Big West Oil Partners S-1 IPO registration

As filed with the Securities and Exchange Commission on December 7, 2007

Registration No. 333-            

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Big West Oil Partners, LP

(Exact name of registrant as specified in its charter)

Delaware	2911	26-1501435
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1104 Country Hills Drive

Ogden, Utah 84403

(801) 624-1000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

J Phillip Adams

Big West Oil Partners, LP

1104 Country Hills Drive

Ogden, Utah 84403

(801) 624-1000

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Allan D. Reiss Catherine Gallagher Vinson & Elkins L.L.P. 666 Fifth Avenue New York, New York 10103 (212) 237-0018 Joshua Davidson Elizabeth Husseini Baker Botts L.L.P. One Shell Plaza 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

Approximate date of commencement of proposed sale to the public:As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to Be Registered	Proposed Maximum Aggregate Offering Price (1)(2)	Amount of Registration Fee
Common units representing limited partner interests	$196,218,750	$6,024

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED DECEMBER 7, 2007

P R O S P E C T U S

[LOGO]

8,125,000 Common Units

Representing Limited Partner Interests

Big West Oil Partners, LP

$            per common unit

We are selling 8,125,000 common units. We have granted the underwriters an option to purchase up to 1,218,750 additional common units.

We are a limited partnership recently formed by Big West Oil, LLC, or Big West, a subsidiary of Flying J Inc., to own and operate a portion of its refining business. Immediately following this offering, we will own a 35.0% interest in and control Big West Oil Operating, LP, a Delaware limited partnership, or OPCO, which will own the milli-second catalytic cracking unit and alkylation unit of the Salt Lake refining complex owned by Big West. This is the initial public offering of our common units. We currently expect the initial public offering price to be between $            and $            per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “BWO.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 21.

These risks include the following:

• We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution on our common units and subordinated units.

• OPCO depends on Big West for all of its revenues, and if Big West were unable to meet its minimum obligations under its refining agreement with OPCO, our ability to make distributions to unitholders would be reduced or eliminated.

• Big West’s obligations under the refining agreement are unsecured and Flying J has not guaranteed the obligations.

• Our ability to make distributions would be reduced or eliminated if Big West’s obligations under the refining agreement were suspended or terminated.

• OPCO’s ability to receive greater cash flows from increases in throughput at the Salt Lake refining complex is limited.

• Flying J and Big West have no obligation to offer us the opportunity to purchase additional assets from them or from third parties and face few restrictions on their ability to compete with us.

• Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

• Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

• Even if unitholders are dissatisfied, initially they cannot remove our general partner without its consent.

• You will experience immediate and substantial dilution of $            per common unit.

• If we were to become subject to entity-level taxation for federal or state income tax purposes, then our cash available for distribution to you would be substantially reduced.

• You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

	Per Common Unit	Total
Public Offering Price	$	$
Underwriting Discount(1)	$	$
Proceeds to Big West Oil Partners, LP (before expenses)	$	$

⁽¹⁾ Excludes structuring fee of $            million to be paid to Citigroup Global Markets Inc., Lehman Brothers Inc. and UBS Securities LLC for evaluation, analysis and structuring of our partnership and this offering.

The underwriters expect to deliver the common units to purchasers on or about                     , 2008.

Citi Lehman Brothers UBS Investment Bank

The date of this prospectus is                    , 2008.

[ARTWORK TO COME]

TABLE OF CONTENTS

SUMMARY	1
RISK FACTORS	21
Risks Related to Our Business	21
Risks Inherent in an Investment in Us	35
Tax Risks to Common Unitholders	42
USE OF PROCEEDS	47
CAPITALIZATION	48
DILUTION	49
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS	50
General	50
Our Initial Distribution Rate	51
Pro Forma Cash Available for Distribution for the Fiscal Year Ended January 31, 2007 and the Twelve Months Ended July 31, 2007	52
Estimated Cash Available for Distribution	55
Assumptions and Considerations	56
HOW WE MAKE CASH DISTRIBUTIONS	58
Distributions of Available Cash	58
Operating Surplus and Capital Surplus	59
Subordination Period	62
Distributions of Available Cash from Operating Surplus During the Subordination Period	64
Distributions of Available Cash from Operating Surplus After the Subordination Period	64
General Partner Interest and Incentive Distribution Rights	64
Percentage Allocations of Available Cash from Operating Surplus	65
Distributions from Capital Surplus	66
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	66
Distributions of Cash Upon Liquidation	67
BIG WEST OIL PARTNERS, LP UNAUDITED PRO FORMA FINANCIAL STATEMENTS	69
SELECTED HISTORICAL FINANCIAL AND OPERATING DATA	76
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	80
Partnership Overview	80
Retained Properties	81
Factors Affecting Comparability	82
Major Influences on Results of Operations	83
Historical Results of Big West	85
Critical Accounting Policies	87
Results of Operations	88
Six Months Ended July 31, 2007 Compared to the Six Months Ended July 31, 2006	93
Fiscal Year Ended January 31, 2007 Compared to Fiscal Year Ended January 31, 2006	94
Fiscal Year Ended January 31, 2006 Compared to Fiscal Year Ended January 31, 2005	95
Liquidity and Capital Resources	97
Contractual Obligations and Commercial Commitments	102
Off-Balance Sheet Arrangements	102
Quantitative and Qualitative Disclosure about Market Risk	103
Standards Issued Not Yet Adopted	104
REFINING INDUSTRY OVERVIEW	105
Refining Process	105
Market Trends	106
Salt Lake Refined Products Market	112
BUSINESS	114
Partnership Overview	114

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Our Relationship with Flying J and Big West	115
Competitive Strengths	116
Business Strategies	117
Salt Lake Refining Complex Overview	117
Refining Process	118
OPCO Process Units	118
Big West Facility Units	119
Historical Throughput and Production	120
Competition	123
Agreements with Affiliates	123
Environmental, Health and Safety Matters	127
Employees	131
Legal Proceedings	131
MANAGEMENT	132
Management of Big West Oil Partners, LP	132
Directors and Executive Officers of Big West GP, LLC	133
Reimbursement of Expenses of Our General Partner	134
Executive Compensation	134
Compensation Discussion and Analysis	134
Compensation of Directors	137
Big West GP, LLC Long-Term Incentive Plan	137
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	140
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	141
Historical Transactions	141
Ownership of General Partner and Limited Partner Interests	141
Contractual Arrangements	141
Registration Rights	142
Future Transactions with Related Parties	142
Distributions and Payments to Our General Partner and its Affiliates	142
Agreements Governing the Transactions	143
Indemnification of Directors and Officers	146
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES	147
Conflicts of Interest	147
Fiduciary Duties	151
DESCRIPTION OF THE COMMON UNITS	154
The Units	154
Transfer Agent and Registrar	154
Transfer of Common Units	154
THE PARTNERSHIP AGREEMENT	156
Organization and Duration	156
Purpose	156
Power of Attorney	156
Capital Contributions	156
Voting Rights	156
Limited Liability	158
Issuance of Additional Securities	159
Amendment of the Partnership Agreement	159
Merger, Sale or Other Disposition of Assets	161
Termination and Dissolution	162
Liquidation and Distribution of Proceeds	162
Withdrawal or Removal of the General Partner	163

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Transfer of General Partner Interest	164
Transfer of Ownership Interests in Our General Partner	164
Transfer of Incentive Distribution Rights	164
Change of Management Provisions	164
Limited Call Right	165
Meetings; Voting	165
Status as Limited Partner	166
Non-Citizen Transferees	166
Indemnification	166
Reimbursement of Expenses	167
Books and Reports	167
Right to Inspect Our Books and Records	167
Registration Rights	168
UNITS ELIGIBLE FOR FUTURE SALE	169
MATERIAL TAX CONSEQUENCES	170
Partnership Status	170
Limited Partner Status	171
Tax Consequences of Unit Ownership	172
Tax Treatment of Operations	177
Disposition of Common Units	178
Uniformity of Units	180
Tax-Exempt Organizations and Other Investors	181
Administrative Matters	182
Reportable Transactions	184
State, Local, Foreign and Other Tax Considerations	184
INVESTMENT IN BIG WEST OIL PARTNERS, LP BY EMPLOYEE BENEFIT PLANS	185
UNDERWRITING	186
VALIDITY OF THE COMMON UNITS	189
EXPERTS	189
WHERE YOU CAN FIND MORE INFORMATION	189
FORWARD-LOOKING STATEMENTS	190
INDEX TO FINANCIAL STATEMENTS	F-1
APPENDIX A    FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED                         PARTNERSHIP OF BIG WEST OIL PARTNERS, LP	A-1
APPENDIX B    GLOSSARY OF SELECTED TERMS	B-1

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You should rely only on the information contained in this prospectus and any free writing prospectus made available by us. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

Through and including                     , 2008 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

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SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes (i) an initial public offering price of $20.00 per common unit and (ii) that the underwriters do not exercise their option to purchase additional units. You should read “Risk Factors” beginning on page 21 for more information about important risks that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

All references in this prospectus to “Big West Oil Partners,” “we,” “our,” “us,” and “the Partnership” refer to Big West Oil Partners, LP and its subsidiaries, including Big West Oil Operating, LP, or OPCO. All references in this prospectus to “Big West Oil Partners,” “we,” “our,” “us” and “the Partnership,” when used in a historical context, refer to the assets of Big West Oil, LLC and its subsidiaries that are being contributed to OPCO in connection with this offering. When used in the present tense or prospectively, those terms refer to Big West Oil Partners, LP and its subsidiaries, including OPCO. References in this prospectus to “our general partner” refer to Big West GP, LLC. References in this prospectus to “Big West” refer to Big West Oil, LLC, a Utah limited liability company indirectly owned by Flying J Inc., which owns the Salt Lake refining complex and indirectly owns the Bakersfield refining complex. References in this prospectus to the “Salt Lake refining complex” refer to the entire refinery complex located in North Salt Lake, Utah owned by Big West prior to the offering. References in this prospectus to “OPCO’s units” refer to the milli-second catalytic cracking unit and alkylation unit at the Salt Lake refining complex to be owned by OPCO upon the closing of the offering. References in this prospectus to the “Big West facility” refer to the process units and facilities at the Salt Lake refining complex, other than OPCO’s units, which will be retained by Big West at the closing of this offering.

Big West Oil Partners, LP

We are an independent refiner of petroleum products operating in North Salt Lake, Utah. We were formed on December 3, 2007 by Big West Oil, LLC, or Big West, a subsidiary of Flying J Inc., or Flying J. Our assets consist of a 35.0% interest in Big West Oil Operating, LP, or OPCO, which will own the milli-second catalytic cracking unit and alkylation unit at the Salt Lake refining complex. We will control OPCO through our ownership of its general partner. Big West will own the remaining 65.0% interest in OPCO, our general partner and the other process units at the Salt Lake refining complex.

OPCO’s assets will consist of a milli-second catalytic cracking unit, or MSCC unit, and an alkylation unit. These two units enable the Salt Lake refining complex to process black wax and yellow wax crude oils, providing a cost advantage that has recently resulted in favorable refining margins for Big West. In connection with this offering, OPCO will enter into a 25-year refining agreement with Big West. Pursuant to the refining agreement, Big West will agree to throughput during each semi-annual period a minimum volume of gas oils from the distillation unit in the Big West facility to OPCO’s MSCC unit in return for a per barrel refining fee. Similarly, Big West will agree to offtake during each semi-annual period a minimum volume of alkylate processed at OPCO’s alkylation unit in return for a per barrel refining fee. Big West will be obligated to pay the minimum refining fees whether or not it utilizes OPCO’s units. Because OPCO will not own any of the gas oils or alkylate, and because the refining fees will not be tied to commodity prices of either feedstocks or refined products, we believe the refining agreement will substantially reduce our direct exposure to commodity price volatility. In addition, in the event that OPCO’s operating costs under its services agreements with Big West increase for any given year during the term of the refining agreement, the refining fees payable by Big West to OPCO for the following year will be increased permanently by the amount of the operating cost increase for the prior year, which will assist OPCO in maintaining its net operating profit.

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OPCO will own and operate the following process units:

• Milli-second catalytic cracking unit. The MSCC unit catalytically breaks down complex, lower value gas oils fed to it by the Salt Lake refining complex’s distillation unit into lighter, higher value liquid products such as gasoline, diesel and other higher value hydrocarbon products. The MSCC unit was installed in 2002 and uses innovative technology that increases the efficiency of catalytic reactions. The MSCC unit has a throughput capacity of 11,500 barrels per day, or bpd. The MSCC unit underwent its most recent turnaround in April 2006, which lasted 27 days. We expect the next turnaround for this unit to occur in 2011.

• Alkylation unit. The alkylation unit combines lower value, low molecular weight olefins such as propylene, butylene or pentene with isobutane in the presence of a hydrofluoric acid catalyst to produce higher value, high octane gasoline blending stock called alkylate. Alkylate is a key blendstock in the production of high specification reformulated gasoline. The low molecular weight olefins and a portion of the isobutane used in the alkylation process are generated as a by-product of the MSCC unit. Additional isobutane is produced in the butamer unit at the Salt Lake refining complex or supplied by third parties. The alkylation unit has an alkylate offtake capacity of 2,800 bpd. The alkylation unit underwent its most recent turnaround in April 2006, which lasted 29 days. We expect the next turnaround for this unit to occur in 2011.

Immediately following the closing of the offering, Big West will be OPCO’s only customer and account for all of OPCO’s sales. We expect OPCO to continue to derive at least a substantial majority, if not all, of its revenues from Big West or its affiliates for the foreseeable future.

The Salt Lake refining complex was originally constructed in 1948 and, since acquiring the complex in 1985, Big West has significantly upgraded the refining complex’s processing capability and expanded its average daily crude oil throughput from approximately 18,000 bpd to approximately 31,000 bpd. The Salt Lake refining complex’s crude oil inputs consist of black wax crude oil and yellow wax crude oil from the nearby Uinta basin in northeastern Utah, light sweet crude oil (condensate) from Southwest Wyoming, or SWWS, and synthetic crude oil, or syncrude, from Canada. Black wax and yellow wax crude oils and SWWS have generally been less expensive than other benchmark light crude oils such as West Texas Intermediate (WTI), and produce a high percentage of light, high-value refined products.

Approximately 90% of the Salt Lake refining complex’s production during the fiscal year ended January 31, 2007 was higher-value products such as gasoline and diesel, and the remainder of production was marketable by-products. Big West sells the refined products from the Salt Lake refining complex in Utah, Idaho, Nevada, Wyoming, Colorado and Oregon. The Rocky Mountain market historically has had among the highest refining margins between prices of refined products and crude oil feedstocks in the United States.

Our Relationship with Flying J and Big West

We are currently an indirect, wholly owned subsidiary of Flying J, a privately held integrated petroleum firm engaged in the exploration and production, refining, transportation and wholesale and retail marketing of petroleum products, as well as the provision of financial, insurance and technology products and services. Flying J owns and operates travel plazas, convenience stores and truck service centers throughout the United States and Canada and provides financial, insurance, telecommunication, transaction data capture and systems integration services to its customer base. We believe that Flying J is the largest retail diesel fuel marketer by volume in North America, marketing in excess of 425,000 bpd of refined petroleum products and operating a fleet of approximately 900 tanker trucks. Flying J purchases more gasoline and diesel products in the Salt Lake market than the Salt Lake refining complex produces. We expect Flying J will continue to be one of the primary

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purchasers from Big West of the refined products at the Salt Lake refining complex, but Flying J will be under no contractual obligation to purchase any refined products from Big West. Approximately $253.1 million, $382.5 million, $405.7 million and $211.5 million of Big West’s total net sales of refined products from the Salt Lake refining complex were to Flying J and its affiliates for the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2007, respectively. We plan to leverage the expertise, relationships and reputation of Flying J to pursue growth opportunities in the refining and other energy industries.

Following the completion of this offering, Big West will own our general partner and all of our subordinated units and 65.0% of the limited partner interests in OPCO, and our general partner will own 1,218,750 common units, a 2.0% general partner interest in us and our incentive distribution rights.

We may have the opportunity to make acquisitions of assets from Big West and Flying J in the future, although Big West and Flying J will be under no contractual obligation to offer or sell any assets to us. At the closing of this offering, Big West will continue to own the remaining 65.0% limited partner interest in OPCO, the remaining portion of the Salt Lake refining complex and a refining complex in Bakersfield, California with a current crude oil throughput capacity of approximately 70,000 bpd. Big West has invested in the past and intends to continue to invest significant capital to upgrade the Bakersfield refining complex, with the completion of the upgrade project targeted for the fourth quarter of 2009. In addition, an affiliate of Flying J owns the 694-mile Longhorn refined products pipeline extending from a terminal near the Houston, Texas Ship Terminal to terminals in El Paso, Texas, where an affiliate of Flying J also owns a terminal with over one million barrels of storage. Additionally, the Flying J affiliate owns 150,000 barrels of tank storage in Crane, Texas from which refined products can be dispensed through a third party terminal in Odessa, Texas. We believe these assets will be potentially suitable over time for possible purchase by our partnership. We also believe that our ability to consummate acquisitions of additional refining or other energy assets will be enhanced by our access to Big West’s and Flying J’s expertise and commercial relationships. Furthermore, we may pursue acquisitions jointly with Big West and Flying J.

While we believe Flying J and Big West will have an incentive to contribute or sell additional assets to us and to allow us to purchase additional refining or other energy assets suitable for us from third parties, neither has any legal or contractual obligation to do so. Flying J and Big West face few limitations on their ability to compete with us and may elect to acquire or dispose of assets that would be attractive to us in the future, including the assets they will retain at the closing of this offering, without offering us the opportunity to purchase those assets. Even if we are offered the opportunity to purchase assets in the future from Flying J, Big West or third parties, we may be unable to agree on acceptable terms of purchase or to obtain approvals or financing for the acquisition. Further, because Big West controls our general partner, we cannot pursue acquisitions unless Big West causes us to do so. If Flying J or Big West declines to present us with, or successfully competes against us for, attractive acquisition opportunities, we may not be able to acquire new assets, which would materially adversely affect our ability to grow.

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Competitive Strengths

We believe the following competitive strengths will assist us in achieving our primary business objective of maintaining and increasing the amount of cash available for distribution per unit:

Stable Cash Flows from Refining Agreement. OPCO’s cash flow is relatively stable because it derives all of its revenues from per barrel refining fees under the 25-year refining agreement with Big West. The fee structure of the refining agreement helps reduce our direct exposure to commodity price volatility for feedstocks and refined products. In addition, the refining agreement specifies that Big West must pay for a minimum volume of throughput for the MSCC unit and minimum volume of offtake from the alkylation unit, whether or not such volumes are actually processed. We believe that this revenue stream, coupled with Big West’s obligation to permanently increase refining fees paid to OPCO in subsequent years for all operating expenses in prior years in excess of a baseline minimum amount and the length of the refining agreement, will provide us with a long-term, stable source of cash flows.

Unique Operational Relationship with Flying J.OPCO’s assets are integrated and optimized to function with the Big West facility, and Big West will continue to rely on OPCO’s units for its catalytic cracking and alkylation needs. OPCO’s relationship with Big West and Flying J provides OPCO with a stable source of feedstock and a reliable outlet for the refined petroleum products OPCO produces. Flying J is the largest retail diesel fuel marketer by volume in North America and purchases more gasoline and diesel products in the Salt Lake market than the Salt Lake refining complex produces. We expect Flying J will continue to be one of the primary purchasers from Big West of the refined products from the Salt Lake refining complex.

