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 do business and own assets in California, Wyoming and Texas.  As we make acquisitions or expand our business, we may do business or own assets in other states in the future.  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.  Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

Item 1B.  Unresolved Staff Comments.

Not applicable.

Item 2.  Properties.

The location and character of the Partnership’s crude oil and natural gas properties are described above under Item 1. Business.  Information required by the Securities Exchange Act Industry Guide No. 2 (“Disclosure of Oil and Gas Operations”) is also contained in Item 1 and on pages F-1 to F-38 of this report.

Item 3.  Legal Proceedings.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings.  In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.

Item 4.  Submission of Matters to a Vote of Security Holders.

No matter was submitted to a vote of security holders during the fourth quarter of 2006.

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PART II

Item 5.  Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our Common Units began trading on the NASDAQ Global Select Market under the symbol “BBEP” commencing with our initial public offering on October 4, 2006.  At December 31, 2006, based upon information received from our transfer agent and brokers and nominees, we had approximately 7,550 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 period indicated.

 

Price Range

 

Cash Distribution

 

Year Ended December 31, 2006

 

High

 

Low

 

Per Common Unit (1)

 

Fourth Quarter

 

$

24.99

 

$

18.15

 

$

0.399

 

 


(1)             On January 22, 2007, the board of directors of our general partner declared our quarterly cash distribution for the fourth quarter of 2006.  The distribution for the quarter ended December 31, 2006 was paid on February 14, 2007, and reflects the pro rata portion of a quarterly distribution rate of $0.4125, covering the period from the first day our common units were publicly traded, October 4, 2006, to and including December 31, 2006.

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% of our borrowing base.  See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facility and Note 8 of our consolidated financial statements.”

Within 45 days after the end of each quarter, we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date.  The amount of available cash generally 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.

The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2006.  For a description of the material features of these plans, see Item 11. “Compensation Discussion and Analysis—Components of Compensation.”

Equity Compensation Plan Information

Plan category

 

Number of Securities
to be Issued Upon
Exercise of Outstanding
Options, Warrants
and Rights
(a)

 

Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
(b)

 

Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plan
(Excluding Securities
Reflected in Column(a))
(c)

 

Equity compensation plans approved by security holders

 

 

$

 

 

Equity compensation plans not approved by security holders

 

40,509

(1)

N/A(2)

 

2,157,067

(3)

Partnership LTIP

 

 

 

 

 

 

 

 


(1)          Represents the number of performance units issued under the Partnership LTIP.  Upon vesting, the grantee of a performance unit receives a payment in cash or common units with a value determined under the provisions of the Partnership LTIP.  See Item 11. “Compensation Discussion and Analysis—Components of Compensation—Long-Term Incentive Plans.”

35




(2)          Performance unit awards under the Partnership LTIP and the BreitBurn Management LTIP vest without payment by recipients.

(3)          The Partnership LTIP provides that the board of directors or a committee of the board of our general partner may award restricted units, performance units, unit appreciation rights or other unit-based awards and unit awards.

The following table shows the common units the Partnership repurchased during the fourth quarter of 2006.

Issuer Purchases of Equity Securities

Period

 

Total Number of 
Shares (or Units 
Purchased)

 

Average Price Paid 
per Share (or Unit)

 

Total Number of 
Shares (or Units) 
Purchased as Part 
of Publicly 
Announced Plans 
or Programs

 

Maximum Number
 (or Approximate
Dollar Value) of
Shares (or Units)
that May Yet Be
Purchased Under
the Plans or
Programs

 

 

 

 

 

 

 

 

 

 

 

October 1, 2006 to

October 31, 2006

 

__

 

__

 

__

 

__

 

November 1, 2006 to

November 30, 2006

 

900,000

(1)

$

17.205

(1)

__

 

__

 

December 1, 2006 to

December 31, 2006

 

__

 

__

 

__

 

__

 

Total

 

900,000

(1)

$

17.205

(1)

__

 

__

 

 


(1)          On November 1, 2006, the underwriters for our initial public offering exercised their option to purchase an additional 900,000 common units to cover over-allotments in connection with the initial offering.  The sale was at the initial public offering price of $18.50 per unit, less the underwriting discount of $1.295 per unit, and closed on November 6, 2006.  The Partnership used the net proceeds from the exercise of the underwriters’ over-allotment option to redeem 900,000 common units owned by BreitBurn Corporation and two indirect subsidiaries of Provident for a per-unit price equal to $17.205.  Following redemption, those common units were cancelled.