Operations in Attractive Geographic Market. The Salt Lake refining complex is located in the Rocky Mountain region of the United States, which we believe is one of the most favorable areas in the United States in which to operate a refinery. This market features access to lower cost black wax and yellow wax crude oils, condensate from natural gas production in the Rocky Mountain region (also called SWWS) and Canadian crude oils, limited refining capacity, above-average growth in demand for refined products and a lack of pipeline capacity that limits the import of refined products to the Rocky Mountain region from the West Coast and Gulf Coast regions of the United States. As a result of these dynamics, the margin between refined product prices and the price of crude oil feedstocks, or the “crack spread,” in this region historically has generally been one of the highest in the United States. In order to capture the growth in this region, Big West expanded the capacity of the MSCC unit in April 2006 and the alkylation unit in November 2006.

Modern and Efficient Process Units. OPCO’s units are modern, efficient and well maintained. The MSCC unit was designed and installed in 2002 using technology tailored to process lower cost indigenous crude oils such as black wax and yellow wax. The MSCC unit can process these crude oils more efficiently than conventional fluid catalytic cracking units. The throughput capacity of the MSCC unit was expanded from approximately 10,000 bpd to approximately 11,500 bpd during its turnaround in April 2006. In November 2006, Big West increased the alkylate production capacity of the alkylation unit from approximately 2,000 bpd to approximately 2,800 bpd.

Experienced Management. Big West’s management has extensive experience operating refining assets and marketing refined products. Through our shared services and master services agreements with Big West, we will benefit from the knowledge, expertise and significant pool of management talent of Big West.

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Business Strategies

Our primary business objective is to maintain and increase the amount of cash available for distribution per unit. Our principal strategies to achieve this objective are to:

Purchase Assets from Big West and Flying J. At the closing of this offering, Big West will own a 65.0% limited partner interest in OPCO, the remaining portion of the Salt Lake refining complex and a refining complex in Bakersfield, California. A Flying J affiliate will continue to own the Longhorn refined products pipeline, as well as related storage assets. We believe these assets will be potentially suitable over time for possible purchase by our partnership.

Purchase Assets from Third Parties. We will also seek to grow through accretive acquisitions of third party refining and other energy assets suitable for our partnership. Because we are not subject to federal income taxation at the entity level, we believe that we will have a lower cost of capital than our corporate competitors that will enhance our ability to make accretive acquisitions. We also believe that our ability to consummate these acquisitions will be enhanced by our access to Big West’s and Flying J’s expertise and commercial relationships. Furthermore, we may pursue acquisitions jointly with Big West and Flying J.

Market Trends

We have identified several key factors that we believe lead to a favorable outlook for the refining industry for the next several years. We believe that favorable conditions for the refining industry in which Big West competes will benefit Big West and provide an incentive for Big West to maximize production at the Salt Lake refining complex, including throughput to OPCO’s units.

• Limited Construction of New Refineries in the United States. High capital costs, historic excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past thirty years. No new major refinery has been built in the United States since 1976, although many existing refineries have expanded their capacity or are planning expansions. In addition, more than 150 refineries have been closed during this period.

• Improvement in Supply and Demand Dynamics for Refined Petroleum Products. The supply and demand fundamentals of the domestic refining industry have improved since the 1990s, and are generally expected to continue to improve as the demand for refined products continues to exceed increases in refining capacity, both in the United States and on a global basis. Moreover, supply in the Rocky Mountain region continues to be constrained by pipeline infrastructure limitations.

• Advantageous Rocky Mountain Location. Refined product pricing tends to be higher in the Rocky Mountain region than in other domestic regions due to the limited local refining capacity and lack of pipeline capacity that limits the import of refined products from the West Coast and Gulf Coast regions of the United States. Furthermore, the Rocky Mountain region is advantageously located to receive increasing volumes of heavy and synthetic crude oils from Canada. The increasing availability of these Canadian crude oils has reduced the pricing of lower quality indigenous crude oils like black wax and yellow wax produced in the Rocky Mountain region. Similarly, SWWS is available at discounted prices to refiners in the region due to the lack of pipeline infrastructure to transport the SWWS to other regions of the United States. As a consequence, refiners operating in the Rocky Mountain region with the ability to process black wax and yellow wax and SWWS crude oils tend to have a cost advantage over refiners in other regions of the United States.

• Cost Advantages to Refiners that Process Lower Cost Feedstocks. Continued excess availability of lower cost black wax and yellow wax crude oils is expected to provide a cost advantage to refiners in the Rocky Mountain region who have the ability to process and transport these crude oils. These wax crude oils require complex equipment to achieve conversion to lighter, higher value products and cannot

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be transported via pipeline without blending with other feedstocks. Refiners such as Big West with access to insulated tanker trucks necessary to ensure reliable transportation of these wax crude oils and refineries configured to process these feedstocks have a competitive advantage.

Refining Agreement with Big West

General. In connection with this offering, OPCO will enter into a 25-year refining agreement with Big West. The refining agreement has a “take or pay” feature requiring Big West to pay a minimum amount of refining fees to OPCO during each semi-annual period whether or not Big West actually throughputs volumes that would accrue such fees.

Gas oil throughput commitment. Big West will agree to throughput in OPCO’s MSCC unit an average of at least 10,000 bpd of gas oil during each semi-annual period (the “MSCC Commitment”) or pay the related refining fee as if it had throughput these volumes. Subject to Big West’s right of first refusal with respect to any excess capacity, OPCO will have the right to use any excess capacity in the MSCC unit to process for itself or third parties on a spot market basis. OPCO may enter into contracts of up to six months duration with any third party with respect to such excess capacity without Big West’s consent if Big West has failed to pay for the MSCC Commitment for six consecutive months. During the six months ended July 31, 2007, Big West throughput an average of 11,304 bpd of gas oil through the MSCC unit.

The fee for refining barrels of gas oil delivered by Big West to OPCO in any semi-annual period up to the MSCC Commitment will be (i) $29.00 multiplied by (ii) 10,000 multiplied by (iii) the number of days in such semi-annual period (such fee, the “MSCC Refining Fee”). For barrels of gas oil delivered by Big West to OPCO in excess of the MSCC Commitment, if any, the refining fee will be $5.00 per barrel (the “Excess Barrels Refining Fee”). Big West will pay the MSCC Refining Fee in estimated installments on a monthly basis, adjusted monthly and at the end of each semi-annual period. Big West will pay the Excess Barrels Refining Fee, if any, monthly in accordance with the refining agreement. If estimated monthly payments for MSCC Refining Fees by Big West in any semi-annual period fail to meet the minimum MSCC Refining Fee due for such semi-annual period, Big West will be required to pay OPCO cash in the amount of any shortfall. If estimated monthly payments for MSCC Refining Fees paid by Big West in any semi-annual period exceed the actual amount due for such semi-annual period, OPCO will be required to pay Big West cash in the amount of any excess.

Alkylation offtake commitment. Big West will be obligated to offtake an average of at least 2,000 bpd of alkylation product during each semi-annual period (the “Required Offtake Commitment”) or pay the related fee as if it had received these volumes. Subject to Big West’s right of first refusal with respect to any excess capacity, OPCO shall have the right to use the excess capacity of the alkylation unit to process alkylation feedstock for itself or third parties on a spot market basis. OPCO may enter into contracts of up to six months duration with third parties with respect to such excess capacity without Big West’s consent if Big West has failed to pay for its Required Offtake Commitment for six consecutive months. During the six months ended July 31, 2007, Big West received an average of 2,661 bpd of alkylate from the alkylation unit.

The fee for processing Big West’s alkylation feedstock in any semi-annual period up to the Required Offtake Commitment will be (i) $19.00 multiplied by (ii) 2,000 multiplied by (iii) the number of days in such semi-annual period (such fee, the “Alkylation Refining Fee”). For barrels of alkylation product received by Big West above the Required Offtake Commitment, if any, the Alkylation Refining Fee will be $3.00 per barrel (the “Excess Alkylation Refining Fee”). Big West will pay the Alkylation Refining Fee in estimated installments on a monthly basis, adjusted monthly and at the end of each semi-annual period. Big West will pay the Excess Alkylation Offtake Fee, if any, monthly in accordance with the refining agreement. If estimated monthly payments for Alkylation Refining Fees by Big West in any semi-annual period fail to meet the minimum

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Alkylation Refining Fee due for such semi-annual period, Big West will be required to pay OPCO cash in the amount of any shortfall. If estimated monthly payments for the Alkylation Refining Fees paid by Big West in any semi-annual period exceed the actual amount due for such semi-annual period, OPCO will be required to pay Big West cash in the amount of any excess.

Shortfall payment. A shortfall payment by Big West for unused capacity in any semi-annual period will be applied as credit entitling Big West to have feedstock refined for it by OPCO during the following twelve-month period, subject to certain conditions.

Refining fee increase. In the event that OPCO’s aggregate operating expenses under its services agreements with Big West increase for any given year during the term of the refining agreement, the refining fees payable by Big West to OPCO for the following year will be increased by the amount of the operating cost increase for the prior year. This refining fee increase will be permanent and is intended to offset increases in OPCO’s operating expenses during the term of the refining agreement that would otherwise decrease OPCO’s net operating profit.

Force majeure. A force majeure event under the refining agreement includes, but is not limited to, acts of God; calamities; fire, war; terrorism; unusually bad weather; interruption or delay in transportation and any inadequacy, shortage or failure or breakdown of supply of raw materials; certain labor difficulties (whether or not the demands of the employee are within the power of the claiming party to concede); and compliance with governmental orders or laws not brought about by an act or omission of the party claiming force majeure. Changes in costs of goods or services or changes in costs of regulatory or other compliance with law or lack of finances are not force majeure events. During any force majeure event with respect to Big West’s facility, OPCO will be relieved of its obligations to refine feedstock to the extent such obligations are affected by the force majeure event. If the force majeure event is solely with respect to Big West’s facility, Big West will be obligated to continue to pay refining fees, including with respect to feedstock that Big West is unable to deliver due to the force majeure event. During any force majeure event with respect to OPCO’s units, Big West will be relieved of its obligation to deliver feedstock and pay refining fees, to the extent such obligations are affected by the force majeure event.

Events of default. With respect to an event of default (other than bankruptcy) under the refining agreement, the non-defaulting party must engage in mediation and a determination by Utah courts that an event of default has occurred before exercising its remedies. In addition, if Big West terminates the refining agreement in violation of the agreement, then Big West must pay OPCO as liquidated damages the present value of the anticipated refining fees (less anticipated payments to Big West under the services agreements and site lease) that would have been received by OPCO over the remainder of the term.

Term. The refining agreement has an initial term of 25 years and may be renewed thereafter if agreed by both parties.

For a more complete description of the refining agreement and the risks related to this agreement and other agreements relating to the operation of OPCO’s units, please see “Business—Agreements with Affiliates” and “Risk Factors—Risks Related to Our Business.” See also “Business—OPCO Process Units” and “Business—Historical Throughput and Production” for historical data relating to the throughput and production of OPCO’s units.

Risk Factors

An investment in our common units involves risks associated with our business operations and the operations of the Salt Lake refining complex generally, the state of the refining industry, the credit of Big West, the terms of our contractual agreements with Big West, regulatory and legal matters, our limited partnership structure, conflicts of interest with Flying J and Big West and the tax characteristics of our common units. Those risks are described under the caption “Risk Factors” immediately following this summary beginning on page 21.

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Formation Transactions and Partnership Structure

We are a Delaware limited partnership formed on December 3, 2007 to hold an interest in OPCO which will acquire, own and operate the Salt Lake refining complex’s MSCC unit and alkylation unit, which were historically owned by Big West.

In connection with this offering and the related formation transactions:

• Big West will cause to be transferred to OPCO the Salt Lake refining complex’s MSCC unit and alkylation unit;

• Big West will transfer to us a 34.999% limited partner interest in OPCO and a 100.0% membership interest in Big West Operating GP, LLC, which holds a 0.001% general partner interest in OPCO;

• we will issue to our general partner, Big West GP, LLC, an indirect wholly owned subsidiary of Big West, 1,218,750 common units, a 2.0% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.43125 per unit per quarter;

• we will issue to the owner of our general partner 6,906,250 subordinated units;

• we will enter into a new $130.0 million senior secured term loan and a $151.0 million senior unsecured term loan under our new credit facility and distribute the net proceeds of $280.0 million to Big West; and

• we will sell 8,125,000 common units to the public in this offering, representing a 49.0% limited partner interest in us, and we will use the net proceeds as described in “Use of Proceeds.”

In addition, at or prior to the closing of this offering:

• OPCO will enter into a refining agreement with Big West pursuant to which OPCO’s units will process feedstocks provided by Big West for per barrel refining fees;

• OPCO will enter into other agreements with Big West relating to the operation of OPCO’s units, the sharing of various site services, a site lease and other matters; and

• we and OPCO will enter into an omnibus agreement with Big West, Flying J, our general partner and other affiliates governing, among other things, indemnification obligations, our grant to Big West of a right of first refusal on any proposed transfer of certain assets, certain limitations on Flying J’s right to compete with us and Big West’s agreement to reimburse us for certain general and administrative expenses.

For further details on our agreements with Big West, Flying J and their affiliates, please read “Business—Agreements with Affiliates” and “Certain Relationships and Related Party Transactions.”

Holding Company Structure

We are a holding entity and will conduct our operations and business through controlled affiliates, as is common with publicly traded limited partnerships, to maximize operational flexibility. Initially, we will conduct all of our operations through OPCO. We intend to conduct additional operations in the future through wholly owned subsidiaries.

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The following diagram depicts our organization and ownership structure after giving effect to the offering and the related formation transactions.

Organizational Structure After the Formation Transactions

Public common units	49.0	%
Common units owned by our general partner	7.3	%
Subordinated units owned by the owner of our general partner	41.7	%
General partner interest	2.0	%
Total	100.0	%

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Management and Ownership of Big West Oil Partners, LP

Big West GP, LLC, our general partner, has sole responsibility for conducting our business and for managing our operations. Flying J indirectly owns our general partner. The President and Chief Executive Officer, the Chief Operating Officer and the Chief Financial Officer and all of the non-independent directors of Big West GP, LLC also serve as executive officers or directors of Flying J Inc. or one of its affiliates. For more information about these individuals and relationships, please read “Management—Directors and Executive Officers of Big West GP, LLC.”

Our wholly owned subsidiary, Big West Operating GP, LLC, the general partner of OPCO, will manage OPCO’s operations and activities. The board of directors of our general partner has the authority to appoint and elect the officers of Big West Operating GP, LLC. Certain directors and officers of our general partner also serve as executive officers of OPCO’s general partner. The partnership agreement of OPCO will provide that certain actions relating to OPCO must be approved by the board of directors of our general partner on our behalf. These actions will include, among other things, establishing estimated maintenance capital, turnaround and other cash reserves and the determination of the amount of quarterly distributions by OPCO to its partners, including us. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—OPCO Partnership Agreement and Big West Operating GP, LLC Limited Liability Company Agreement.”

Our general partner will not receive any management fee or other compensation in connection with its management of our business but will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. Our general partner will also be entitled to distributions on its general partner interest and, if specified requirements are met, on its incentive distribution rights. Please read “Certain Relationships and Related Party Transactions” and “Management—Reimbursement of Expenses of Our General Partner.”

Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect the directors of our general partner. Big West will elect all of the directors of our general partner. At least three of the directors will be independent, as defined under the independence standards of the NYSE, not later than one year following the listing of our units on the NYSE. We are not obligated to have, and we will not have, a majority of independent directors.

We and OPCO will enter into agreements with Big West relating to the operation of OPCO’s units, the sharing of various site services, a site lease and other matters.

Upon the closing of this offering, we and OPCO will enter into an omnibus agreement with Flying J, Big West, our general partner and others. This agreement addresses: (i) Big West’s 25-year indemnification of us for certain potential environmental and toxic tort liabilities; (ii) our grant to Big West of a right of first refusal on any proposed transfer of assets that service the Salt Lake refining complex; (iii) Flying J’s agreement for a period of five years following the closing of this offering not to create any new publicly traded limited partnership that (A) conducts the business of refining crude oil or other hydrocarbon products in the continental United States or (B) owns or operates the Longhorn refined products pipeline; (iv) Big West’s agreement for a period of three years following the closing of this offering to reimburse us for incremental general and administrative expenses that we will incur as a public partnership in excess of $1.5 million per year; and (v) other matters. Please read “Business—Agreements with Affiliates” and “Certain Relationships and Related Party Transactions.”

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Principal Executive Offices and Internet Address

Our principal executive offices are located at 1104 Country Hills Drive, Ogden, Utah 84403, and our telephone number is (801) 624-1000. Our website is located at http://www.                    .com. We will make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

Big West GP, LLC, our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is indirectly owned by Flying J, the officers and directors of Big West GP, LLC also have fiduciary duties to manage the business of our general partner in a manner beneficial to Flying J. In addition, the general partner of OPCO has a fiduciary duty to manage OPCO in a manner beneficial to us, as the general partner’s owner, and to OPCO’s limited partners, including us and Big West. OPCO’s general partner will be member managed and our general partner’s board of directors will appoint its officers. The board of directors of our general partner, which includes some of the directors and executive officers of Flying J and its affiliates, may resolve any conflict between the interests of us and our unitholders and Flying J and its affiliates, and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not be in the best interest of us or our unitholders.

As a result of these relationships, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and Flying J and its other affiliates, including our general partner and OPCO, on the other hand. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties” and “Risk Factors—Risks Inherent in an Investment in Us.”

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to unitholders. By purchasing a common unit, you are treated as having consented to various actions contemplated in our partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.

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The Offering

Common units offered to the public 8,125,000 common units.

9,343,750 common units, if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering 9,343,750 common units representing a 56.3% limited partner interest in us and 6,906,250 subordinated units representing a 41.7% limited partner interest in us.

Use of proceeds We intend to use the net proceeds of approximately $148.0 million from this offering, after deducting underwriting fees, discounts and commissions and estimated offering expenses to:

• purchase approximately $130.0 million of certificates of deposit, which will be assigned as collateral to secure the senior secured term loan under our new credit facility; and

• make an $18.0 million cash distribution to Big West to reimburse it for certain capital expenditures.

We also anticipate that we will borrow approximately $130.0 million in secured term debt and $151.0 million in unsecured term debt under our new credit facility upon the closing of this offering, and we will distribute the $280.0 million aggregate amount of the proceeds of such borrowings (net of $1.0 million of financing fees) to Big West as partial consideration for the 35.0% interest in OPCO contributed to us upon the closing of this offering.

If the underwriters’ option to purchase additional common units is exercised, we will use the net proceeds to (1) purchase an equivalent amount of certificates of deposit, which will be assigned as collateral to secure the additional term loan borrowings described below, and (2) borrow an additional amount under the senior secured term loan portion of our new credit facility equal to the net proceeds to be received from the exercise of the underwriters’ option. The proceeds of the additional senior secured term loan borrowings will be used to redeem from our general partner a number of common units equal to the number of common units issued upon exercise of the underwriters’ option to purchase additional common units.

Cash distributions We intend to make minimum quarterly distributions of $0.37500 per unit per quarter ($1.50 per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

Within 45 days after the end of each fiscal quarter, beginning with the fiscal quarter ending April 30, 2008, we will distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through the end of the quarter in which the offering occurs based on the actual length of the period. Our ability to pay our minimum quarterly distribution is subject to various

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restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement, in “How We Make Cash Distributions—Distributions of Available Cash—Available Cash” and in the glossary of terms attached as Appendix B. The amount of available cash may be greater than or less than the minimum quarterly distribution to be distributed on all units.

In general, we will pay any cash distributions we make each quarter in the following manner:

• first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received a minimum quarterly distribution of $0.37500 plus any arrearages from prior quarters;

• second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.37500; and

• third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.43125.