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Item 6.  Selected Financial Data.

Set forth below is summary historical consolidated financial data for BreitBurn Energy Partners L.P., BreitBurn Energy Company L.P. 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 for the period from October 10, 2006 to December 31, 2006 is derived from the audited financial statements of BreitBurn Energy Partners L.P.  The selected historical consolidated financial data presented as of and for each of the years ended December 31, 2002 and 2003, 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 derived from the audited consolidated financial statements of BreitBurn Energy and its predecessors.  In connection with the initial public offering, BreitBurn Energy contributed to the Partnership’s 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.  The Partnership conducts its operations through its wholly owned subsidiaries BreitBurn Operating L.P. (“OLP”) and OLP’s general partner BreitBurn Operating GP, LLC (“OGP”).  BreitBurn Energy’s historical results of operations include combined information for the Partnership and BreitBurn Energy, and thus may not be indicative of the Partnership’s future results.

You should read the following summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our 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 exploration expense, interest expense, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, loss or gain on sale of assets, cumulative effect of changes in accounting principles, and income tax provision.

We use Adjusted EBITDA to assess:

·      the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·      the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

·      our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure; and

·      the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

We are required to report Adjusted EBITDA to our lenders under our credit facility, and to use Adjusted EBITDA to determine our compliance with the consolidated leverage test thereunder.  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.

37




Selected Financial Data

 

Successor

 

Predecessors

 

 

 

BreitBurn 
Energy
Partners L.P.

 

BreitBurn Energy Company L.P.

 

BreitBurn Energy Company LLC

 

 

 

October 10 to

 

January 1 to

 

Year Ended

 

June 16 to

 

January 1 to

 

Year Ended

 

Year Ended

 

 

 

December 31,

 

October 9,

 

December 31,

 

December 31,

 

June 15,

 

December 31,

 

December 31,

 

Thousands of dollars

 

2006

 

2006

 

2005

 

2004

 

2004

 

2003

 

2002

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues and other income items

 

$

19,504

 

$

113,543

 

$

101,865

 

$

29,033

 

$

12,213

 

$

42,181

 

$

38,002

 

Operating costs

 

7,159

 

34,893

 

32,960

 

10,394

 

6,700

 

15,704

 

16,469

 

Depletion, depreciation and amortization

 

2,506

 

10,903

 

11,862

 

4,305

 

1,388

 

3,618

 

4,523

 

General and administrative expenses

 

7,852

 

18,046

 

16,111

 

4,310

 

5,309

 

4,171

 

3,302

 

Operating income (loss)

 

1,987

 

49,701

 

40,932

 

10,024

 

(1,184

)

18,688

 

13,708

 

Interest and other financing costs, net

 

72

 

2,651

 

1,631

 

143

 

4,711

 

5,503

 

3,476

 

Other expenses, net

 

84

 

528

 

294

 

203

 

501

 

268

 

(1,159

)

Income (loss) before taxes and minority interest

 

1,831

 

46,522

 

39,007

 

9,678

 

(6,396

)

12,917

 

11,391

 

Income taxes

 

(40

)

90

 

 

 

 

 

 

Minority interest

 

 

(1,039

)

 

 

 

 

 

Loss from discontinued operations

 

 

 

 

 

 

 

(6,609

)

Income (loss) before cumulative change in accounting principles

 

1,871

 

47,471

 

39,007

 

9,678

 

(6,396

)

12,917

 

4,782

 

Cumulative effect of change in accounting principles

 

 

577

 

 

 

 

1,653

 

 

Net income (loss)

 

$

1,871

 

$

48,048

 

$

39,007

 

$

9,678

 

$

(6,396

)

$

14,570

 

$

4,782

 

Net income per basic unit or common share

 

$

0.08

 

$

0.27

 

$

0.22

 

$

0.07

 

$

(0.49

)

$

0.95

 

$

0.38

 

Net income per diluted unit or common share

 

$

0.08

 

$

0.27

 

$

0.22

 

$

0.07

 

$

(0.49

)

$

0.95

 

$

0.38

 

Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash (used in) provided by operating activities

 

$

(1,256

)

$

47,743

 

$

45,926

 

$

111

 

$

1,697

 

$

6,626

 

$

10,205

 

Net cash (used in) provided by investing activities

 

(1,248

)

(35,268

)

(93,439

)

(60,490

)

(8,531

)

20,620

 

(19,261

)

Net cash (used in) provided by financing activities

 

2,581

 

(13,693

)

49,617

 

60,698

 

6,302

 

(26,854

)

8,553

 

Capital expenditures (excluding property acquisitions) for oil and gas properties

 

(1,248

)

(36,941

)

(39,945

)

(11,314

)

(8,522

)

(12,809

)

(20,619

)

Capital expenditures for property acquisitions

 

 

 

(72,700

)

(47,508

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

93

 

$

1,359

 

$

2,740

 

$

636

 

$

183

 

$

715

 

$

323

 

Other current assets

 

20,863

 

29,527

 

18,933

 

9,839

 

9,527

 

6,467

 

6,356

 

Net property, plant and equipment

 

185,870

 

340,654

 

310,741

 

212,324

 

104,018

 

96,846

 

110,555

 

Other assets

 

418

 

3,057

 

1,112

 

816

 

751

 

1,325

 

1,309

 

Total assets

 

$

207,244

 

$

374,597

 

$

333,526

 

$

223,615

 

$

114,479

 

$

105,353

 

$

118,543

 

Current liabilities

 

13,458

 

44,376

 

40,980

 

25,025

 

79,381

 

55,735

 

14,149

 

Long -term debt

 

1,500

 

56,000

 

36,500

 

10,500

 

 

 

62,400

 

Other long term liabilities

 

15,078

 

22,314

 

16,021

 

4,076

 

2,534

 

6,460

 

9,453

 

Redeemable preferred shares

 

 

 

 

 

40,736

 

37,785

 

34,925

 

Minority interest

 

 

1,361

 

 

 

 

 

 

Partners' capital (deficit)

 

177,208

 

250,546

 

240,025

 

184,014

 

(8,172

)

5,373

 

(2,384

)

Total liabilities and partners' capital

 

$

207,244

 

$

374,597

 

$

333,526

 

$

223,615

 

$

114,479

 

$

105,353

 

$

118,543

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other Financial Data (unaudited):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA

 

$

5,708

 

$

55,132

 

$

52,345

 

$

16,736

 

$

(297

)

$

11,214

 

$

16,718

 

 

38




The following table presents a reconciliation of Adjusted EBITDA to net income (loss) and net cash flow from operating activities, our most directly comparable GAAP financial performance and liquidity measures, for each of the periods indicated.

 

 

Successor

 

Predecessors

 

 

 

BreitBurn
Energy
Partners L.P.

 

BreitBurn Energy Company L.P.

 

BreitBurn Energy Company LLC

 

 

 

October 10 to

 

January 1 to

 

Year Ended

 

June 16 to

 

January 1 to

 

Year Ended

 

Year Ended

 

 

 

December 31,

 

October 9,

 

December 31,

 

December 31,

 

June 15,

 

December 31,

 

December 31,

 

Thousands of dollars

 

2006

 

2006

 

2005

 

2004

 

2004

 

2003

 

2002

 

Reconciliation of consolidated net income to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

$

1,871

 

$

48,048

 

$

39,007

 

$

9,678

 

$

(6,396

)

$

14,570

 

$

4,782

 

Unrealized loss (gain) on derivative instruments

 

1,299

 

(5,983

)

(155

)

2,610

 

 

 

 

Depletion, depreciation and amortization expense

 

2,506

 

10,903

 

11,862

 

4,305

 

1,388

 

3,618

 

4,523

 

Interest expense and other financing costs

 

72

 

2,651

 

1,631

 

143

 

4,711

 

5,503

 

3,476

 

Loss (gain) on sale of assets

 

 

 

 

 

 

(10,824

)

3,937

 

Income tax expense

 

(40

)