If cash distributions to our unitholders exceed $0.43125 per common unit in any quarter, our general partner will receive increasing percentages, up to 50.0%, of the cash we distribute in excess of that amount. We refer to the amount of these distributions in excess of the 2.0% general partner interest as “incentive distributions.” Please read “How We Make Cash Distributions—General Partner Interest and Incentive Distribution Rights.”

Our pro forma cash available for distribution generated during the fiscal year ended January 31, 2007 and the twelve months ended July 31, 2007 would have been sufficient to allow us to pay the full minimum quarterly distribution on all common units and subordinated units. We believe that, based on the assumptions listed under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash from operations to enable us to pay the full minimum quarterly distribution for the twelve months ending January 31, 2009 on all common units and subordinated units.

Subordinated units The owner of our general partner will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that, in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.37500 per unit only after the common units have received the minimum quarterly distribution plus arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue

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arrearages. The subordination period will end if we have earned and paid the annualized minimum quarterly distribution of $1.50 on each outstanding common unit and subordinated unit and the 2.0% general partner interest for any three consecutive, non-overlapping, four quarter periods ending on or after January 31, 2013 and there are no common unit arrearages.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

Early conversion of the subordinated units If we have earned and paid at least the annualized minimum quarterly distribution of $1.50 on each outstanding common unit and subordinated unit and the 2.0% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after January 31, 2011 and there are no common unit arrearages, 25.0% of the subordinated units will convert into common units. If we meet these tests for any three consecutive, non-overlapping four-quarter periods ending on or after January 31, 2012, an additional 25.0% of the subordinated units will convert into common units. The early conversion of the second 25.0% of the subordinated units may not occur until at least one year after the early conversion of the first 25.0% of subordinated units.

In addition to the early conversion described above, if we have earned and paid from operating surplus at least $1.8750 (125% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the 2.0% general partner interest for any two consecutive, non-overlapping four-quarter periods ending on or after January 31, 2011 and there are no common unit arrearages, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please read “How We Make Cash Distributions—Subordination Period—Early Conversion of Subordinated Units.”

Issuance of additional units We may issue an unlimited number of additional units, including units that are senior in right of distributions, liquidation and voting to the common units, without obtaining unitholder approval. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Securities.”

Limited voting rights Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²/₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its owner will own 1,218,750 common units and 6,906,250 subordinated units, representing 50.0% of our

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outstanding units. This will give our general partner the practical ability to prevent its involuntary removal. Please read “The Partnership Agreement—Voting Rights.”

Limited call right If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.

Estimated ratio of taxable income to distributions We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending January 31, 2011, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be    % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $         per unit, we estimate that your average allocable federal taxable income per year will be no more than $         per unit. The difference between the amount of cash distributed to you and your share of taxable income is attributable to various non-cash expenses, including depreciation that will be allocated to you. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

Material tax consequences For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Trading We intend to apply to list our common units on the New York Stock Exchange under the symbol “BWO.”

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Summary Historical Financial and Operating Data and Pro Forma Financial Data

The following table shows summary historical financial and operating data of Big West Oil Predecessor, the predecessor to Big West Oil Partners, LP, and pro forma financial data of Big West Oil Partners, LP for the periods and as of the dates indicated. The summary historical financial data as of January 31, 2005, 2006 and 2007 and July 31, 2006 and 2007 and for the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2006 and 2007 are derived from the financial statements of Big West Oil Predecessor. The historical financial statements of Big West Oil Predecessor reflect all of the assets located in the Salt Lake refining complex, as well as, for periods on and after March 15, 2005, the refining complex in Bakersfield, California that Big West of California, LLC, a wholly owned subsidiary of Big West, acquired from Shell Oil Products U.S. The assets of our partnership on the closing date of the offering will consist only of our interests in OPCO. OPCO’s assets will consist only of the MSCC unit and the alkylation unit located at the Salt Lake refining complex. Accordingly, the historical financial statements reflect significantly larger asset values and results of operations than our partnership will have on the closing date of the offering. Moreover, Big West Oil Predecessor’s historical financial statements before and after the acquisition of the Bakersfield refining complex on March 15, 2005 are not directly comparable, because periods subsequent to the acquisition reflect the addition of the Bakersfield refining complex’s assets and results of operations. In addition, Big West expanded the crude unit at the Salt Lake refining complex in 2004 and expanded the MSCC unit and the alkylation unit at the Salt Lake refining complex in 2006, which resulted in increased throughput at that refinery subsequent to those expansions.

The summary pro forma financial data as of July 31, 2007 and for the fiscal year ended January 31, 2007 and the six months ended July 31, 2007 are derived from the unaudited pro forma financial statements of Big West Oil Partners, LP. The pro forma adjustments have been prepared as if the transactions listed below had taken place on July 31, 2007 in the case of the pro forma balance sheet, or as of February 1, 2006 in the case of the pro forma statements of operations for the fiscal year ended January 31, 2007 and the six months ended July 31, 2007. The pro forma financial data give pro forma effect to:

• the contribution to OPCO of the Salt Lake refining complex’s MSCC unit and alkylation unit;

• the transfer by Big West to us of a 34.999% limited partner interest in OPCO and a 100.0% interest in Big West Operating GP, LLC, which holds a 0.001% general partner interest in OPCO;

• the issuance by Big West Oil Partners, LP to subsidiaries of Big West of 1,218,750 common units, 6,906,250 subordinated units, the 2.0% general partner interest represented by 331,633 general partner units, and the incentive distribution rights;

• the sale by Big West Oil Partners, LP of 8,125,000 common units to the public at an assumed initial offering price of $20.00 per unit in this offering;

• the payment of estimated underwriting commissions and other offering and transaction expenses;

• the application of the net proceeds of the offering as described under “Use of Proceeds;”

• our entry into a new $130.0 million senior secured term loan and a $151.0 million senior unsecured term loan under our new credit facility and the distribution of the net proceeds of $280.0 million to Big West; and

• the entry by OPCO into the refining agreement, shared services agreement, master services agreement and site lease with Big West and its affiliates, and the entry by OPCO and us into the omnibus agreement with Flying J, Big West and their affiliates.

The following table includes the non-GAAP financial measure Adjusted EBITDA. We define Adjusted EBITDA as earnings before income tax expense, interest expense, depreciation and amortization and gains or losses on derivative activities. For a reconciliation of Adjusted EBITDA to net income and net cash flow provided by (used in) operating activities, please read “—Non-GAAP Financial Measure” below.

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We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	Big West Oil Predecessor Historical															Big West Oil Partners, LP Pro Forma
	Year Ended January 31,									Six Months Ended July 31,						Year Ended January 31,			Six Months Ended July 31,
	2005			2006			2007			2006			2007			2007			2007
										(unaudited)						(unaudited)
	(in thousands, except for per unit and operating data)
Statement of Operations Data:
Sales	$	715,700		$	2,016,973		$	2,410,078		$	1,286,035		$	1,412,664		$	—		$	—
Operating costs and expenses:
Cost of products		619,726			1,729,022			2,149,090			1,121,375			1,143,500			—			—
Cost of refining		24,945			133,200			140,257			70,516			84,578			—			—
Selling, general and administrative		4,785			10,216			12,208			6,181			11,738			1,500	(a)		750	(a)
Depreciation and amortization		6,130			19,220			18,748			8,882			13,612			—			—
Gain on sale of other assets		—			—			(838	)		—			(2,208	)		—			—
Total operating costs and expenses		655,586			1,891,658			2,319,465			1,206,954			1,251,220			1,500			750
Income from operations		60,114			125,315			90,613			79,081			161,444			(1,500	)		(750	)
Other income (expense):
Interest expense, net		(958	)		(2,150	)		219			(581	)		451			(10,475	)		(5,238	)
Loss on derivative activities		(7,084	)		(18,106	)		(2,528	)	��	(2,727	)		(4,003	)		—			—
Income (loss) from investments in affiliated companies(b)		—			—			—			—			—			35,134			17,831
Total other income (expenses)		(8,042	)		(20,256	)		(2,309	)		(3,308	)		(3,552	)		24,659			12,594
Net income	$	52,072		$	105,059		$	88,304		$	75,773		$	157,892		$	23,159		$	11,844
General partner interest in net income																$	463		$	237
Limited partner interest in net income attributable to common units																	14,016			7,008
Limited partner interest in net income attributable to subordinated units																	8,680			4,599
Basic and diluted pro forma net income per limited partner unit:
Common units (basic and diluted)																$	1.50		$	.75
Subordinated units (basic and diluted)																	1.26			.67
Weighted average units:
Common units (basic and diluted)																	9,343,750			9,343,750
Subordinated units (basic and diluted)																	6,906,250			6,906,250
Cash Flow Data:
Cash flows provided by operating activities	$	49,319		$	165,369		$	58,518		$	67,176		$	174,577
Cash flows used in investing activities		(31,726	)		(211,277	)		(150,328	)		(38,996	)		(91,883	)
Cash flows provided by (used in) financing activities		(19,856	)		47,250			90,480			(28,499	)		(25,462	)

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	Big West Oil Predecessor Historical										Big West Oil Partners, LP Pro Forma
	Year Ended January 31,						Six Months Ended July 31,				Year Ended January 31, 2007		Six Months Ended July 31, 2007
	2005		2006		2007		2006		2007
							(unaudited)				(unaudited)
	(in thousands, except for operating data)
Other Data:
Adjusted EBITDA(c)	$	66,244	$	144,535	$	109,361	$	87,963	$	175,056	$	35,128	$	17,829
Capital expenditures		21,726		35,330		151,418		39,201		94,203		—		—
Balance Sheet Data (end of period):
Total assets	$	173,903	$	475,716	$	659,368	$	552,213	$	851,936			$	146,524
Total debt		22,211		35,392		146,571		6,399		180,000				281,000	(d)
Total liabilities		88,374		238,135		360,339		238,859		452,515				281,000
Member’s equity		85,529		237,581		299,029		313,354		399,421				—
Partners’ capital		—		—		—		—		—				(134,476	)
Operating Data:
Salt Lake refining complex throughput (bpd)(e)		29,520		32,027		30,426		29,148		30,939
Bakersfield refining complex throughput (bpd)(e)		—		56,874		54,671		57,424		62,945
Salt Lake refining complex sales (bpd)		36,858		32,953		31,565		31,199		31,869
Bakersfield refining complex sales (bpd)		—		55,675		56,555		57,992		65,391
Per barrel of crude throughput:
Salt Lake refining complex refining margin (per barrel of throughput)(f)	$	8.88	$	11.10	$	14.88	$	14.83	$	26.80
Bakersfield refining complex refining margin (per barrel of throughput)(f)		—		8.61		4.80		8.31		10.45
Salt Lake refining complex cost of refining per barrel(g)		2.31		2.43		2.84		2.95		3.76
Bakersfield refining complex cost of refining per barrel(g)		—		5.71		5.45		5.29		5.57

(a) Consists of estimated incremental general and administrative expenses we will incur as a result of being a publicly traded partnership, such as costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations and registrar and transfer agent fees, director compensation and incremental insurance costs, including director and officer liability insurance.

(b) Reflects our 35.0% share of OPCO’s earnings based on the refining fees OPCO would have received under the refining agreement using historical throughput volumes.

(c) Please read “—Non GAAP Financial Measure” below for a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and cash flow from operating activities.

(d) Consists of $130.0 million of term debt secured by certificates of deposit and $151.0 million of unsecured term debt.

(e) Total refinery throughput represents the total crude oil and other feedstock inputs in the refinery production process.

(f) Refining margin per barrel is used to evaluate performance, allocate resources and compare profitability to other companies in the industry. Refining margin per barrel is calculated by dividing the difference between sales and cost of products by total throughput volumes. Refining margin per barrel may not be comparable to similarly titled measures used by other companies. Investors and analysts use these measures to help analyze and compare companies in the industry on the basis of operating performance.

(g) Refining cost per barrel is used to evaluate the efficiency of operations and to allocate resources. Cost of refining per barrel is calculated by dividing cost of refining by total throughput volumes. Cost of refining per barrel may not be comparable to similarly titled measures used by other companies. Investors and analysts use these measures to help analyze and compare companies in the industry on the basis of operating performance.

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Non-GAAP Financial Measure:

Adjusted EBITDA represents earnings before income tax expense, interest expense, depreciation and amortization, gains or losses on derivative activities and the effect of straight line rents. However, Adjusted EBITDA is not a recognized measurement under accounting principles generally accepted in the United States, or GAAP. Our management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by security analysts, investors and other interested parties in the evaluation of companies in the refining industry. In addition, our management believes that Adjusted EBITDA is useful for the following reasons:

• Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry. Our calculation of Adjusted EBITDA eliminates the effects of financing, income taxes, derivative activities and depreciation and amortization, all of which may vary for different companies for reasons unrelated to overall operating performance.

• Management uses Adjusted EBITDA as a measure of operating performance and return on capital and, therefore, public disclosure of Adjusted EBITDA calculated in the same manner is important in explaining how management evaluates our partnership.

• We expect that our new credit facility will require us to maintain a minimum ratio of Adjusted EBITDA to interest expense. In computing Adjusted EBITDA under our new credit facility, we expect we will be required to include deferred revenue (which excludes the effect of straight line rents) and exclude loss on derivative activities. We believe it is important to maintain consistency between the way we report Adjusted EBITDA and the way we are required to calculate Adjusted EBITDA for purposes of our new credit facility.

• Adjusted EBITDA is a frequently used financial measure for evaluating cash available for distribution.

Adjusted EBITDA should not be considered as an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

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The following table reconciles EBITDA and Adjusted EBITDA to net income and net cash provided by (used in) operating activities for the periods presented:

	Big West Oil Predecessor Historical															Big West Oil Partners, LP Pro Forma
	Year Ended January 31,									Six Months Ended July 31,						Year Ended January 31, 2007		Six Months Ended July 31, 2007
	2005			2006			2007			2006			2007
										(unaudited)						(unaudited)
	(dollars in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to net income:
Net income	$	52,072		$	105,059		$	88,304		$	75,773		$	157,892		$	23,159	$	11,844
Interest expense (revenue), net		958			2,150			(219	)		581			(451	)		10,475		5,238
Income tax expense		—			—			—			—			—			—		—
Depreciation and amortization		6,130			19,220			18,748			8,882			13,612			—		—
EBITDA		59,160			126,429			106,833			85,236			171,053			33,634		17,082
Deferred revenue(a)																	1,494		747
Loss on derivative activities		7,084			18,106			2,528			2,727			4,003			—		—
Adjusted EBITDA	$	66,244		$	144,535		$	109,361		$	87,963		$	175,056		$	35,128	$	17,829
Reconciliation of EBITDA and Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	49,319		$	165,369		$	58,518		$	67,176		$	174,577
Interest expense, net		958			2,150			(219	)		581			(451	)
Other		(554	)		(1,104	)		77			(414	)		1,072
Change in working capital:
Trade receivables		3,634			50,373			(11,051	)		15,564			22,981
Trade receivables from affiliated companies		(500	)		2,167			7,620			3,321			(931	)
Inventories		15,718			34,681			9,550			25,357			11,386
Prepaid expenses and other assets		1,970			12,836			27,948			1,856			9,545
Accounts payable and accrued liabilities		(11,004	)		(138,115	)		14,273			(28,268	)		(44,387	)
Accounts payable to affiliated companies		(576	)		(102	)		911			68			(3,376	)
Other liabilities		195			(1,826	)		(794	)		(5	)		637
EBITDA		59,160			126,429			106,833			85,236			171,053
Loss on derivative activities		7,084			18,106			2,528			2,727			4,003
Adjusted EBITDA	$	66,244		$	144,535		$	109,361		$	87,963		$	175,056

(a) The refining agreement provides for minimum refining fees for 25 years. OPCO has determined that the minimum refining fees for the first 24 years under the refining agreement are fixed lease payments that are required under GAAP to be recorded on a straight-line basis over the 25-year life of the agreement. Minimum required payments under the refining agreement in excess of the recognized revenue will be recorded as deferred revenue which is expected to be recognized at the end of the refining agreement.

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RISK FACTORS

Limited partner interests are inherently different from common stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

The following risks could materially and adversely affect our business, financial condition or results of operations. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution on our common units and subordinated units.

Initially, our cash flow will be generated exclusively from cash distributions from OPCO, and OPCO’s cash flow will be generated exclusively from payments by Big West under the refining agreement. The level of payments made by Big West will depend upon its ability to pay its minimum obligations under the refining agreement and its ability and desire to increase volumes above the minimums specified in the refining agreement, which in turn are dependent upon, among other things, the level of production at the Salt Lake refining complex and the margins Big West receives for its production there. If Big West is unable to generate sufficient cash flow from its operations to meet its obligations under the refining agreement, OPCO will not have sufficient available cash to distribute to us to enable us to pay the minimum quarterly distribution on all our units.

In addition, the actual amount of cash OPCO will have available for distribution to us will depend on other factors, including:

• the level of fees and expense reimbursements OPCO makes to Big West and its affiliates under the services agreements and the site lease;

• the level of general and administrative expenses we incur;

• the level of capital expenditures OPCO makes;

• debt service requirements and other liabilities;

• restrictions on distributions contained in debt instruments;

• our ability and OPCO’s ability to borrow funds and access capital markets;

• the amount of any cash reserves, including reserves for future maintenance capital expenditures, working capital and other matters, established by the board of directors of our general partner; and

• fluctuations in future working capital needs.

OPCO’s limited partnership agreement provides that it will distribute its available cash to its partners on a quarterly basis. OPCO’s available cash includes cash on hand less any reserves that may be appropriate for operating its business. The amount of OPCO’s quarterly distributions, including the amount of cash reserves not distributed, will be determined by the board of directors of our general partner.

The amount of cash OPCO generates from operations may differ materially from its profit or loss for the period, which will be affected by non-cash items. As a result of this and the other factors mentioned above, OPCO may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records positive net income.

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The assumptions underlying our estimate of cash available for distribution are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause us to have insufficient cash to pay the minimum quarterly distribution on our common units and subordinated units.

Our estimate of cash available for distribution for the twelve months ending January 31, 2009 set forth in “Cash Distribution Policy and Restrictions on Distributions” is based on assumptions that are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If we do not achieve the estimated results, we may not be able to pay the full minimum quarterly distribution or any amount on the common units or subordinated units, in which event the market price of the common units may decline materially.

OPCO is subject to the credit risk of Big West on all of its revenues, and Big West’s leverage and creditworthiness could adversely affect our ability to make distributions to our unitholders.

Our ability to make distributions to unitholders will be entirely dependent on Big West’s ability to meet its minimum contractual obligations under the refining agreement. If Big West defaults on its obligations, our ability to make distributions to our unitholders would be reduced or eliminated. Neither Flying J nor any of its affiliates has guaranteed the payment or performance of Big West’s obligations to us under the refining agreement or any of the services agreements. Also, neither Flying J nor any of its affiliates has any contractual obligation to purchase any refined products from Big West at either the Salt Lake refining complex or the Bakersfield refining complex. Flying J accounted for approximately 35.4%, 42.7% and 40.3% of the refined product sales at the Salt Lake refining complex for the fiscal years ended January 31, 2006 and 2007 and the six months ended July 31, 2007, respectively. Big West has not pledged any assets to us as security for the performance of its obligations.

Big West has not agreed with us to limit its ability to incur indebtedness, pledge or sell assets or make investments and we have no control over the amount of indebtedness Big West incurs, the assets it pledges or sells or the investments it makes. Big West is not itself a reporting company under the Exchange Act and therefore will not publicly release periodic financial information that investors could use to assess its financial condition or creditworthiness as a counterparty under the refining agreement and the related site agreements.

Big West’s only income generating assets are refining assets and Big West’s business is subject to numerous business, operational and regulatory risks as described below. The refining business has historically been volatile. While Big West owns the Bakersfield refining complex through a subsidiary, the subsidiary is under no obligation to make cash distributions to Big West and it may enter into agreements or incur obligations restricting its ability to make distributions.