90

 

 

 

 

 

 

Cumulative effect of change in accounting principles

 

 

(577

)

 

 

 

(1,653

)

 

Adjusted EBITDA

 

$

5,708

 

$

55,132

 

$

52,345

 

$

16,736

 

$

(297

)

$

11,214

 

$

16,718

 

Reconciliation of net cash from operating activities to Adjusted EBITDA:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash from operating activities

 

$

(1,256

)

$

47,743

 

$

45,926

 

$

111

 

$

1,697

 

$

6,626

 

$

10,205

 

Add:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Increase (decrease) in current assets and current liabilities relating to operating activities

 

10,166

 

14,259

 

10,510

 

15,973

 

(2,107

)

1,974

 

2,671

 

Unrealized gain on financial derivative instruments

 

1,299

 

(5,983

)

(155

)

2,610

 

 

 

 

Interest expense and other financing costs

 

72

 

2,651

 

1,631

 

143

 

1,760

 

3,281

 

3,476

 

Equity in earnings from affiliates, net

 

(32

)

(48

)

1

 

(35

)

(28

)

(81

)

7

 

Stock based compensation paid

 

 

4,400

 

1,970

 

 

 

 

 

Deferred stock based compensation

 

(4,490

)

(7,979

)

(7,213

)

(1,874

)

 

 

 

Other

 

(51

)

(950

)

(325

)

(192

)

(1,619

)

(586

)

359

 

Minority interest

 

 

1,039

 

 

 

 

 

 

Adjusted EBITDA

 

$

5,708

 

$

55,132

 

$

52,345

 

$

16,736

 

$

(297

)

$

11,214

 

$

16,718

 

 

39




Item 7.           Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial and Operating Data” and the financial statements and related notes included elsewhere in this report.  The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance.  The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control.  Our actual results could differ materially from those discussed in these forward-looking statements.  Factors that could cause or contribute to such differences are discussed in “Risk Factors” contained in Item 1A of this report.  In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.  See “Cautionary Statement Relevant to Forward-Looking Information” in the front of this report.

Overview

We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties.  Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders.  Our assets consist primarily of producing and non-producing crude oil reserves located in the Los Angeles Basin in California and the Wind River and Big Horn Basins in central Wyoming.  Through a 2007 acquisition, we now also have properties in the Permian Basin of West Texas.

Our Predecessor, BreitBurn Energy, is a 95.55% owned indirect subsidiary of Provident, a publicly traded Canadian energy trust.  Provident acquired its interest in BreitBurn Energy in June 2004 with the intent to use BreitBurn Energy as the primary acquisition vehicle to grow its upstream energy business in the United States.  BreitBurn Energy Corporation (“BreitBurn Corporation”) owns the remaining 4.45% in BreitBurn Energy.  In October 2004, BreitBurn Energy acquired the Orcutt Hills Oil Field in California and in March 2005, it acquired Nautilus Resources, LLC (‘‘Nautilus’’), a privately held company with assets in the Wind River and Big Horn Basins in central Wyoming.

On October 10, 2006, we completed our initial public offering of 6,000,000 Common Units representing limited partner interests in the Partnership at $18.50 per unit, or $17.205 per unit after payment of the underwriting discount.  On November 6, 2006, we also completed the sale of an additional 900,000 Common Units to cover over-allotments in the initial public offering.  After the initial public offering and the subsequent over-allotment exercise, Provident and BreitBurn Corporation together own 15,075,758 Common Units, representing an aggregate 68.60% limited partner interest, and an indirect 2% general partner interest in the Partnership; and the public unitholders own 6,900,000 Common Units, representing an aggregate 31.40% limited partner interest.

Partnership Properties

In connection with the initial public offering, BreitBurn Energy contributed to us the Partnership Properties, which include 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.  As of December 31, 2006, the total estimated proved reserves of the Partnership Properties were 30.7 MMBoe, of which approximately 98% were oil and 93% were classified as proved developed reserves.  Of these total estimated proved reserves 57% are located in California and 43% are located in Wyoming.  We operate approximately 99% of the total wells in which we have interests.  The Partnership conducts its operations through, and its operating assets are owned by, its subsidiaries.  The Partnership owns directly or indirectly all of the ownership interests in its operating subsidiaries.