If Big West were to become bankrupt, a court might characterize our agreements with Big West to be executory contracts and might permit Big West to assume or reject these agreements. Rejection would give rise to a claim by OPCO for damages for breach of the agreements, and Big West might be unable to pay those damages in full, if at all. Also, rejection might prevent OPCO from continuing to receive the services from Big West or from receiving the services on the same terms.

OPCO depends on Big West for all of its revenues, and if Big West were unable to meet its minimum obligations under the refining agreement, our ability to make distributions to unitholders would be reduced or eliminated.

Big West may be unable to generate enough cash flow from operations to meet its minimum obligations under the refining agreement for a variety of reasons, including the following:

• turnarounds and other scheduled and unscheduled maintenance at the Big West facility;

• competition from other refineries that may be able to supply Big West’s end-user markets on a more cost-effective basis;

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• operational problems at the Big West facility or the Bakersfield refining complex, such as catastrophic events, labor difficulties or environmental proceedings, regulatory action or requirements or litigation that compel the cessation of all or a portion of the operations of Big West;

• the inability of Big West to obtain feedstocks (particularly black wax crude oil and condensate) for its refineries at competitive prices; or

• a general reduction in demand for Big West’s refined products due to:

• a local or national recession or other adverse economic condition that results in lower spending by businesses and consumers on gasoline, diesel fuel and travel;

• higher gasoline prices due to higher crude oil prices, higher taxes or stricter environmental regulations;

• a shift by consumers to more fuel-efficient or alternative fuel vehicles or an increase in fuel economy, whether as a result of technological advances by manufacturers, legislation mandating higher fuel economy or otherwise; or

• loss of customers by Big West, including its primary customer, Flying J, or credit problems with Big West’s customers.

If Big West were unable to meet its minimum payment obligations to us as a result of any one or more of these factors, our ability to make distributions to our unitholders would be reduced or eliminated.

Big West’s ability to meet its payment obligations under the refining agreement may be impaired if it realizes low refining margins for a sustained period of time.

Big West’s profitability and its incentive to continue to operate the Big West facility and to maximize throughput at OPCO’s units is primarily affected by the margins between fuel prices and the prices for crude oil and other feedstocks. The cost to acquire feedstocks, the availability of feedstocks and the prices at which Big West can ultimately sell refined products depend upon numerous factors beyond its control. Historically, refining margins have been volatile, and they are likely to continue to be volatile in the future. If the margin between refined products prices and crude oil and other feedstock prices contracts, it could negatively affect the volumes Big West puts through OPCO’s units in excess of the minimum commitment under the refining agreement or its ability to meet its payment obligations under the refining agreement and, accordingly, our results of operations. A prolonged period of adverse refining margins could provide an incentive for Big West to shut down the Big West facility. Big West has no obligation to continue to operate the Big West facility, and may shut down its facility at any time in its sole discretion, which would make it more difficult for Big West to satisfy its obligations under the refining agreement.

The prices at which Big West sells fuel and other refined products are strongly influenced by the commodity price of crude oil, which is highly volatile. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of fuel and other refined products. However, if crude oil prices increase, Big West’s operating margins will fall unless it is able to pass along these price increases to its customers. Big West may not be able to pass on all or any portion of the increased crude oil costs to those customers. Big West historically has made limited use of derivative instruments to manage a portion of the risks associated with commodity price fluctuations. While it has historically used commodity forward contracts to hedge excess inventories, they will not be able to eliminate this risk. Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond Big West’s control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel and other refined products. Such supply and demand are affected by, among other things, changes in global and local economic conditions, domestic and foreign demand for fuel products, worldwide political conditions, the level of foreign and domestic production and importation of crude oil and refined products, U.S. government regulations, and local factors, including the availability of crude oil and other feedstocks, the demand for refined products, the availability of transportation to move feedstocks and refined products to and from refineries, the level of operations of nearby refineries, other market conditions, weather conditions and natural disasters.

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Big West’s ability to meet its payment obligations under the refining agreement may be impaired if it is unable to contract for sufficient volumes of crude oil feedstock.

In order to maintain production levels at the Salt Lake refining complex, Big West must continually contract for new crude oil supplies. A material decrease in crude oil production from the fields that supply the Salt Lake refining complex, as a result of depressed commodity prices, lack of drilling activity, natural production declines or otherwise, could result in a decline in the volume of crude oil OPCO refines. For example, black wax and yellow wax crude oil production levels are particularly sensitive to price declines because they are priced at a significant discount to WTI crude oil. The Salt Lake refining complex would lose its cost advantage that has recently resulted in favorable refining margins if sufficient supply of these feedstocks were no longer available. In addition, OPCO’s and our future growth will depend in part upon whether Big West can contract for additional supplies of crude oil at a greater rate than the rate of natural decline in its currently connected supplies. Fluctuations in crude oil prices can greatly affect production rates and investments by third parties in the development of new oil reserves. Drilling activity generally decreases as crude oil prices decrease. OPCO and Big West have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline or producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, geological considerations, governmental regulation and the availability and cost of capital. If Big West experiences difficulties in contracting for supplies of crude oil for the Salt Lake refining complex, its production levels will fall and Big West may not be able to meet its payment obligations under the refining agreement.

Big West’s ability to meet its payment obligations under the refining agreement may be impaired if the Big West facility is not operational for any sustained period of time.

OPCO’s MSCC unit and alkylation unit are dependent on the process units in the Salt Lake refining complex retained by Big West, such as the crude unit for feedstocks and other process units for further refining products. OPCO is also dependent upon the proper maintenance and efficient and safe functioning of the process units of the Salt Lake refining complex that Big West has retained, as well as the related logistics, storage and other infrastructure at the Salt Lake refining complex.If the unavailability of these process units rendered Big West unable to meet its payment obligations, then our ability to make distributions to our unitholders would be materially adversely affected.

Big West’s ability to meet its payment obligations under the refining agreement may be impaired if transportation of crude oil to or refined products from the Salt Lake refining complex is unavailable.

Big West depends upon third-party pipelines and railcars to transport crude oil to the Salt Lake refining complex and refined products from the Salt Lake refining complex to end user markets. If any of these third-party pipelines or railcars become unavailable to transport crude oil feedstock or refined products because of accidents, government regulation, terrorism or other events, Big West’s ability to meet its payment obligations under the refining agreement may be impaired, which could materially adversely affect our ability to make distributions to our unitholders.

Big West’s ability to meet its payment obligations under the refining agreement may be impaired if Big West loses existing customers or is unable to attract new customers as a result of competition.

The refining industry is highly competitive. The Salt Lake refining complex is one of five refineries competing in the Salt Lake City market. Big West’s competitors include large, integrated, major or independent oil companies that, because of their more diverse operations, larger refineries and stronger capitalization, may be better positioned than Big West to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. Many of Big West’s competitors obtain a significant portion of their feedstocks from company-owned production; competitors that have their own significant production are at times able to offset losses from refining operations with profits from producing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock

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shortages. If Big West is unable to compete effectively, Big West may lose existing customers or fail to acquire new customers, which could have a material adverse effect on its ability to meet its payment obligations under the refining agreement, which would reduce OPCO’s operating results and cash available for distribution to our unitholders.

Because the refining agreement with Big West is presently OPCO’s only source of revenue, our ability to make distributions would be reduced or eliminated if Big West’s obligations under the refining agreement were suspended or terminated.

Big West’s obligations to deliver feedstock and pay refining fees under the refining agreement may be temporarily suspended to the extent OPCO is unable to perform its obligations caused by any of certain events outside the reasonable control of OPCO. Such events include, for example, acts of God or calamities which affect the operation of OPCO’s units; certain labor difficulties (whether or not the demands of the employees are within the power of OPCO to concede); and governmental orders or laws not brought about by an act or omission by OPCO. In addition, Big West is not obligated to pay any refining fees with respect to any period during which OPCO’s units are not operating due to scheduled or unscheduled maintenance or turnarounds. A suspension of Big West’s obligations under the refining agreement would reduce OPCO’s revenues and cash flows, and could materially adversely affect our ability to make distributions to our unitholders.

OPCO is only entitled to increase the refining fees charged under the refining agreement to cover increases in its operating costs under the services agreements, not increases in capital expenditures or our public partnership costs, which could reduce our net operating profit.

OPCO does not have the right to increase the refining fees charged under the refining agreement without Big West’s consent, except that the refining fees will permanently increase to cover increases in operating costs. Any such refining fee increase will occur in the year following the cost increase experienced by OPCO and will not be retroactive.

The refining fees will not increase to cover increases in OPCO’s capital expenditures or in our public partnership costs, which could reduce our net operating profit. Although OPCO currently expects to reserve approximately $1.5 million per year to fund maintenance capital expenditures, including lost revenue during turnarounds, it is possible that actual maintenance capital expenditures or lost revenue during turnarounds will average materially more than $1.5 million per year. This estimate is based on our assumption that OPCO’s units will require a turnaround every five years and that each turnaround will result in four weeks of lost revenue. OPCO’s maintenance capital expenditures and lost revenue during turnarounds could increase for various reasons, including the following:

• turnarounds being required more frequently than every five years or lasting longer than four weeks;

• increases in the cost of labor or materials;

• changes in environmental or other governmental laws or regulations;

• environmental or other legal proceedings;

• changes in customer requirements; and

• the aging of OPCO’s units.

Since Big West will not reimburse OPCO for increases in capital expenditures or lost revenue during turnarounds, any increase in these expenditures or lost revenue over the 25-year term of the refining agreement will result in less cash available for us to distribute to our unitholders.

The fee structure of the refining agreement will limit OPCO’s ability to take advantage of favorable market developments.

The refining agreement limits OPCO’s ability to take advantage of widening crack spreads or other favorable market developments. Under these circumstances, OPCO may not be in a position to enable its

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partners, including us, to benefit from favorable market developments through increased distributions. In addition, under these circumstances, OPCO may be disadvantaged relative to those of its competitors that are in a better position to take advantage of widening crack spreads.

If Big West terminates the refining agreement in violation of the agreement, including because it chooses to shut down the Big West facility for economic reasons, our damages under the agreement may not be sufficient for us to continue to pay distributions to our unitholders.

If Big West terminates the refining agreement in violation of the agreement, including if it shuts down the Big West facility for any reason, then Big West has agreed to pay us liquidated damages equal to the present value of the anticipated refining fees (less operating expenses and capital expenditures) that OPCO would have received over the remainder of the term. Since the calculation of such present value involves the determination of a number of variables, including the volumes to be throughput through OPCO’s units over the remainder of the term, the level of operating expenses and capital expenditures that will be spent by OPCO and the appropriate discount rate, there can be no assurance that OPCO would receive sufficient cash to compensate it for the termination of the refining agreement.

If the refining agreement terminates, Big West may also terminate the services agreements and the site lease. OPCO’s units cannot continue to operate at the Salt Lake refining complex without the provision of certain services that are provided by Big West under the services agreements and a valid leasehold interest on the property underlying OPCO’s refining assets.

If we do receive liquidated damages, we may invest the proceeds in assets that do not perform as expected and produce less cash flow than the refining agreement. In addition, under Utah law, the law governing the refining agreement, a court may hold that the liquidated damages provision is unenforceable, in which case we may not be entitled to the full amount of the liquidated damages under the refining agreement.In addition, even if OPCO were entitled to receive the full amount of liquidated damages under the refining agreement, Big West may be unable to pay these liquidated damages, in full or in part.

Also, if OPCO no longer has operating assets, we will face an increased risk of being treated as an “investment company.” Please read “—Risks Inherent in an Investment in Us—If we cease to control OPCO, we may be deemed to be an investment company under the Investment Company Act of 1940.”

If OPCO is unable to renew or extend the refining agreement or the other agreements with Big West upon expiration of these agreements, our ability to make distributions in the future would be materially adversely affected and the value of our units would decline.

Big West’s obligations under the refining agreement and the related services agreements and site lease terminate after 25 years, unless extended by mutual agreement. If OPCO were unable to reach agreement with Big West on a renewal or extension of these agreements then our ability to make distributions on our common units would be materially adversely affected and the value of our common units would decline.

OPCO may find it difficult to sell its units at the Salt Lake refining complex should it seek to sell them.

Because OPCO’s units are located at the Salt Lake refining complex and are optimized for use by the Big West facility, Big West may be the only logical purchaser for OPCO’s units, and Big West has no obligation to purchase OPCO’s units. Even if a third party purchaser for OPCO’s units did exist, the market price for OPCO’s units could be significantly discounted because, absent an agreement between the third party purchaser and Big West for provision of certain site services and a leasehold interest in the land underlying OPCO’s units, the units might only be useful to the third party if they were removed and installed at another refining complex. Big West has no obligation to enter into any agreements with a purchaser of OPCO’s units. In addition, any transfer of OPCO’s units to a third party would trigger Big West’s right of first refusal, which may further discount the price a third party is willing to pay.

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OPCO depends upon Big West for numerous services and for its labor force.

In connection with this offering, OPCO will enter into a shared services agreement and a master services agreement with Big West pursuant to which Big West will be obligated to provide OPCO operating and other key site services. Big West will provide the services of certain of its employees, who will act as OPCO’s agents in operating and maintaining OPCO’s units. If these agreements are terminated or if Big West or its affiliates fail to satisfactorily provide these services or employees, OPCO would be required to hire labor, provide these services internally or find a third-party provider of these services. Any services or labor OPCO chooses to provide internally may not be as cost effective as those that Big West or its affiliates provide, particularly in light of OPCO’s lack of experience as an independent organization. If OPCO is required to obtain these services or labor from a third party, it may be unable to do so in a timely, efficient and cost-effective manner, the services or labor it receives may be inferior to or more costly than those that Big West is currently providing, or such services and labor may be unavailable. Given the integration of OPCO’s units and the Big West facility at the Salt Lake refining complex, it may not be practical for us or for a third party to provide site services or labor for OPCO’s units separately.

Because OPCO’s process units have limited functions and are integrated with the Big West facility, OPCO may be unable to compete effectively for third-party refining business.

OPCO’s assets consist of the MSCC unit and the alkylation unit located at the Salt Lake refining complex. These process units can produce only a limited range of refined products for which there is a limited market. The input of the MSCC unit consists largely of gas oils, and the output of the alkylation unit consists largely of high octane gasoline blending stocks. These units do not produce a broad range of fuels and other hydrocarbon products, and the majority of products they do produce require further processing to meet all applicable legal requirements and the needs of many customers. As a result, OPCO’s units are unlikely to be able to compete effectively for customers other than Big West or its affiliates. In addition, these units are integrated with the Big West facility and the functioning of these units has been optimized to service Big West’s refining and marketing supply chain and for the operating requirements of the Big West facility. OPCO does not own or lease storage tanks and other equipment necessary in order for OPCO to throughput product on behalf of a third party. If OPCO were to refine products on behalf of third parties, OPCO would need to lease tanks and related facilities from Big West at an additional cost, and this expense would reduce OPCO’s profits. OPCO also may not be in a position to change its operations to adapt to different market conditions or customer requirements if its plans are not compatible with those of Big West for the other process units in the Salt Lake refining complex. It may be difficult or costly to connect OPCO’s units to feedstock supply or offtake locations outside of the Salt Lake refining complex. In addition, it may be difficult for OPCO to compete effectively for the business of unrelated third parties, which may have requirements different from those of Big West. Therefore, in the event Big West fails to use the full capacity of OPCO’s units, OPCO is unlikely to be able to attract sufficient business to generate replacement revenues from third parties.

OPCO’s ability to receive greater cash flows from increases in the throughput at the Salt Lake refining complex is limited.

OPCO’s ability to increase throughput volumes through its assets is constrained by the capacity limitations of those assets, which are currently operating at close to full capacity. As discussed above, there are various factors that might cause Big West not to throughput more than the minimum volumes at OPCO’s units. Our forecast under “Our Cash Distribution Policy and Restrictions on Distributions” assumes OPCO will continue to process volumes in excess of the minimum volumes. On a pro forma basis, had OPCO received only the minimum payments under the refining agreement, our distributable cash flow would have been reduced by approximately $1.0 million for the year ended January 31, 2007. Furthermore, the per barrel refining fees OPCO receives on any volumes throughput in excess of the contractual minimums are significantly less than the per barrel refining fees for the minimum volumes. Specifically, OPCO will receive $29.00 per barrel for the first 10,000 bpd of gas oil processed at the MSCC Unit in any semi-annual period and $5.00 per barrel for any barrels of gas oil processed in excess of 10,000 bpd during that semi-annual period, and OPCO will receive $19.00 per

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barrel for the first 2,000 bpd of alkylate produced at the alkylation unit and $3.00 per barrel for any barrel of alkylate in excess of 2,000 bpd during that semi-annual period. As a result, we anticipate only minimal increases in our cash flow due to increases in throughput by Big West at the Salt Lake refining complex.

Our reconfiguration and enhancement of assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect OPCO’s and our business, operating results, cash flows and financial condition.

OPCO’s units are integrated with the Big West facility and the functioning of these units has been optimized for the operating requirements of the Big West facility. OPCO’s ability to increase production volumes is limited by the configuration of the Salt Lake refining complex. The construction of additions or modifications to OPCO’s units would involve numerous regulatory, environmental, political and legal uncertainties beyond our and OPCO’s control and would require significant amounts of capital. If OPCO were to undertake a project, it might not be completed on schedule or at the budgeted cost, or at all. Moreover, OPCO’s and our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if OPCO’s units are expanded, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed.

We face significant hurdles in making acquisitions on economically favorable terms that will enable us to increase our distributions to unitholders.

A principal focus of our strategy is to increase the per unit cash distribution on our units by expanding our business through the purchase of additional assets. Our ability to achieve this strategy is subject to a number of factors beyond our control, including the following:

• Flying J and its affiliates have no obligation to offer us the opportunity to purchase from them assets they currently own, including additional interests in OPCO, or assets they acquire in the future.

• Flying J and its affiliates may face legal or business hurdles in contributing or selling assets to OPCO or to us. Tax considerations may affect the willingness of Flying J and its affiliates to sell assets to us for cash. Provisions in Big West’s or Flying J’s existing or future credit agreements could restrict their ability to sell or contribute assets to us.

• We will rely on Flying J and its affiliates to identify and evaluate for us prospective assets or businesses for acquisition. Flying J and its affiliates are not obligated to present us with acquisition opportunities and are permitted under our partnership agreement to take these opportunities for themselves. Because Big West controls our general partner, we will not be able to pursue or consummate any acquisition opportunity unless Big West causes us to do so.

• Flying J and its affiliates, including Big West, will not be restricted under our partnership agreement or the omnibus agreement or any other agreement from owning assets or engaging in businesses that compete directly or indirectly with us, provided that they do not compete through the vehicle of a new publicly traded partnership that (1) conducts the business of refining crude oil or other hydrocarbon products in the continental United States or (2) owns or operates the Longhorn refined products pipeline. Flying J and Big West are large, established participants in the energy business, and each has significantly greater resources and experience than we have, which may make it more difficult for us to compete with them.

• Even if Flying J and its affiliates offer OPCO or us an opportunity to buy assets from them or from third parties, OPCO or we may not be able to consummate any such acquisition for several reasons, including an inability to agree on acceptable purchase terms, an inability to obtain financing for the purchase on acceptable terms, the lack of required regulatory approvals, and restrictions in credit facilities, indentures or other contracts.

• We may be outbid by competitors for third party assets.

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If Flying J and its affiliates decline to present us with, or successfully compete against us for, acquisition opportunities, or if we are unable to consummate any acquisition opportunities we have, we will be unable to increase our distributions, which could adversely affect the market price of our units. Please read “Conflicts of Interest and Fiduciary Duties” for a discussion about the ability of Flying J and its affiliates to compete with us.

Even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per common unit.

Any acquisition involves potential risks, including, among other things:

• performance by the acquired assets and businesses that is below the forecasts we used in evaluating the acquisition;

• a significant increase in our indebtedness and working capital requirements;

• an inability to timely and effectively integrate the operations of recently acquired businesses or assets, particularly those in new geographic areas or in new lines of business;

• the incurrence of substantial unforeseen environmental and other liabilities arising out of the acquired businesses or assets, including liabilities arising from the operation of the acquired businesses or assets prior to our acquisition, for which we are not indemnified or for which the indemnity is inadequate;

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

• customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our funds and other resources.

We may be unable to obtain needed capital or financing on satisfactory terms, which could adversely affect our ability to maintain or grow our cash distribution rate.

To fund the development and maintenance of our existing assets and pursue acquisitions of additional assets or ownership interests in OPCO, we will need to use our cash reserves and cash generated from our operations, additional borrowings or the proceeds from the issuance of additional partnership interests, or some combination thereof, which could limit our ability to pay distributions at the then current distribution rate. The use of cash generated from operations to fund development and acquisition activities 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, the covenants that will be contained in our new credit facility or future debt agreements, adverse market conditions or other contingencies and uncertainties that are beyond our control. Our failure to obtain the funds necessary for future development, maintenance and acquisition activities could materially adversely affect our business, results of operations, financial condition and ability to pay distributions and limit our growth. 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 dangers inherent in operations at the Salt Lake refining complex could cause disruptions in OPCO’s operations and could expose us to potentially significant losses, costs or liabilities. OPCO is particularly vulnerable to disruptions in its operations because all of its refining operations are conducted within a refining complex that it does not operate.

Operations at the Salt Lake refining complex, including OPCO’s units, are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined

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products. These hazards and risks include, but are not limited to, fires, explosions, pipeline ruptures and spills, natural disasters, third-party interference and mechanical failures at the Salt Lake refining complex or facilities of third parties. These hazards and risks could result in supply, production and distribution difficulties and disruptions, environmental compliance problems or releases of petroleum or petroleum constituents, personal injury or wrongful death claims and other damage to our properties and the properties of others. The Salt Lake refining complex is located in a flood zone and a seismic risk zone and could sustain flood damage or earthquake damage.

Because all of OPCO’s refining operations are conducted at only the Salt Lake refining complex, any such events affecting OPCO’s units could significantly disrupt its production and distribution of refined products, and any sustained disruption could have a material adverse effect on our business, financial condition and results of operations. Moreover, such events could impair or prevent Big West’s performance under the refining agreement. OPCO’s operations are subject to significant interruption, and its cash from operations could be materially adversely affected, if either OPCO’s units or any other part of the Salt Lake refining complex experience a major accident or fire, are damaged by severe weather or other natural disaster, or otherwise are forced to curtail operations or shut down. These hazards could result in substantial losses due to personal injury and/or loss of life, severe damage to, and destruction of property and equipment and releases of petroleum or petroleum constituents or other environmental impacts and may result in curtailment or suspension of our and/or Big West’s operations.

In addition, OPCO’s units consist of processing units which will require periodic maintenance. One or both of the units may require additional unscheduled down time for unanticipated maintenance or repairs that are more frequent than our scheduled turnaround for each unit every five years. Scheduled and unscheduled maintenance reduce OPCO’s and our revenues during the period of time that OPCO’s units are not operating. Because OPCO does not have any other refining assets, it would have no operating cash flow during any such interruption.

The potential limits on insurance coverage could expose us to potentially significant liability costs.

We and OPCO are not fully insured against all risks incident to our business. Furthermore, we and OPCO may be unable to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and ability to make distributions to unitholders. OPCO’s current business interruption insurance at the Salt Lake refining complex will not apply unless a business interruption exceeds 45 days. In addition, although Big West maintains an environmental insurance policy covering certain environmental liabilities at the Salt Lake refining complex, that policy provides maximum coverage of only $4.0 million for each loss and maximum aggregate coverage of only $8.0 million over the policy period.

We and OPCO share the majority of our insurance policies with Big West. These policies contain caps on the insurer’s maximum liability under the policy, and claims made by either Big West or us are applied against the caps. The possibility exists that, in any event in which we or OPCO wish to make a claim under a shared insurance policy, our claim could be denied or only partially satisfied due to claims made by Big West against the policy cap.

A substantial portion of OPCO’s refining workforce is unionized, and it could face labor disruptions that would interfere with OPCO’s operations.

Under OPCO’s services agreements with Big West, certain employees of Big West at the Salt Lake refining complex will act as OPCO’s agents in operating and maintaining OPCO’s process units. As of July 31, 2007, the Salt Lake refining complex employed approximately 140 people, approximately 90 of whom were covered by a

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collective bargaining agreement. The collective bargaining agreement with respect to employees at the Salt Lake refining complex expires on April 16, 2009. Big West may not be able to renegotiate the collective bargaining agreement on satisfactory terms or at all. A failure to do so may increase Big West’s costs or cause Big West to limit or halt operations in the Salt Lake refining complex before a new agreement is reached. In addition, Big West’s existing labor agreements may not prevent a strike or work stoppage in the future, and any such work stoppage could have a material adverse effect on OPCO’s results of operations and financial condition and our ability to make distributions to unitholders.

We and OPCO may incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations or otherwise comply with health, safety, environmental and other laws and regulations.

OPCO’s operations require numerous permits and authorizations under various laws and regulations. These authorizations and permits are subject to revocation, renewal or modification and can require operational changes to limit impacts or potential impacts on the environment and/or health and safety. OPCO’s processes are subject to variable conditions, and it might not always be compliance with applicable permit requirements. Additional violations of permit conditions or other legal requirements could result in increased fines, criminal sanctions, permit revocations, injunctions and/or facility shutdowns. In addition, any major changes in our operations may require modifications to the existing permits applicable to OPCO or upgrades to OPCO’s existing pollution control equipment. From time to time, the Salt Lake refining complex has been investigated for alleged violations of health, safety, environmental and other laws. If a lawsuit or enforcement proceeding were commenced or resolved against OPCO or us, we could incur significant costs and liabilities. Moreover, because the permits and authorizations for OPCO’s air emissions, water discharges and waste handling activities cover the entire Salt Lake refining complex, compliance by the Salt Lake refining complex with those permits or other applicable requirements of federal, state or local environmental laws may affect our ability to obtain and maintain the permits and authorizations that are necessary for operation of OPCO’s units. In addition, because the permits and authorizations for OPCO’s operations are obtained by held by Big West, we have no control over the process of obtaining and maintaining the permits and authorizations required for operation of OPCO’s units. If Big West fails to obtain or maintain the permits necessary to operate OPCO’s units, the units may have to be shut down and we would have limited recourse against Big West for the resulting loss of cash flows. Any or all of these matters could have a material adverse effect on OPCO’s results of operations and cash flows. Please read “Business—Environmental, Health and Safety Matters.”

OPCO is subject to compliance with stringent environmental laws and regulations that may expose it to substantial costs and liabilities.

OPCO’s refining operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations impose numerous obligations that are applicable to OPCO’s operations, including the acquisition of permits to conduct regulated activities, the incurrence of significant capital expenditures to limit or prevent releases of materials from OPCO’s units and related facilities, and the incurrence of substantial costs and liabilities for pollution resulting both from OPCO’s operations and from those of prior owners. Numerous governmental authorities, such as the EPA and state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with environmental laws, regulations, permits and orders may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of OPCO’s operations. Because the permits and authorizations for OPCO’s air emissions, water discharges and waste handling activities are held by Big West, compliance by the Salt Lake refining complex with those permits or other applicable requirements of federal, state or local environmental laws may affect our ability to obtain and maintain the permits and authorizations that are necessary for our business.

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There is inherent risk of incurring significant environmental costs and liabilities in the operation of OPCO’s units and related facilities due to the handling of petroleum hydrocarbons and wastes, air emissions and water discharges related to OPCO’s operations, and historical operations and waste disposal practices by prior owners. OPCO currently owns or operates properties that for many years have been used for industrial activities, including refining operations. Although Big West’s operating and disposal practices were standard in the industry at the time, petroleum hydrocarbons or wastes have been released in the past on or under the properties to be owned or operated by OPCO. Joint and several strict liability may apply to releases of petroleum hydrocarbons and wastes on, under or from OPCO’s properties and facilities. Private parties, including the owners of properties adjacent to OPCO’s operations and facilities where OPCO’s petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions for various remedies including affirmative requirements to address alleged non-compliance with environmental laws and regulations or applicable permits, reimbursement of the costs of addressing releases of hazardous materials and damages for personal injury or property damage. OPCO may not be able to recover some or any of these costs from insurance or other sources of indemnity.

In addition, new laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement or other developments such as unanticipated remediation obligations and emissions control expenditures and claims for penalties or damages could require us to make additional unforeseen expenditures or result in substantial costs or liabilities. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted or enforced. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. To the extent that the costs associated with meeting any of these requirements are substantial and not adequately provided for, our results of operations, cash flows and ability to make distributions to our unitholders could be materially adversely affected.

OPCO is subject to strict regulations regarding employee safety, and failure to comply with these regulations could adversely affect our ability to make distributions to our unitholders.

The workplaces associated with OPCO’s units are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that OPCO maintain information about hazardous materials used or produced in its operations and that OPCO provide this information to employees, state and local government authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances, could adversely affect our ability to make distributions to our unitholders if OPCO is subjected to fines or significant compliance costs.

Our debt level may limit our flexibility in obtaining additional financing, in pursuing other business opportunities and paying distributions to you.

At the closing of this offering, we expect to have $281.0 million in outstanding indebtedness under our new credit facility. Our level of indebtedness could have important consequences to us, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions 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;

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• 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;

• 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; and

• our debt level may limit our flexibility in responding to changing business and economic conditions.

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 our 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. If OPCO incurs indebtedness in the future, its indebtedness will pose the same risks to our distributions as described above.

Our new credit facility will contain operating and financial restrictions that may restrict our business and financing activities.

The operating and financial restrictions and covenants in our new credit facility and any future financing agreements for OPCO or us could restrict its and our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. For example, we anticipate that our new credit facility will restrict our ability to:

• grant liens;

• make certain loans or investments;

• incur additional indebtedness or guarantee other indebtedness;

• make any material change to the nature of our business;

• make any material dispositions of assets;

• enter into a merger, consolidation, sale leaseback transaction or purchase of assets; or

• make distributions if any potential default or event of default occurs.

We anticipate that we also will be required to comply with certain financial covenants and ratios. Our ability to comply with the covenants and restrictions contained in the new credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. 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 the new credit facility, a significant portion of our indebtedness may become immediately due and payable, and the 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 the new credit facility will be secured by substantially all of our assets, and if we are unable to repay our indebtedness under the new credit facility, the lenders could seek to foreclose on our assets.

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The credit and risk profiles of Big West and Flying J could materially adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

The credit and business risk profiles of Big West and Flying J, including the degree of their financial leverage and the level of their dependence on cash flow from us to service their indebtedness, are factors that may be considered by third parties in evaluating our credit for various reasons, including the following:

• all of OPCO’s assets are located at the Salt Lake refining complex;

• OPCO leases the land on which its assets are located from Big West;

• we and OPCO have no employees of our own and depend upon Big West’s employees;

• Big West is OPCO’s sole counterparty;

• Flying J is Big West’s primary customer for diesel and one of Big West’s primary customers for gasoline at the Salt Lake refining complex; and

• Big West and Flying J control our general partner’s board of directors and therefore our decisions about cash distributions, borrowings, capital expenditures and acquisitions.

If we were to seek a credit rating in the future, our credit rating may be materially adversely affected by the leverage of Big West and Flying J, as credit rating agencies such as Standard & Poor’s and Moody’s may consider the leverage and credit profile of Big West and Flying J because of their ownership interest in and control of us and the strong operational links between Big West and us.Any adverse effect on any credit rating we may be assigned would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.

In connection with this offering we will enter into an omnibus agreement with Big West, Flying J and our general partner regarding certain administrative cost reimbursement, commercial, indemnification and competition matters. Any material nonperformance by Big West under our omnibus agreement could materially and adversely impact our ability to operate and make distributions to unitholders. For more information, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement.”

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.

Terrorist attacks, threats of war or actual war could negatively affect our business, financial condition and results of operations.

Terrorist attacks, threats of war or actual war, as well as events occurring in response to or in connection with them, may adversely affect our business, financial condition and results of operations. Energy-related assets (which could include refineries such as the Salt Lake refining complex) may be at greater risk of attack than other possible targets in the United States. A direct attack on OPCO’s assets or assets used by OPCO or the Salt Lake refining complex would have a material adverse effect on its business, financial condition and results of operations. In addition, any terrorist attack, threat of war or actual war could have an adverse impact on energy prices, including prices for crude oil and refined products. In addition, disruption or significant increases in energy prices could result in government-imposed price controls.

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Risks Inherent in an Investment in Us

Big West will indirectly own a 49.0% limited partner interest in us and will indirectly own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

Following the offering, Big West will indirectly own a 49.0% limited partner interest in us. In addition, Big West will indirectly own our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, the general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires Big West to pursue a business strategy that favors us. Our general partner’s officers and directors have a fiduciary duty to make these decisions in the best interest of Big West, 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 its affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

• our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

• our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to unitholders;

• our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

• our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• affiliates of our general partner may engage in competition with us under certain circumstances and are not obligated to offer business opportunities to us or to offer to contribute or sell additional assets to us;

• our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a capital expenditure for acquisitions or capital improvements, which does not. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

• in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

• neither we nor OPCO will have any employees and will depend upon the officers and employees of Big West, who will also devote significant time to the business of Big West and will be compensated by Big West for the services rendered to it;

• our partnership agreement permits us to classify up to $15.0 million as operating surplus, even if it is generated from asset sales or long-term borrowings, which can be used to fund distributions on the subordinated units or the incentive distribution rights;

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• our general partner intends to limit its liability regarding our contractual and other obligations;

• our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80.0% of our common units;

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

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

Please read “Conflicts of Interest and Fiduciary Duties.”

Although we control OPCO through our ownership of its general partner, OPCO’s general partner owes fiduciary duties to OPCO and OPCO’s other partner, Big West, which may conflict with the interests of us and our unitholders.

Conflicts of interest may arise as a result of the relationships between us and our unitholders, on the one hand, and OPCO, its general partner and its other limited partner, Big West, on the other hand. Big West owns a 65.0% limited partner interest in OPCO and controls our general partner, which appoints the officers of OPCO’s general partner. The officers of OPCO’s general partner have fiduciary duties to manage OPCO in a manner beneficial to us, as such general partner’s owner. At the same time, OPCO’s general partner has a fiduciary duty to manage OPCO in a manner beneficial to OPCO’s limited partners, including Big West. The board of directors of our general partner may resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in the best interest of us or our unitholders.

For example, conflicts of interest may arise in the following situations:

• the allocation of shared overhead expenses to OPCO and us;

• the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and OPCO or its subsidiaries, on the other hand;

• the determination and timing of the amount of cash to be distributed to OPCO’s partners and the amount of cash to be reserved for the future conduct of OPCO’s business;

• the decision as to whether OPCO should make asset or business acquisitions or dispositions, and on what terms;

• the determination or the amount and timing of OPCO’s capital expenditures;

• the determination of whether OPCO should use cash on hand, borrow or issue equity to raise cash to finance maintenance or expansion capital projects, repay indebtedness, meet working capital needs or otherwise; and

• any decision we make to engage in business activities independent of, or in competition with, OPCO.

The fiduciary duties of the officers and directors of our general partner may conflict with those of the officers of OPCO’s general partner.

Our general partner’s officers and directors have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, the Chief Executive Officer, the Chief Operating Officer and the Chief Financial Officer and all of the non-independent directors of our general partner also serve as executive officers of OPCO’s general partner and executive officers or directors of Big West, Flying J or their affiliates, and, as a result, have fiduciary duties, among others, to manage the business of OPCO in a manner beneficial to OPCO and its partners, including Big West. Consequently, these officers and directors may encounter situations in which their fiduciary obligations to OPCO or Big West, on one hand, and us, on the other hand, are in conflict. The

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resolution of these conflicts may not always be in the best interest of us or our unitholders. For a more detailed description of the conflicts of interest involving our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement limits our general partner’s fiduciary duties to our 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. Examples include the exercise of its limited call right, its rights to transfer or vote the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment to our partnership agreement;

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

• generally provides that affiliated 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 being provided to or available from unrelated third parties or be “fair and reasonable” to us. 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 our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners 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 or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal; and

• provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or its conflicts committee 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.

In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

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 did not elect our general partner or its board of directors, and will 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 by the members of our general partner. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of

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these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if unitholders are dissatisfied, initially they cannot remove our general partner without its consent.

The unitholders will be unable initially to remove the general partner without its consent because the general partner and its affiliates will own sufficient units upon completion of the offering to be able to prevent its removal. The vote of the holders of at least 66²/₃% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner and its owner will own 50.0% of our units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished. A removal of the general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner during the subordination period because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

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

Unitholders’ voting rights are further restricted by the partnership agreement provision 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 the unitholders’ ability to influence the manner or direction of management.

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, our partnership agreement does not restrict the ability of the members of our general partner from transferring their respective membership interests in our general partner to a third party. The new members 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 thereby control the decisions taken by the board of directors.

If we cease to control OPCO, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control OPCO and are deemed to be an investment company under the Investment Company Act of 1940 because of our ownership of OPCO partnership interests, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the U.S. Securities and Exchange Commission or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other

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transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates.

You will experience immediate and substantial dilution of $         in net tangible book value per common unit.

The assumed initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $        per unit. Based on an assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $        per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. Please read “Dilution.”

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs.

We do not have our own officers and employees and rely solely on the officers and employees of our general partner and its affiliates to manage our business and affairs. Affiliates of our general partner and Big West conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to the partnership. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner, Big West and their affiliates. If the officers of our general partner and the employees of Big West 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.

Our general partner may cause us to issue an unlimited number of additional units or other equity securities without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity securities will have the following effects:

• our unitholders’ proportionate ownership interest in us may decrease;

• the amount of cash available for distribution on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

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

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

• the ratio of taxable income to distributions may increase.

Our general partner’s determination of the level of cash reserves may reduce the amount of available cash for distribution to you.

OPCO’s partnership agreement provides that the board of directors of our general partner, on our behalf, will approve the amount of reserves from OPCO’s cash flow that will be retained by OPCO to fund its future operating expenditures. Our partnership agreement requires our general partner to deduct from operating surplus cash reserves that it establishes are necessary to fund our future operating expenditures. In addition, our partnership agreement also permits our general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to

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provide funds for future distributions to partners. These reserves will affect the amount of cash available for distribution by OPCO to us and by us to our unitholders. In addition, our general partner may establish reserves for distributions on the subordinated units, but only if those reserves will not prevent us from distributing the full minimum quarterly distribution, plus any arrearages, on the common units for the following four quarters. As described above in “Risks Related to Our Business—Each quarter our general partner is required to deduct estimated maintenance capital expenditures and turnaround reserves from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted,” our partnership agreement requires our general partner each quarter to deduct from operating surplus estimated maintenance capital expenditures and turnaround reserves, as opposed to actual maintenance capital expenditures, which could reduce the amount of available cash for distribution.