The Partnership has no employees.  The Partnership entered into an Administrative Services Agreement with BreitBurn Management, a majority owned subsidiary of Provident, pursuant to which such subsidiary operates the Partnership’s assets and performs other administrative services for the Partnership such as accounting, corporate development, finance, land, legal and engineering.  BreitBurn Management also manages the assets retained by BreitBurn Energy.  In addition, the Partnership entered into an Omnibus Agreement with Provident, which details certain agreements with respect to conflicts of interest.

40




How We Evaluate our Operations

We use a variety of financial and operational measures to assess our performance.  Among these measures are the following: volumes of oil and natural gas produced, reserve replacement; realized prices; operating and general and administrative expenses; and Adjusted EBITDA, as defined in Item 6 of this report.

For the year ended December 31, 2006 as compared to the year ended December 31, 2005, production volumes for the Partnership Properties increased by 82 MBoe, or 5%.  Most of the increase resulted from reporting a full year of production for Nautilus in 2006 as compared to 10 months in 2005.  This increase was partially offset by lower production due to natural field declines primarily in our California properties.

As of December 31, 2006, our proved reserves were 30.7 million Boe.  The properties contributed to us had reserves of 29.7 million Boe as of December 31, 2005.  This increase of 1 million Boe was net of 1.6 million Boe produced during 2006 for these properties.  On that basis, these properties realized an approximate 160% reserve replacement during 2006.  This increase does not include the acquisition we made in early 2007, which is discussed under “Recent Acquisitions.”

We analyze the prices we realize from sales of our oil and gas production and the impact on those prices of differences in market -based index prices and the effects of our derivative activities.  We market our oil and natural gas production to a variety of purchasers based on regional pricing.  Crude oil produced in the Los Angeles Basin of California and Wind River and Big Horn Basins of central Wyoming typically sells at a discount to NYMEX WTI crude oil due to, among other factors, its relatively heavier grade and/or relative distance to market.  Our Los Angeles Basin crude oil is generally medium gravity crude.  Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX WTI.  Our Wyoming crude oil, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that it is priced relative to the Bow River benchmark for Canadian heavy sour crude oil, which has historically traded at a significant discount to NYMEX WTI.  Our revenues and net income are sensitive to oil and natural gas prices.  We enter into various derivative contracts in order to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas.  We currently maintain derivative arrangements for a significant portion of our oil and gas production.  See ‘‘Item 7A.  Quantitative and Qualitative Disclosure About Market Risk” for more detail on our hedging activities.

In evaluating our production operations, we frequently monitor and assess our operating and general and administrative expenses per Boe produced.  This measure allows us to better evaluate our operating efficiency and is used by us in reviewing the economic feasibility of a potential acquisition or development project.

Operating expenses are the costs incurred in the operation of producing properties.  Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses.  A majority of our operating cost components are variable and increase or decrease along with our levels of production.  For example, we incur power costs in connection with various production related activities such as pumping to recover oil and gas, separation and treatment of water produced in connection with our oil and gas production, and re -injection of water produced into the oil producing formation to maintain reservoir pressure.  Although these costs typically vary with production volumes, they are driven not only by volumes of oil produced but also volumes of water produced.  Consequently, fields that have a high percentage of water production relative to oil production, also known as a high water cut, will experience higher levels of power costs for each barrel of oil produced.  Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period.  For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed.

Production taxes vary by state.  California, Wyoming and Texas impose ad valorem taxes on oil and gas properties.  Various states regulate the drilling for, and the production, gathering and sale 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% 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% of the value of the gross product extracted.  California does not currently impose a severance tax but attempts to impose a similar tax have been introduced in the past.

41




The Partnership entered into an Administrative Services Agreement with BreitBurn Management, pursuant to which BreitBurn Management began operating the Partnership’s assets and performing other administrative services for the Partnership such as accounting, corporate development, finance, land, legal and engineering.  Under the Administrative Services Agreement, we reimburse BreitBurn Management for all direct and indirect expenses it incurs in connection with the services it performs (including salary, bonus, incentive compensation and other amounts paid to its executive officers).  BreitBurn Management currently either allocates to us expenditures specifically identified with conducting our operations or in proportion to the aggregate barrels of oil equivalents produced by us.  BreitBurn Management also allocates certain expenses based on its good -faith determination of actual time spent performing services for us relative to any other entity.  BreitBurn Management will from time to time review the methodology utilized to allocate costs, including reviewing the impacts of acquisitions, capital programs, and other factors, and may modify the methodology to appropriately reflect the value attributable to the Partnership.