Each quarter we are required to deduct estimated maintenance capital expenditures and turnaround reserves from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

Our partnership agreement requires our general partner to deduct our estimated, rather than actual, maintenance capital expenditures from operating surplus each quarter in an effort to reduce fluctuations in operating surplus. The amount of estimated maintenance capital expenditures and turnaround reserves deducted from operating surplus is subject to review and change by the conflicts committee of our general partner at least once a year. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures or when the amount of lost revenue from a turnaround is greater than the estimated turnaround reserves, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If our general partner underestimates the appropriate level of estimated maintenance capital expenditures and turnaround reserves, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates.

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to you.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Any such reimbursement will be determined by our general partner. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interests and Fiduciary Duties—Conflicts of Interest.” The reimbursement of expenses and payment of fees, if any, to our general partner could adversely affect our ability to pay cash distributions to you.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80.0% of the issued and outstanding common units, our general partner will have the right, but not the obligation, which right it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units to our general partner, its affiliates or us at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. At the completion of this offering, our general partner and its owner will own 1,218,750 common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its owner will own 50.0% of the common units. For additional information about this right, please read “The Partnership Agreement—Limited Call Right.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general

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partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. 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 other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner 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 the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

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, which we call 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. Delaware law provides that for a period of three years from the date of the 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. Purchasers of units who become limited partners are liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of the units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to the offering, there has been no public market for the common units. After the offering, there will be only 8,125,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

• our quarterly distributions;

• our quarterly or annual earnings or those of other companies in our industry;

• loss of the refining agreement or a large customer;

• announcements by us or our competitors of significant contracts or acquisitions;

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• changes in accounting standards, policies, guidance, interpretations or principles;

• general economic conditions;

• the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

• future sales of our common units; and

• the other factors described in these “Risk Factors.”

We will incur increased costs as a result of being a public partnership.

We have no history operating as a public entity. As a public partnership, we will incur significant legal, accounting and other expenses that we did not incur as a private company. The Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the New York Stock Exchange, place certain requirements for corporate governance practices on public companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a public partnership, we will be required to have three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our public partnership reporting requirements. We also expect these rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our 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 affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum 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, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would

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result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law 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. For example, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, beginning in 2008, partnerships operating in Texas will be required to pay Texas franchise tax at a maximum effective rate of 0.7% of gross income of partnerships apportioned to Texas in the prior year. If we became subject to the Texas franchise tax or if any other state were to impose a tax on us, the cash available for distribution to you would be reduced.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Tax Consequences—Uniformity of Units.”

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

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

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conclusions of our counsel expressed in this prospectus 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.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no 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 tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person you should consult your tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual 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 and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election.”

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A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our tax counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

As a result of investing in our common units, you may be subject to foreign, state and local taxes and return filing requirements in jurisdictions were we operate or own or acquire property.

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes, that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay foreign, 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 will initially own assets and do business in Utah. Utah currently imposes a personal income tax as well as an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

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, which would result in us filing two tax returns (and our unitholders receiving two Schedule K-1s) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending January 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Please read “Material Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In

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that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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USE OF PROCEEDS

We intend to use the net proceeds of approximately $148.0 million from this offering, after deducting underwriting fees, discounts and commissions and after estimated offering expenses of approximately $3.1 million, to:

• purchase $130.0 million of certificates of deposit, which will be assigned as collateral to secure the senior secured term loan under our new credit facility; and

• make an $18.0 million cash distribution to Big West to reimburse it for certain capital expenditures.

We also anticipate that we will borrow approximately $130.0 million in secured term debt and $151.0 million in unsecured term debt under our new credit facility upon the closing of this offering, and we will distribute $280.0 million of the proceeds of such borrowings to Big West (which is net of $1.0 million in financing fees).

To the extent that the underwriters’ option to purchase additional common units is exercised, we will use the net proceeds to purchase an equivalent amount of certificates of deposit, which will be assigned as collateral to secure additional term loan borrowings and we will borrow under the term loan portion of our new credit facility. These additional borrowings will be equal to the net proceeds to be received from the exercise of the underwriters’ option. The proceeds of the additional term loan borrowings will be used to redeem from our general partner a number of common units equal to the number of common units issued upon exercise of the underwriters’ option to purchase additional common units.

A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per common unit would increase or decrease the amount of certificates of deposit we would purchase and the amount of borrowings we would make under our secured term loan by approximately $7.6 million.

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CAPITALIZATION

The following table shows:

• Big West Oil Predecessor’s historical cash and cash equivalents and capitalization as of July 31, 2007; and

• Big West Oil Partners, LP’s pro forma cash and cash equivalents and capitalization as of July 31, 2007 as adjusted to reflect (1) the offering of the common units, borrowings under our new credit facility and the application of the net proceeds therefrom described under “Use of Proceeds” and (2) the acquisition of a 35.0% interest in OPCO and the related formation and contribution transactions.

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	As of July 31, 2007
	Big West Oil Predecessor		Big West Oil Partners, LP Pro Forma
	(in thousands)
Cash and cash equivalents	$	57,606	$	—
Short term investments				130,000	(1)(2)
Long term debt, including current portion:
Term loans		180,000		281,000	(2)
Total debt		180,000		281,000
Equity:
Member’s equity		399,421		—
Partners’ equity:
Held by public:
Common units		—		148,000
Held by the general partner and its affiliates:
Common units		—		(40,710	)
Subordinated units		—		(230,689	)
General partner interest		—		(11,077	)
Total equity		399,421		(134,476	)(3)
Total capitalization	$	579,421	$	146,524

(1) Consists of $130.0 million of certificates of deposit assigned as collateral for the secured term loan portion of our new credit facility.

(2) A $1.00 increase or decrease in the assumed initial public offering price of $20.00 per common unit would increase or decrease the amount of certificates of deposit we would purchase and the amount of borrowings we would make under our secured term loan by approximately $7.6 million.

(3) The total net partnership deficit of $134.5 million consists of the net proceeds of approximately $148.0 million from this offering plus the $15.5 million capital contribution recorded on a historical basis less the distribution to Big West of $298.0 million ($280.0 million from borrowings under our new credit facility and $18.0 million from the net proceeds of the offering).

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of July 31, 2007, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value was $             million, or $             per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

Assumed initial public offering price per common unit		$	20.00
Pro forma net tangible book value per common unit before the offering(1)	$
Increase in net tangible book value per common unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per common unit after the offering(2)
Immediate dilution in tangible net book value per common unit to new investors		$

(1) Determined by dividing the number of units (1,218,750 common units, 6,906,250 subordinated units and the 2.0% general partner interest represented by 331,633 general partner units) to be issued to the general partner and its affiliates for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities.

(2) Determined by dividing the total number of units to be outstanding after the offering (9,343,750 common units, 6,906,250 subordinated units and the 2.0% general partner interest represented by 331,633 general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner, its affiliates and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

	Units Acquired		Total Consideration
	Number	Percent	Amount	Percent
General partner and affiliates(1)		%	$	%
New investors		%		%
Total			$

(1) The units acquired by our general partner and its affiliates consist of 6,906,250 subordinated units, 1,218,750 common units and the 2.0% general partner interest represented by 331,633 general partner units.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions upon which our cash distribution policy is based. Please read “—Assumptions and Considerations” below. For additional information regarding our historical and pro forma operating results, you should refer to our historical financial statements for the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2006 and 2007, and our unaudited pro forma condensed financial statements for the fiscal year ended January 31, 2007 and the six months ended July 31, 2007, included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash quarterly. Our available cash is our cash on hand at the end of a quarter after deducting expenses and estimated maintenance capital expenditures and turnarounds and other reserves. Because we believe we will generally finance any acquisitions or capital improvements from external financing sources as opposed to cash from operations, we believe that our investors are better served by our distributing our cash available from operations after expenses and reserves. Because we are not subject to a partnership-level federal income tax, we have more cash to distribute to you than would be the case were we subject to partnership level federal income tax. Our determination of available cash takes into account the need to maintain certain cash reserves to preserve our distribution levels across seasonal and cyclical fluctuations in our business. Please read “How We Make Cash Distributions.”

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:

• Our unitholders have no contractual or other legal right to receive distributions other than the obligation under our partnership agreement to distribute available cash on a quarterly basis, which is subject to our general partner’s broad discretion to establish reserves and other limitations.

• Our cash flow will depend completely on OPCO’s distributions to us as one of its partners. The amount of cash OPCO can distribute to its partners will principally depend upon the amount of cash it generates from operations less any reserves that may be appropriate for operating its business. Please read “Risk Factors” for a discussion of factors affecting OPCO’s distributions.

• We must (subject to the approval of the board of directors of our general partner) establish reserves for the prudent conduct of OPCO’s business (including reserves for working capital, estimated maintenance capital expenditures, turnarounds, environmental matters and legal proceedings). The establishment of these reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on the unitholders. Our partnership agreement provides that in order for a determination by our general partner to be made in good faith, it must believe that the determination is in our best interests.

• While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of non-affiliated common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units after the subordination period has ended. At the closing of this offering, our general partner and its affiliates will own 50% of our outstanding common units and subordinated units.

• Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

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• Under Section 17-607 of 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.

• We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including nonperformance by Big West of its obligations under the refining agreement or suspension of Big West’s obligations under the refining agreement, operational problems at the Salt Lake refining complex, increases in general and administrative expenses, principal and interest payments on outstanding debt, tax expenses, future working capital requirements, unanticipated cash needs and seasonality. Please read “Risk Factors” for a discussion of these factors.

• Our distribution policy will be affected by restrictions on distributions under our new credit facility, which contain material financial tests and covenants that must be satisfied. These financial tests and covenants are described in this prospectus in “Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity and Capital Resources—Covenants and Other Restrictions in Our Financing Agreements.” Should we be unable to satisfy these restrictions included in the credit agreements or if we are otherwise in default under the credit agreements, we would be prohibited from making cash distributions to you, notwithstanding our stated cash distribution policy.

Our ability to make distributions to our unitholders will initially depend on the performance of OPCO and its ability to distribute funds to us. Upon the closing of this offering, our interest in OPCO will be our only cash generating asset. The ability of our controlled affiliates, including OPCO, to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable partnership and limited liability company laws, fraudulent conveyance and other solvency laws and other laws and regulations. Please read “Risk Factors—Risks Related to Our Business—We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution on our common units and subordinated units.”

Dependence of Our Ability to Grow on Our and OPCO’s Ability to Access External Expansion Capital

Because we and OPCO distribute all of our and its available cash, growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. We expect that we and OPCO will rely upon external financing sources, including bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion and investment capital expenditures. As a result, to the extent OPCO or we are unable to finance growth externally, the cash distribution policy will significantly impair our or its ability to grow. To the extent we issue additional units in connection with any acquisitions or expansion or investment capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may affect the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior in right of distributions to the common units. The incurrence of additional borrowings or other debt by OPCO or us to finance our growth strategy would result in increased interest expense, which in turn may affect the available cash that OPCO has to distribute to us and that we have to distribute to our unitholders.

Our Initial Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare an initial quarterly distribution of $0.37500 per unit per complete quarter, or $1.50 per unit per year, to be paid no later than 45 days after the end of the fiscal quarter. This equates to an aggregate cash distribution of $6.2 million per quarter or $24.9 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. If the underwriter’s option to purchase additional common units is exercised, an equivalent number of common units will be redeemed from an affiliate of Big West. Accordingly, the exercise of the underwriters’ option will not affect the total amount of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Our ability to pay the minimum quarterly distribution will be subject to the factors described above under the caption “—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

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The table below sets forth the assumed number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the aggregate amounts needed to pay the minimum quarterly distribution for one quarter and for four quarters on such units following the closing of this offering at our initial distribution rate of $0.37500 per unit per quarter ($1.50 per unit on an annualized basis).

		Distributions
	Number of Units	One Quarter		Four Quarters
Publicly held common units	8,125,000	$	3,046,875	$	12,187,500
Common units held by our general partner	1,218,750		457,031		1,828,125
Subordinated units held by the owner of our general partner	6,906,250		2,589,844		10,359,375
General partner units held by our general partner	331,633		124,362		497,450
Total	16,581,633	$	6,218,112	$	24,872,450

As of the date of this offering, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. The general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

If distributions on our common units are not paid with respect to any fiscal quarter at the initial minimum quarterly distribution rate, our unitholders will not be entitled to receive such payments in the future; provided, however, the holders of common units will be entitled to a preference over holders of subordinated units with respect to cash distributions at our initial minimum quarterly distribution rate, which preference will allow holders of common units to receive deficiencies in payments of cash distributions at our initial minimum quarterly distribution rate in subsequent quarters to the extent we have available cash to pay these deficiencies related to prior quarters, before any cash distribution is made to holders of subordinated units. Please read “How We Make Cash Distributions—Subordination Period.”

We will pay our distributions on or about the 15th of each March, June, September and December to holders of record on or about the 1st of each of such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through April 30, 2008 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash from operating surplus to pay the minimum quarterly distribution on all of our outstanding common and subordinated units for each quarter through January 31, 2009. In those sections, we present two tables, consisting of:

• “Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of cash we would have had available for distribution for our fiscal year ended January 31, 2007 and the twelve months ended July 31, 2007, based on our pro forma financial statements.

• “Estimated Cash Available for Distribution,” in which we present how we calculate that we will have sufficient available cash to pay the full minimum quarterly distribution on all our units for the twelve months ending January 31, 2009. In “—Assumptions and Considerations” below, we also present our assumptions underlying this estimate.

Pro Forma Cash Available for Distribution for the Fiscal Year Ended January 31, 2007 and the Twelve Months Ended July 31, 2007

If we had completed the transactions contemplated in this prospectus on February 1, 2006, pro forma available cash generated during the fiscal year ended January 31, 2007 would have been approximately

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$25.6 million. This amount would have been sufficient to pay the full the minimum quarterly distribution on the common units and on the subordinated units for the fiscal year ended January 31, 2007. If we had completed the transactions contemplated in this prospectus on August 1, 2006, our pro forma available cash for the twelve months ended July 31, 2007 would have been approximately $26.1 million. This amount would have been sufficient to pay the full minimum quarterly distribution on the common units and on the subordinated units for the twelve-month period ended July 31, 2007.

Pro forma cash available for distribution includes cash payments to OPCO under the refining agreement that are treated for accounting purposes as deferred revenue due to the effect of straight-line rents. The refining agreement along with the master services agreement and the shared services agreement are collectively considered as one agreement for purposes of analysis under GAAP. In accordance with Emerging Issues Task Force Issue No. 01-08,Determining Whether an Arrangement Contains a Lease, this agreement is treated as a lease for accounting purposes. Under the refining agreement, OPCO receives minimum non-refundable cash payments throughout the 25-year life of the agreement. OPCO has determined that the minimum refining payments for the first 24 years qualify as fixed lease payments that are required under GAAP to be recorded on a straight-line basis over the 25-year life of the refining agreement. Minimum required payments under the refining agreement in excess of the recognized revenue will be recorded as deferred revenue. OPCO estimates that $106.7 million of deferred revenue, representing cash received in excess of revenue recognized over the life of the refining agreement, will be recognized as revenue at the end of the refining agreement. However, the distributable cash for each year of the refining agreement will include $4.3 million in deferred revenue, which is the difference between the minimum cash payments and the revenue recognized under GAAP each year. Distributable cash in year 25 of the agreement is expected to be consistent with the prior years of the refining agreement.

Pro forma cash available for distribution includes incremental general and administrative expenses we will incur as a result of being a publicly traded limited partnership, such as costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, director compensation and incremental insurance costs, including director and officer liability insurance. We expect these incremental general and administrative expenses initially to total approximately $1.5 million per year. For three years following this offering, pursuant to the omnibus agreement, Big West will agree to reimburse us to the extent these expenses exceed $1.5 million per year.

The pro forma financial statements, upon which pro forma cash available for distribution is based, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma cash available for distribution shown above in the manner described in the table below. As a result, the amount of pro forma cash available for distribution should only be viewed as a general indication of the amount of cash available for distribution that we might have generated had we been formed in earlier periods.

The following table illustrates, on a pro forma basis, for the fiscal year ended January 31, 2007 and for the twelve months ended July 31, 2007, the amount of available cash that would have been available for distributions to our unitholders, assuming in each case that the offering and related transactions had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

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Big West Oil Partners, LP

Unaudited Pro Forma Cash Available for Distribution

	Year Ended January 31, 2007			Twelve Months Ended July 31, 2007
	(in thousands)
OPCO
Gross sales(a)	$	115,701		$	118,321
Operating costs and expenses:
Cost of refining(b)		(8,312	)		(9,457	)
Selling, general and administrative(c)		(3,450	)		(3,450	)
Total operating costs and expenses		(11,762	)		(12,907	)
Deferred revenue(d)		4,269			4,269
Adjusted EBITDA	$	108,208		$	109,683
Less:
Estimated maintenance capital expenditures and turnaround reserve(e)		(1,500	)		(1,500	)
Cash available for distribution from OPCO	$	106,708		$	108,183
Big West Oil Partners, LP
Big West Oil Partners, LP’s share of OPCO’s available cash	$	37,348		$	37,864
Public partnership expenses(f)		(1,500	)		(1,500	)
Interest expense, excluding amortization(g)		(10,225	)		(10,225	)
Pro forma cash available for distribution	$	25,623		$	26,139
Surplus		751			1,267

(a) Reflects the terms of the refining agreement applied to historical throughput volumes for the MSCC unit of 10,113 bpd and 11,252 bpd for the fiscal year ended January 31, 2007 and the twelve months ended July 31, 2007, respectively, and historical alkylate unit offtake volumes of 2,040 bpd and 2,534 bpd for the fiscal year ended January 31, 2007 and the twelve months ended July 31, 2007, respectively.

(b) Cost of refining, a component of net sales, reflects the cost to refine historical throughput and offtake volumes for the MSCC and alkylation units pursuant to the shared services and master services agreements, including reimbursements paid to Big West for natural gas, utilities and shared site service expenses and payments for Big West employees.

(c) Reflects payment for administrative services under the services agreements and rental payments under the site lease.

(d) OPCO has determined that the minimum refining fees for the first 24 years under the refining agreement are fixed lease payments that are required under GAAP to be recorded on a straight-line basis over the 25-year life of the agreement. Minimum required payments under the refining agreement in excess of the recognized revenue will be recorded as deferred revenue which is expected to be recognized at the end of the refining agreement. However, the distributable cash for each year of the refining agreement will include the deferred revenue.

(e) Our partnership agreement requires that an estimate of the maintenance capital expenditures necessary to maintain our asset base and a turnaround reserve be subtracted from operating surplus each quarter, as opposed to amounts actually spent. Because our interest in OPCO will represent our only cash-generating asset upon the closing of this offering, an estimate of its maintenance capital expenditures is more meaningful. The board of directors of our general partner will approve the amount of OPCO’s reserves for estimated maintenance capital expenditures and turnaround reserves. Our initial estimated maintenance capital expenditures and turnaround reserves for OPCO are $1.5 million per year, which is based on the average annual anticipated direct turnaround costs for OPCO’s units as well as the loss of revenues related to such turnarounds. We have assumed a turnaround for OPCO’s units will take place every five years and last for approximately four weeks. The actual cost of maintenance capital expenditures, including turnarounds and other items, will depend on a number of factors and could differ from our estimates.

(f) Reflects an adjustment for estimated incremental general and administrative expenses we will incur as a result of being a publicly traded limited partnership, such as costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, director compensation and incremental insurance costs, including director and officer liability insurance. Pursuant to the omnibus agreement that we and OPCO will enter into with Big West, Flying J and certain of their affiliates, for three years following this offering, Big West will reimburse us for incremental

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general and administrative expenses in excess of $1.5 million per year that we will incur as a result of being a publicly traded partnership.

(g) Reflects the interest expense and fees related to our borrowings pursuant to our new credit facility that we expect to enter into in connection with the offering. We have assumed that the interest rate under our new secured term loan will be 5.15% and under our new unsecured term loan will be 6.64% and that we will incur approximately $1.0 million in commitment and other financing-related fees.