The Partnership’s general and administrative expenses totaled $7.9 million in the 83 days from October 10, 2006 to December 31, 2006.  This result was $5.2 million more than management expected due to higher expenses related to management incentive plans caused by a 30% increase in the price of the Partnership’s units from the first day of trading to the last day of the year.  In addition, general and administrative expenses were approximately $0.5 million higher than expectations as we experienced higher accounting, audit, legal and other professional fees attributable to our transition to a public entity.  The management incentive plans can result in the Partnership recognizing significant compensation expense if the Partnership’s units also significantly increase in value.  We estimate that each $1.00 increase in the trading price of our common units above $24.10 (which was our closing unit price for the last trading day of 2006) would increase the amount of our compensation expense for 2007 by approximately $0.9 million.

Outlook

Oil and natural gas prices have increased significantly since the beginning of 2004.  The Partnership anticipates a continued favorable commodity price environment in 2007.  Significant factors that will impact near -term commodity prices include political developments in Iraq, Iran and other oil producing countries, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American natural gas and refined products supply and demand indicators.  A substantial portion of the Partnership’s estimated production is currently covered through derivative transactions through 2008, and the Partnership intends to continue to enter into commodity derivative transactions to mitigate the impact of price volatility on its oil and gas revenues.

Industry price levels for crude oil generally increased in the first half of 2006 and declined in the second half.  Prices at the end of 2006 were slightly lower than at the beginning of the year.  The WTI spot price for crude oil averaged $66 per barrel in 2006, an increase of approximately $9 per barrel from the 2005 average price.  The rise in crude oil prices between years reflected, among other things, increasing demand in growing economies, the heightened level of geopolitical uncertainty in some areas of the world and supply concerns in other key producing regions.  To date in 2007, the WTI spot price has averaged approximately $56 per barrel.

The increase in commodity prices has resulted in increased drilling activity and demand for drilling and operating services and equipment in North America.  The Partnership anticipates drilling service and labor costs, as well as costs of equipment and raw materials, to remain at the levels experienced in 2006.

42




Results of Operations

The table below summarizes certain of the results of operations and period-to-period comparisons attributable to the Partnership Properties for the periods indicated.  These results are presented for illustrative purposes only and are not indicative of the future results of the Partnership Properties.  The information was prepared by us and is unaudited.  This presentation does not correspond to the financial statements included elsewhere in this report and represents only a sub set of those financial statements.

 

 

Year Ended December 31,

 

Increase / decrease%

 

Thousands of dollars, except as indicated

 

2006

 

2005

 

2004

 

2006-2005

 

2005-2004

 

Total Production (MBoe)

 

1,640

 

1,558

 

866

 

5

%

80

%

Average daily production (Boe/d)

 

4,494

 

4,269

 

2,368

 

5

%

80

%

Oil, natural gas and natural gas liquid sales

 

$

89,815

 

$

73,334

 

$

32,845

 

22

%

123

%

Realized gains (losses) on derivative instruments

 

1,077

 

(8,594

)

(4,882

)

113

%

-76

%

Unrealized gains (losses) on derivative instruments

 

3,303

 

98

 

(1,356

)

3,270

%

107

%

Other revenues, net

 

1,104

 

964

 

968

 

15

%

0

%

Total revenues and other income items

 

$

95,299

 

$

65,802

 

$

27,575

 

45

%

139

%

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

$

29,261

 

$

21,388

 

$

11,561

 

37

%

85

%

 

Comparison of Results of the Partnership Properties for the Year Ended December 31, 2006, 2005 and 2004

The variance in the results of the Partnership Properties was due to the following components:

Production

For the year ended December 31, 2006 as compared to the year ended December 31, 2005, production volumes increased by 82 MBoe, or 5%.  Most of the increase in 2006 resulted from reporting two extra months of production for Nautilus in 2006 as compared to 2005.  Nautilus was purchased by our Predecessor in March 2005.  This increase was partially offset by lower production due to natural field declines primarily in our California properties.