Estimated Cash Available for Distribution

As a result of the factors described in this “—Estimated Cash Available for Distribution” and “—Assumptions and Considerations” below, we believe we will be able to pay the minimum quarterly distribution on all our common units, subordinated units and general partner units for each quarter in the twelve months ending January 31, 2009.

We estimate OPCO will generate Adjusted EBITDA of approximately $110.2 million for the twelve months ending January 31, 2009. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or ability to service debt obligations. Please read “Summary Historical Financial and Operating Data and Pro Forma Financial Data—Non-GAAP Measure.” You should read “—Assumptions and Considerations” below for a discussion of the material assumptions underlying this belief, which reflect our judgment of conditions we expect to exist and the course of action we expect to take. If our estimate is not achieved, we may not be able to pay the minimum quarterly distribution on all our units. We can give you no assurance that our assumptions will be realized or that OPCO will generate approximately $110.2 million in Adjusted EBITDA. There will likely be differences between our estimates and the actual results OPCO will achieve and those differences could be material. If OPCO does not generate at least $106.1 million of Adjusted EBITDA or if maintenance and environmental capital expenditures, interest expense or income tax expense are higher than estimated or we encounter unanticipated cash needs, we may not be able to pay the minimum quarterly distribution on all units.

When considering OPCO’s ability to generate estimated Adjusted EBITDA of approximately $110.2 million, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our results of operations and cash available for distribution to our unitholders to vary significantly from those set forth below.

We do not, as a matter of course, make public projections as to future sales, earnings or other results. However, we have prepared the cash available for distribution and the assumptions set forth below to substantiate our belief that we will have sufficient cash available to make the minimum quarterly distribution on all units for the for the four quarters ending January 31, 2009. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we will have sufficient cash available for distribution on the all units at the minimum quarterly distribution rate. However, this information is not factual and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent registered public accounting firm nor any other independent registered public accounting firm has examined, compiled or otherwise applied procedures to the prospective financial information presented herein, and, accordingly, they do not express an opinion or any other form of assurance on such information or its achievability. Accordingly, they assume no responsibility for the prospective financial information.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date in this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

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The following table shows how we calculate the estimated cash available for distribution through January 31, 2009.

Big West Oil Partners, LP

Estimated Cash Available for Distribution

	Twelve Months Ending January 31, 2009
	(in thousands)
OPCO
Gross Sales	$	118,927
Operating costs and expenses:
Cost of refining		(9,570	)
Selling, general and administrative		(3,450	)
Total operating costs and expenses		(13,020	)
Deferred revenue		4,269
Adjusted EBITDA	$	110,176
Less:
Estimated maintenance capital expenditures and turnaround reserve		(1,500	)
Cash available for distribution from OPCO	$	108,676
Big West Oil Partners, LP
Big West Oil Partners, LP’s share of OPCO’s available cash	$	38,036
Public partnership expenses		(1,500	)
Interest expense, excluding amortization		(10,225	)
Estimated cash available for distribution	$	26,311
Per unit minimum annual distribution	$	1.50
Distributions to(1):
Publicly held common units	$	12,188
Common units held by our general partner		1,828
Subordinated units held by the owner of our general partner		10,359
General partner interests held by our general partner		497
Total minimum annual cash distribution	$	24,872
Excess of cash available for distribution over total minimum annual cash distribution by Big West Oil Partners, LP	$	1,439

(1) Forecasted payments of distributions on common units, subordinated units and general partner units as set forth in the table above assume payment of a full four quarters worth of the minimum quarterly distribution. Pursuant to the partnership agreement, we will adjust the minimum quarterly distribution for the first quarter from the closing of the offering through April 30, 2008.

Assumptions and Considerations

Based on a number of specific assumptions, we believe that, following completion of this offering, we will have sufficient cash available for distribution to allow us to make the full minimum quarterly distribution on all the outstanding units for each quarter through January 31, 2009. These assumptions include that:

• The refining agreement, the services agreements, the omnibus agreement and the site lease agreement each will remain in full force and effect, with no dispute, default, termination, or invocation of force majeure by either party thereunder.

• OPCO will receive $123.2 million in aggregate gross sales and deferred revenue related to services provided under its refining agreement with Big West. We base this assumption on the further assumptions that OPCO processes volumes in excess of its minimum commitment under the refining agreement: (1) 10,000 bpd of gas oil at a price of $29.00 per barrel of gas oil processed and 1,300 bpd of gas oil at a price of $5.00 per barrel of gas oil processed and (2) 2,000 bpd of alkylation product at a price of $19.00 per barrel of alkylation

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product processed and 700 bpd of alkylation product at a price of $3.00 per barrel of alkylate product processed. These volumetric assumptions are based on the average daily processing volume levels for the MSCC unit and the alkylation unit for the six months ended July 31, 2007. These price assumptions are based on the applicable fees provided for in the refining agreement. See “Business—Big West Facility Units” and “Business—Historical Throughput and Production” for data relating to the historical throughput and production of our process units. If Big West were to satisfy only the minimum MSCC Commitment of 10,000 bpd of gas oil and the minimum Required Offtake Commitment of 2,000 bpd of alkylate under the refining agreement, aggregate gross sales and deferred revenue would be reduced by $3.1 million to $120.0 million and cost of refining would be reduced by $1.4 million to $8.2 million. As a result, cash available for distribution would decline to $25.7 million, which would be sufficient to pay the minimum quarterly distribution on all of the common units, subordinated units and general partner units.

• OPCO will not receive any revenues from third parties.

• OPCO’s cost of refining, a component of net sales, for the twelve months ended January 31, 2009 will be $9.6 million. We base this assumption on the payment under OPCO’s agreements with Big West for natural gas, electricity, water and other shared site service expenses and payments for Big West employees.

• OPCO’s selling, general and administrative expenses, a component of net sales, for the twelve months ending January 31, 2009 will be approximately $3.5 million. We base this assumption on the payment for administrative services under OPCO’s shared services agreement and the rental payments to Big West under the site lease. Pro forma selling, general and administrative expenses for the twelve months ended January 31, 2007 were $3.5 million.

• Our public partnership expense for the twelve months ending January 31, 2009, will be approximately $1.5 million as a result of incremental expenses associated with our operation as a publicly traded partnership. Pro forma public partnership expense for the twelve month periods ended January 31, 2007 and July 31, 2007 was $1.5 million. For three years following this offering, pursuant to the omnibus agreement, Big West will agree to reimburse us to the extent these expenses exceed $1.5 million per year.

• Our interest expense (including commitment, letter of credit and other fees) for the twelve months ending January 31, 2009 will be approximately $10.5 million. Interest expense includes non-cash loan amortization of $250,000. Pro forma interest expense for the twelve months ended January 31, 2007 was $10.5 million. We have assumed that the interest rate under our new secured term loan will be 5.15% and under our new unsecured term loan will be 6.64% and that we will incur approximately $1.0 million in commitment and other financing-related fees.

• We have assumed our estimated maintenance capital expenditures and turnaround reserve will be approximately $1.5 million, which includes the direct cost of turnarounds for OPCO’s units as well as the loss of revenues related to such turnarounds. We have assumed OPCO’s process units will require a turnaround every five years and that each such turnaround will result in four weeks of lost revenue.

• No material accidents, force majeure events, releases or other unanticipated material events will occur.

• Market, regulatory and overall economic conditions will not change substantially.

While we believe that these assumptions are reasonable in light of management’s current beliefs concerning future events, the assumptions are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual cash available for distribution that we could generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all units, in which event the market price of the common units may decline materially. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors.” We do not undertake any obligation to release publicly the results of any future revisions we may make to the foregoing or to update the foregoing to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

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HOW WE MAKE CASH DISTRIBUTIONS

Distributions of Available Cash

General

Within 45 days after the end of each quarter, beginning with the fiscal quarter ending April 30, 2008, we will distribute our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through April 30, 2008 based on the actual length of the period.

Available Cash

Available cash generally means, for any quarter, all cash on hand at the end of the quarter (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own, including OPCO):

• less the amount of cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own) established by our general partner to:

• provide for the proper conduct of our business;

• comply with applicable law, any of our debt instruments or other agreements; or

• provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

• plus all cash on hand (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own) on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that are made under a credit agreement and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months from sources other than additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.37500 per unit, or $1.50 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Because our 35.0% interest in OPCO will be our only cash generating asset upon the closing of this offering, the amount of our distributions to unitholders initially will depend completely upon distributions by OPCO to us. OPCO will be prohibited from making any distributions to us if it would cause an event of default, or an event of default is existing, under its credit agreements. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a discussion of the restrictions to be included in the credit agreements that may restrict OPCO’s ability to make distributions.

General Partner Interest and Incentive Distribution Rights

As of the date of this offering, our general partner will be entitled to 2.0% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest will be represented by 331,633 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our general

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partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.43125 per unit. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest, and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on units that it owns. Please read “—General Partner Interest and Incentive Distribution Rights” below for additional information.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus

Operating surplus generally consists of:

• $15.0 million (as described below); plus

• all of our cash receipts (including our proportionate share of cash receipts for certain subsidiaries we do not wholly own, including OPCO) after the closing of this offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities, (3) sales or other dispositions of assets outside the ordinary course of business, (4) termination of interest rate swap agreements or commodity hedge contracts prior to the termination date specified therein, (5) capital contributions or (6) corporate reorganizations or restructurings; plus

• working capital borrowings (including our proportionate share of working capital borrowings for certain subsidiaries we do not wholly own) made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

• all of our operating expenditures (including our proportionate share of operating expenditures by certain subsidiaries we do not wholly own) after the closing of this offering and the repayment of working capital borrowings, but not (1) the repayment of other borrowings, (2) actual maintenance capital expenditures, expansion capital expenditures or investment capital expenditures, (3) transaction expenses (including taxes) related to interim capital transactions or (4) distributions; less

• estimated capital expenditures and turnaround reserves and the amount of cash reserves (including our proportionate share of cash reserves for certain subsidiaries we do not wholly own) established by our general partner for future operating expenditures; less

• all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

As described above, operating surplus includes a provision that will enable us, if we choose, to distribute as operating surplus up to $15.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowing, that would otherwise be distributed as capital surplus.

We define operating expenditures in our partnership agreement, and it generally means all of our expenditures, including, but not limited to, operating expenses, estimated maintenance capital expenditures and turnaround reserves, taxes, reimbursement of expenses incurred by our general partner on our behalf, non-pro rata purchases of units (other than those made with the proceeds of an interim capital transaction (as defined below)),

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repayment of working capital borrowings, interest payments and payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts, provided that operating expenditures will not include:

• repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus above when such repayment actually occurs;

• payments of principal of and premium on indebtedness other than working capital borrowings;

• actual maintenance capital expenditures;

• expansion or investment capital expenditures;

• payment of transaction expenses (including taxes) related to interim capital transactions;

• distributions to our partners; and

• non-pro rata purchases of units of any class made with the proceeds of an interim capital transaction.

Capital Expenditures

For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain over the long term the operating capacity of or the revenue generated by our capital assets, and expansion capital expenditures are those capital expenditures that increase the operating capacity of or the revenue generated by capital assets. To the extent, however, that capital expenditures increase the revenues or the operating capacity of capital assets, those capital expenditures would be classified as expansion capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes.

Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Examples of maintenance capital expenditures include capital expenditures associated with turnarounds to the extent such expenditures are incurred to maintain the operating capacity of or the revenue generated by OPCO’s units.

Expansion capital expenditures represent capital expenditures made to expand the existing operating capacity of assets or to expand the operating capacity or revenues of existing or new assets, whether through construction or acquisition. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as operations and maintenance expenses as we incur them.

Because we expect that maintenance capital expenditures will vary significantly in timing, the amount of actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus, and available cash for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus each quarter. Accordingly, to eliminate the effect on operating surplus of these fluctuations, our partnership agreement will require that an amount equal to an estimate of the average quarterly maintenance capital expenditures necessary to maintain the operating capacity of or the revenue generated by our capital assets over the long term as well as a turnaround reserve be subtracted from operating surplus each quarter, as opposed to the actual amounts spent.

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The amount of estimated maintenance capital expenditures and turnaround reserves deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change must be approved by the board’s conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will affect our assets. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures and turnaround reserves, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Our use of estimated maintenance capital expenditures and turnaround reserves in calculating operating surplus will have the following effects:

• it will reduce the risk that actual maintenance capital expenditures or loss of revenues from a turnaround in any one quarter will be large enough to make operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter and subsequent quarters;

• it will reduce the need for us to borrow to pay distributions;

• it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to our general partner; and

• it will reduce the likelihood that a large maintenance capital expenditure or loss of revenue from a turnaround in a period will prevent our general partner’s owner from being able to convert some or all of its subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, mitigating the effect of the actual payment of the expenditure on any single period.

Capital Surplus

Capital surplus consists of:

• borrowings other than working capital borrowings;

• sales of our equity and debt securities;

• sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets;

• the termination of interest rate hedge contracts or commodity hedge contracts prior to the termination date specified therein;

• capital contributions received; and

• corporate reorganizations or restructurings.

Characterization of Cash Distributions

We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes $15.0 million. This amount does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

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Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below and in Appendix B), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.37500 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period

The subordination period will extend until the first day of any quarter beginning after January 31, 2013 that each of the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

• there are no arrearages in payment of minimum quarterly distributions on the common units.

Expiration of the Subordination Period

When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:

• the subordination period will end and each subordinated unit will immediately convert into one common unit;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• the general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units

Before the end of the subordination period, up to 50.0% of the subordinated units, or up to 3,453,125 subordinated units, may convert into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after:

• January 31, 2011 with respect to 25.0% of the subordinated units; and

• January 31, 2012 with respect to an additional 25.0% of the subordinated units.

The early conversions will occur if at the end of the applicable quarter each of the following has occurred:

• distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the sum of the minimum quarterly

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distributions, in each case on all such units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions, in each case on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

• there are no arrearages in payment of the minimum quarterly distribution on the common units.

However, the second early conversion of the subordinated units may not occur until at least one year following the first early conversion of the subordinated units.

In addition to the early conversion of subordinated units described above, all of the subordinated units will convert into an equal number of common units on the first day of any quarter beginning after January 31, 2011 that each of the following tests are met:

• distributions of available cash from operating surplus on each outstanding common unit, subordinated unit and the 2% general partner interest equaled or exceeded $1.8750 per unit (125% of the annualized minimum quarterly distribution) for each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date;

• the adjusted operating surplus generated during each of the two consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of a distribution of $1.8750 per unit (125% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis; and

• there are no arrearages in payment of the minimum quarterly distribution on the common units.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the $15.0 million operating surplus “basket,” net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:

• operating surplus generated with respect to that period; less

• any net increase in working capital borrowings (including our proportionate share of any changes in working capital borrowings of certain subsidiaries we do not wholly own, including OPCO) with respect to that period; less

• any net decrease in cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own) for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

• any net decrease in working capital borrowings (including our proportionate share of any changes in working capital borrowings of certain subsidiaries we do not wholly own) with respect to that period; plus

• any net increase in cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own) for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

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Distributions of Available Cash from Operating Surplus During the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

• first, 98.0% to the common unitholders, pro rata, and 2.0% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

• second, 98.0% to the common unitholders, pro rata, and 2.0% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

• third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus After the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

• first, 98.0% to all unitholders, pro rata, and 2.0% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

• thereafter, in the manner described in “—Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our general partner’s capital contribution in order to maintain its 2.0% general partner interest may be in the form of a contribution of common units based on the current market value of the contributed common units.

Incentive distribution rights are a non-voting limited partner interest that represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

If for any quarter:

• we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

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• we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

• first, 98.0% to all unitholders, pro rata, and 2.0% to the general partner, until each unitholder receives a total of $0.43125 per unit for that quarter (the “first target distribution”);

• second, 85.0% to all unitholders, pro rata, and 15.0% to the general partner, until each unitholder receives a total of $0.46875 per unit for that quarter (the “second target distribution”);

• third, 75.0% to all unitholders, pro rata, and 25.0% to the general partner, until each unitholder receives a total of $0.56250 per unit for that quarter (the “third target distribution”); and

• thereafter, 50.0% to all unitholders, pro rata, and 50.0% to the general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus between the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest and assume our general partner has contributed any additional capital to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights.

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Amount	Unitholders		General Partner
Minimum Quarterly Distribution	$0.37500	98.0	%	2.0	%
First Target Distribution	up to $0.43125	98.0	%	2.0	%
Second Target Distribution	above $0.43125 up to $0.46875	85.0	%	15.0	%
Third Target Distribution	above $0.46875 up to $0.56250	75.0	%	25.0	%
Thereafter	above $0.56250	50.0	%	50.0	%

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Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

• first, 98.0% to all unitholders, pro rata, and 2.0% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

• second, 98.0% to the common unitholders, pro rata, and 2.0% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

• thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50.0% being paid to the holders of units and 50.0% to the general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume the general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

• the minimum quarterly distribution;

• target distribution levels;

• the unrecovered initial unit price; and

• the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we or OPCO become taxable as a corporation or otherwise subject to taxation as an entity for

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federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter will be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

• first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

• second, 98.0% to the common unitholders, pro rata, and 2.0% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

• third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

• fourth, 98.0% to all unitholders, pro rata, and 2.0% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to the general partner, for each quarter of our existence;

• fifth, 85.0% to all unitholders, pro rata, and 15.0% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per

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unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to the general partner for each quarter of our existence;

• sixth, 75.0% to all unitholders, pro rata, and 25.0% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to the general partner for each quarter of our existence; and

• thereafter, 50.0% to all unitholders, pro rata, and 50.0% to the general partner.

The percentage interests set forth above for our general partner include its 2.0% general partner interest and assume the general partner has not transferred the incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner:

• first, 98.0% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

• second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

• thereafter, 100.0% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

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BIG WEST OIL PARTNERS, LP

UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Introduction

The unaudited pro forma financial statements of Big West Oil Partners, LP (“Partnership”) as of July 31, 2007, for the fiscal year ended January 31, 2007 and for the six months ended July 31, 2007 are based on the unaudited pro forma balance sheet and statement of operations of Big West Oil Operating, LP (“OPCO”). OPCO’s unaudited pro forma financial statements are based on the historical balance sheet and statement of operations of Big West Oil Predecessor. A 35.0% interest in OPCO will be contributed to the Partnership at or prior to the closing of the initial public offering of the Partnership (the “Offering”), which will consist of a 34.999% limited partner interest in OPCO and a 0.001% general partner interest in OPCO held through a wholly-owned subsidiary of the Partnership.

The unaudited pro forma balance sheet and statement of operations were derived by adjusting the historical financial statements of Big West Oil Predecessor. The adjustments are based on currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transaction as contemplated and the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma financial information. The pro forma financial statements have been prepared on the basis that the Partnership will be treated as a partnership for federal and state income tax purposes but may be subject to applicable local and state taxes. The unaudited pro forma financial statements should be read in conjunction with the accompanying notes and with the historical financial statements and related notes of Big West Oil Predecessor.

The Partnership will own and control the general partner of OPCO and own a 35.0% aggregate interest in OPCO. However, OPCO is a variable interest entity as defined by FASB Interpretation No. 46R,Consolidation of Variable Interest Entities an interpretation of ARB No. 51. Big West is the primary beneficiary of OPCO based on the nature of the refining and services agreements and consolidates the operations of OPCO. Therefore, the Partnership reflects its ownership interest in OPCO on an equity basis, which means that OPCO’s financial results will be recognized as income from its equity method investment in OPCO on the Partnership’s statement of operations. In addition to the income from its equity method investment in OPCO, the Partnership has general and administrative expenses from operating as a public entity, interest expense on notes, and interest income on investments. The Partnership’s cash flow consists of cash distributions from OPCO based on the Partnership’s ownership interest in OPCO.