For the year ended December 31, 2005 as compared to the year ended December 31, 2004, production volumes increased by 692 MBoe, or 80%.  Approximately 86% of the increase in 2005 was a result of the Nautilus acquisition.

Revenues

Total revenues increased $29.5 million in 2006 as compared to 2005.  The majority of the increase was attributable to higher crude oil prices, which increased revenues by approximately $12.6 million.  The 2006 results also reflected higher revenues of $4.2 million, which was attributable to including a full year of Nautilus production in 2006 as compared to ten months in 2005.  In addition, the 2006 results were higher by $3.2 million compared to 2005 due to larger unrealized derivative gains in 2006 versus 2005.  The 2006 results included realized gains of $1.1 million versus losses of $8.6 million in 2005 related to derivative instruments.

The increase in total revenues of $38.2 million from 2004 to 2005 was due to an increase of $40.5 million from oil and gas sales, which included $22.6 million resulting from higher production attributable to the Nautilus acquisition in March 2005, $14.3 million from price increases, and $3.6 million from drilling and optimization programs. This increase was partially offset by higher losses of $2.3 million from derivative instruments.

43




Operating expenses

For the year ended December 31, 2006 as compared to the year ended December 31, 2005, operating expenses were $17.84 per Boe compared with $13.73, an increase of 30%.  This increase was due to overall increases in labor, service, insurance and production and property tax costs, primarily in California operations.  Higher property taxes in 2006 added $1.93 per Boe to operating expenses.

For the year ended December 31, 2005 as compared to the year ended December 31, 2004, operating expenses were $13.73 per Boe compared with $13.35 per Boe, an increase of 3%.

Depletion, depreciation and amortization

Depletion, depreciation and amortization (“DD&A”) expense increased by $0.83 per Boe from $4.36 per Boe in 2005 to $5.19 per Boe in 2006.  The increase in DD&A rates was due to changes in reserve estimates at December 31, 2006, primarily related to our Wyoming properties.  In addition, DD&A included an impairment charge of $0.3 million in one of our Wyoming properties, which increased our DD&A rate by approximately $0.20 per Boe.

Depletion, depreciation and amortization expense increased by $1.37 per Boe from $2.99 per Boe in 2004 to $4.36 per Boe in 2005.  The increase in DD&A rates primarily reflected the investment related to the Nautilus acquisition.

Results of Operations – For the Partnership’s Predecessor from 2004 through the date of the Initial Public Offering (October 10, 2006) and the Partnership for the Period from October 10, 2006 through December 31, 2006.

The discussion of the results of operations and period-to-period comparisons presented below primarily covers the historical results of BreitBurn Energy.  Because the historical results of BreitBurn Energy include combined information for both the Partnership Properties and the properties retained by BreitBurn Energy, we do not consider these historical results of BreitBurn Energy for operations and period-to-period comparisons of its results as indicative of the Partnership’s future results.  Nevertheless, they are presented here to provide a possible context for the current operations of the Partnership.

Revenues—BreitBurn Energy – Pre-IPO and the Partnership Post-IPO to 12/31/06

For the 282 day period of 2006 preceding the Partnership’s initial public offering, net revenue for BreitBurn Energy was $113.5 million, including unrealized gains on derivative instruments of $6.0 million and realized losses on derivative instruments of $3.7 million.  The Partnership’s revenues for the 83 day period from October 10, 2006, the day the Partnership completed its initial public offering, through December 31, 2006, totaled $19.5 million, including realized gains on derivative instruments of $2.2 million and unrealized losses on derivative instruments of $1.3 million.

Total revenues for BreitBurn Energy increased by $60.6 million from 2004 to 2005 due to increases of $65.4 million from oil and gas sales, which included $22.6 million from Nautilus properties that were acquired in March 2005, $22.9 million from higher prices, $14.0 million from a full year of Orcutt production, as compared to three months in 2004, and $6.5 million in higher production from drilling and optimization programs.  Th