The pro forma adjustments have been prepared as if the transactions to be effected at the closing of the Offering had taken place on July 31, 2007, in the case of the pro forma balance sheet, or as of February 1, 2006, in the case of the pro forma statements of operations for the fiscal year ended January 31, 2007 and six months ended July 31, 2007.

The pro forma financial statements reflect the following transactions:

• the contribution to OPCO of the Salt Lake refining complex’s MSCC unit and alkylation unit;

• the transfer by Big West Oil, LLC (“Big West”) to the Partnership of a 34.999% limited partner interest in OPCO and a 100% interest in Big West Operating GP, LLC, which holds a 0.001% general partner interest in OPCO;

• the issuance by the Partnership to a subsidiary of Big West of 6,906,250 subordinated units;

• the issuance by the Partnership to Big West GP, LLC, the Partnership’s general partner, of 1,218,750 common units, a 2.0% general partner interest represented by 331,633 general partner units, and all of its incentive distribution rights;

69

• the sale by the Partnership of 8,125,000 common units to the public at an assumed initial public offering price of $20.00 per common unit;

• the payment of estimated underwriting commissions and other offering and transaction expenses;

• the application of the net proceeds of the Offering: (1) to purchase approximately $130.0 million of certificates of deposit, which will be assigned as collateral for the secured term loan portion of the Partnership’s new credit facility; and (2) to make a $18.0 million distribution to Big West;

• the borrowing of approximately $130.0 million in secured term debt and $151.0 million in unsecured term debt under the Partnership’s new credit facility;

• the distribution of $280.0 million to Big West from borrowings under the Partnership’s new credit facility; and

• the entry by OPCO into a refining agreement, shared services agreement, master services agreement and site lease with Big West and its affiliates and the entry by OPCO and the Partnership into the omnibus agreement with Flying J, Big West and their affiliates.

The unaudited pro forma financial statements and accompanying notes have been prepared in conformity with U.S. generally accepted accounting principles (or “GAAP”) consistent with those used in, and should be read together with, Big West Oil Predecessor’s historical financial statements and related notes, which are included elsewhere in this prospectus.

The unaudited pro forma financial statements do not purport to present the Partnership’s results of operations had the Offering and related transactions to be effected in connection with the Offering actually been completed at the dates indicated. In addition, they do not project the Partnership’s results of operations for any future period.

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BIG WEST OIL PARTNERS, LP

Unaudited Pro Forma Balance Sheet

as of July 31, 2007

(Dollars in thousands)

	Big West Oil Predecessor			Excluded Assets Adjustments			Big West Oil Operating, LP (“OPCO”)		Offering and Related Financing Transactions			Pro Forma Big West Oil Partners, LP
Current assets:
Cash	$	57,606		$	(57,606	)(a)	$	—	$	162,500	(c)
										(14,500	)(d)
										281,000	(e)
										(298,000	)(g)
										(130,000	)(h)
										(1,000	)(f)
Short term investments		—			—			—		130,000	(h)	$	130,000
		79,174			(79,174	)(a)		—		—			—
Trade receivables from affiliated companies		17,999			(17,999	)(a)		—		—			—
Receivable from affiliated companies		5,796			(5,796	)(a)		—		—			—
Inventories		161,306			(161,306	)(a)		—		—			—
Prepaid expenses		5,380			(5,380	)(a)		—		—			—
Total current assets		327,261			(327,261	)		—		130,000			130,000
Land, buildings, and equipment:
Land and improvements		7,280			(7,280	)(a)		—		—			—
Buildings		3,988			(3,988	)(a)		—		—			—
Equipment		303,282			(303,282	)(a)		56,704		(56,704	)(i)		—
					56,704	(b)							—
Construction in progress		243,758			(243,758	)(a)		—		—			—
		558,308			(501,604	)		56,704		(56,704	)		—
Less accumulated depreciation and amortization		79,343			(79,343	)(a)		12,350		(12,350	)(i)		—
					12,350	(b)
Net land, buildings, and equipment		478,965			(434,611	)		44,354		(44,354	)		—
Investment in Subsidiary		—			—			—		15,524	(k)		15,524
Other assets		45,710			(45,710	)(a)		—		1,000	(f)		1,000
Total assets	$	851,936		$	(807,582	)	$	44,354	$	102,170		$	146,524
Liabilities and Member’s/Partners’ Equity
Current liabilities:
Current installments of long-term debt	$	4,000		$	(4,000	)(a)	$	—	$	—		$	—
Accounts payable		225,303			(225,303	)(a)		—		—			—
Accounts payable to affiliated companies		4,979			(4,979	)(a)		—		—			—
Accrued fuel, property, and state taxes		25,767			(25,767	)(a)		—		—			—
Other accrued liabilities		12,758			(12,758	)(a)		—		—			—
Total current liabilities		272,807			(272,807	)		—		—			—
Long-term debt, excluding current installments		176,000			(176,000	)(a)		—		281,000	(e)		281,000
Other liabilities		3,708			(3,708	)(a)		—		—			—
Total liabilities		452,515			(452,515	)		—		281,000			281,000
Member’s equity:
Member’s equity		401,668			(401,668	)(a)		44,354		15,524	(k)		—
					44,354	(b)				(298,000	)(g)
										(44,354	)(i)
										282,476	(j)
Accumulated other comprehensive loss		(2,247	)		2,247	(a)		—		—			—
Total member’s equity		399,421			(355,067	)		44,354		(44,354	)		—
Partners’ equity:
Limited partner interests
Common units:
Public unitholders										162,500	(c)		148,000
										(14,500	)(d)
Big West										(40,710	)(j)		(40,710	)
Subordinated units										(230,689	)(j)		(230,689	)
General partner interest										(11,077	)(j)		(11,077	)
Total partners’ equity		—			—			—		(134,476	)		(134,476	)
Total liabilities and member’s/partners’ equity	$	851,936		$	(807,582	)	$	44,354	$	102,170		$	146,524

The accompanying notes are an integral part of the unaudited pro forma financial statements.

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BIG WEST OIL PARTNERS, LP

Unaudited Pro Forma Statement of Income

For the Year Ended January 31, 2007

(Dollars in thousands, except per unit amounts)

	Big West Oil Predecessor			Excluded Operating Results			Big West Oil Operating, LP (“OPCO”)			Offering and Related Financing Transactions			ProForma Big West Oil Partners, LP
Sales	$	2,410,078		$	(2,410,078	)(l)	$	103,989		$	(103,989	)(p)	$	—
					103,989	(m)
Operating costs and expenses:
Cost of products		2,149,090			(2,149,090	)(l)		—						—
Cost of refining		140,257			(140,257	)(l)		—						—
Selling, general, and administrative		12,208			(12,208	)(l)		—			1,500	(q)		1,500
					50	(n)		50			(50	)(n)
Depreciation and amortization		18,748			(18,748	)(l)		3,557			(3,557	)(p)		—
					3,557	(o)
Gain on sale of other assets		(838	)		838	(l)		—						—
		2,319,465			(2,315,958	)		3,557			(2,107	)		1,500
Income from operations		90,613			9,769			100,382			(101,882	)		(1,500	)
Other income (expenses):
Interest expense		(115	)		115	(l)		—	��		(16,725	)(r)		(16,975	)
											(250	)(s)
Interest income		334			(334	)(l)		—			6,500	(t)		6,500
Income from investments in affiliated companies		—			—			—			35,134	(u)		35,134
Losses on derivative activities		(2,528	)		2,528	(l)		—			—			—
		(2,309	)		2,309			—			24,659			24,659
Net income	$	88,304		$	12,078		$	100,382		$	(77,223	)	$	23,159
General partner interest in net income													$	463
Limited partner interest in net income attributable to common units														14,016
Limited partner interest in net income attributable to subordinated units														8,680
Net income per(v):
Common unit (basic and diluted)													$	1.50
Subordinated (basic and diluted)														1.26
Weighted average number of units outstanding:
Common unit (basic and diluted)														9,343,750
Subordinated (basic and diluted)														6,906,250

The accompanying notes are an integral part of the unaudited pro forma financial statements.

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BIG WEST OIL PARTNERS, LP

Unaudited Pro Forma Statement of Income

For the Six Months Ended July 31, 2007

(Dollars in thousands, except per unit amounts)

	Big West Oil Predecessor			Excluded Operating Results			Big West Oil Operating, LP (“OPCO”)		Offering and Related Financing Transactions			ProForma Big West Oil Partners, LP
Sales	$	1,412,664		$	(1,412,664	)(l)	$	52,750	$	(52,750	)(p)	$	—
					52,750	(m)
Operating costs and expenses:
Cost of products		1,143,500			(1,143,500	)(l)		—					—
Cost of refining		84,578			(84,578	)(l)		—					—
Selling, general, and administrative		11,738			(11,738	)(l)		—		750	(q)		750
					25	(n)		25		(25	)(n)
Depreciation and amortization		13,612			(13,612	)(l)		1,778		(1,778	)(p)		—
					1,778	(o)
Gain on sale of other assets		(2,208	)		2,208	(l)		—					—
		1,251,220			(1,249,417	)		1,803		(1,053	)		750
Income from operations		161,444			(110,498	)		50,947		(51,697	)		(750	)
Other income (expenses):
Interest expense		—			—			—		(8,363	)(r)		(8,488	)
										(125	)(s)
Interest income		451			(451	)(l)				3,250	(t)		3,250
Income from investments in affiliated companies		—						—		17,831	(u)		17,831
Losses on derivative activities		(4,003	)		4,003	(l)		—					—
Total other income (expense)		(3,552	)		3,552			—		12,594			12,594
Net income	$	157,892		$	(106,946	)	$	50,947	$	(39,103	)	$	11,844
General partner interest in net income												$	237
Limited partner interest in net income attributable to common units													7,008
Limited partner interest in net income attributable to subordinated units													4,599
Net income per(v):
Common unit (basic and diluted)												$	.75
Subordinated (basic and diluted)													.67
Weighted average number of units outstanding:
Common unit (basic and diluted)													9,343,750
Subordinated (basic and diluted)													6,906,250

The accompanying notes are an integral part of the unaudited pro forma financial statements.

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BIG WEST OIL PARTNERS, LP

Notes to Unaudited Pro Forma Financial Statements

Pro Forma Adjustments and Assumptions

(a) Reflects the elimination of assets, liabilities and member’s equity and expenses not contributed to OPCO but included in the historical combined financial statements of Big West Oil Predecessor. The Bakersfield refining complex and all process units in the Salt Lake refining complex other than OPCO’s units have been retained by Big West.

(b) Reflects the contribution of the milli-second catalytic cracking unit and alkylation unit at the Salt Lake refining complex (“OPCO’s units”) to OPCO. The OPCO units are recorded at their historical cost with their historical accumulated depreciation.

(c) Reflects the gross proceeds to the Partnership of $162.5 million from the issuance and sale of 8,125,000 common units at an assumed initial public offering price of $20.00 per unit.

(d) Reflects the payment of the estimated underwriting discount, structuring fee and other expenses of the Offering of $14.5 million.

(e) Reflects the proceeds from the borrowing of $130.0 million in secured term debt collateralized by $130.0 million in certificates of deposit; and proceeds from the borrowing of $151.0 million in unsecured term debt under the Partnership’s new credit facility.

(f) Reflects the payment of financing and commitment fees associated with the Partnership’s new credit facility.

(g) Reflects the $280.0 million distribution to Big West from the net proceeds of the Partnership’s borrowings and the $18.0 million distribution to Big West from the net proceeds of the Offering.

(h) Reflects the purchase of certificates of deposit pledged as collateral on the $130.0 million in secured term debt.

(i) As a result of the Partnership accounting for its ownership interest in OPCO on an equity basis, this entry reflects the elimination of OPCO’s account balances.

(j) Partnership deficit consists of $15.5 million of capital contribution recorded on a historical basis less the distribution of $298.0 million (see note (g)). Reflects the allocation of $282.5 million of net partnership deficit, of which $40.7 million is allocated to the 1,218,750 common units, $230.7 million is allocated to the 6,906,250 subordinated units and $11.1 million is allocated to the general partner interest, all of which are held by affiliates of Big West.

(k) Reflects the Partnership’s 35.0% investment in OPCO, which is accounted for according to the equity method.

(l) Reflects the elimination of the operating results that are not continuing in OPCO.

(m) Reflects the estimated net sales of OPCO based on its refining agreement and services agreements with Big West. Net sales consist of refining revenue recognized by OPCO under the refining agreement less the payment by OPCO of fees under the shared services agreement and the master services agreement. The refining agreement along with the master services agreement and the shared services agreement are collectively considered as one agreement for purposes of analysis under GAAP, which is treated as a lease for accounting purposes. OPCO has determined that the minimum refining fees for the first 24 years are fixed lease payments that are required to be recorded on a straight-line basis over the 25-year life of the agreement. Minimum required payments under the refining agreement in excess of the recognized revenue will be recorded as deferred revenue which is expected to be recognized at the end of the refining agreement.

(n) Reflects the site lease payment from OPCO to Big West.

(o) Reflects the depreciation on OPCO’s units. Depreciation is calculated on a straight-line basis over their estimated useful lives of 5 to 30 years.

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(p) As a result of the Partnership accounting for its ownership interest in OPCO on an equity basis, this entry reflects the elimination of OPCO’s operating results.

(q) Reflects the general and administrative expenses from operating as a public partnership. Upon completion of this offering, the Partnership anticipates incurring incremental general and administrative expenses of approximately $1.5 million per year, as a result of being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unit holders, financial statement audit, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. Pursuant to the omnibus agreement the Partnership will enter into with Big West and other parties, Big West will agree to reimburse the Partnership for general and administrative expenses it will incur as a public partnership in excess of $1.5 million per year for a period of three years after the Offering.

(r) Reflects the estimated interest expense on the $130.0 million secured term loan at 5.15% and the $151.0 million unsecured term loan at 6.64%.

(s) Reflects the loan cost amortization related to the Partnership’s term debt.

(t) Reflects the estimated interest income on $130.0 million of certificates of deposit at 5.00%.

(u) Reflects the 35.0% share of estimated earnings of OPCO.

(v) Pro forma net income per unit is determined, in accordance with Emerging Issues Task Force Issue No. 03-6,Participating Securities and the Two-Class Method under FASB Statement No. 128, by dividing the pro forma net income available to the common and subordinated unitholders, after deducting the general partner’s interest in the pro forma net income, by the weighted average number of common and subordinated units expected to be outstanding at the closing of the offering. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.37500 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. For purposes of the calculation of pro forma net income per unit, we assumed that the minimum quarterly distribution was made to all unitholders for each quarter during the periods presented and that the number of units outstanding were 9,343,750 common and 6,906,250 subordinated. All units were assumed to have been outstanding since February 1, 2006. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The following table shows selected historical financial and operating data of Big West Oil Predecessor, the predecessor to Big West Oil Partners, LP, for the periods and as of the dates indicated. The selected historical financial data as of January 31, 2003, 2004, 2005, 2006 and 2007 and July 31, 2006 and 2007 and for the fiscal years ended January 31, 2003, 2004, 2005, 2006 and 2007 and the six months ended July 31, 2006 and 2007 are derived from the financial statements of Big West Oil Predecessor. The historical financial statements of Big West Oil Predecessor reflect all of the assets located in the Salt Lake refining complex, as well as, for periods on and after March 15, 2005, the refining complex in Bakersfield, California that Big West of California, LLC, a wholly owned subsidiary of Big West acquired from Shell Oil Products U.S. The assets of our partnership on the closing date of the offering will consist only of our interests in OPCO. OPCO’s assets will consist only of the MSCC unit and the alkylation unit located at the Salt Lake refining complex. Accordingly, the historical financial statements will reflect significantly larger asset values and results of operations than our partnership will have on the closing date of the offering. Moreover, Big West Oil Predecessor’s historical financial statements before and after the acquisition of the Bakersfield refining complex on March 15, 2005 are not directly comparable, because periods subsequent to the acquisition reflect the addition of the Bakersfield refining complex’s assets and results of operations. In addition, Big West expanded the crude unit at the Salt Lake refining complex in 2004 and expanded the MSCC unit and the alkylation unit at the Salt Lake refining complex in 2006, which resulted in increased throughput at that refining complex subsequent to those expansions.

The following table includes the non-GAAP financial measure Adjusted EBITDA. We define Adjusted EBITDA as earnings before income tax expense, interest expense, depreciation and amortization, and gains or losses on derivative activities. For a reconciliation of Adjusted EBITDA to net income and net cash flow provided by (used in) operating activities, please read “—Non-GAAP Financial Measure” below.

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We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Big West Oil Partners, LP Unaudited Pro Forma Financial Statements.”

	Big West Oil Predecessor Historical
	Fiscal Year Ended January 31,															Six Months Ended July 31,
	2003			2004			2005			2006			2007			2006			2007
																(unaudited)
	(in thousands, except for operating data)
Statement of Operations Data:
Sales	$	310,474		$	481,358		$	715,700		$	2,016,973		$	2,410,078		$	1,286,035		$	1,412,664
Operating costs and expenses:
Cost of products		265,506			408,134			619,726			1,729,022			2,149,090			1,121,375			1,143,500
Cost of refining		19,329			22,568			24,945			133,200			140,257			70,516			84,578
Selling, general and administrative		3,107			3,850			4,785			10,216			12,208			6,181			11,738
Gain on sale of other assets		—			—			—			—			(838	)		—			(2,208	)
Depreciation and amortization		4,944			6,834			6,130			19,220			18,748			8,882			13,612
Total operating costs and expenses		292,886			441,386			655,586			1,891,658			2,319,465			1,206,954			1,251,220
Income from operations		17,588			39,972			60,114			125,315			90,613			79,081			161,444
Other income (expense):
Interest expense, net		(2,912	)		(2,601	)		(958	)		(2,150	)		219			(581	)		451
Other income		(50	)		(13	)		—			—			—			—			—
Income (loss) from investments in affiliated companies(a)		(183	)		96			—			—			—			—			—
Loss on derivative activities		(308	)		(419	)		(7,084	)		(18,106	)		(2,528	)		(2,727	)		(4,003	)
Total other income (expenses)		(3,453	)		(2,937	)		(8,042	)		(20,256	)		(2,309	)		(3,308	)		(3,552	)
Net income	$	14,135		$	37,035		$	52,072		$	105,059		$	88,304		$	75,773		$	157,892
Cash Flow Data:
Cash flows provided by operating activities	$	17,515		$	35,391		$	49,319		$	165,369		$	58,518		$	67,176		$	174,577
Cash flows used in investing activities		(14,161	)		(9,065	)		(31,726	)		(211,277	)		150,328			(38,996	)		(91,883	)
Cash flows provided by (used in) financing activities		(1,789	)		(25,319	)		(19,856	)		47,250			90,480			(28,499	)		(25,462	)
Other Data:
Adjusted EBITDA(b)	$	22,299		$	46,889		$	66,244		$	144,535		$	109,361		$	87,963		$	175,056
Capital expenditures		13,907			9,065			21,726			35,330			151,418			39,201			94,203
Balance Sheet Data (end of period):
Total assets	$	113,157		$	129,201		$	173,903		$	475,716		$	659,368		$	552,213		$	851,936
Total debt		39,565			29,803			22,211			35,392			146,571			6,399			180,000
Total liabilities		84,371			80,110			88,374			238,135			360,339			238,859			452,515
Member’s equity		28,786			49,091			85,529			237,581			299,029			313,354			399,421
Operating Data:
Salt Lake refining complex throughput (bpd)(c)		24,996			28,498			29,520			32,027			30,426			29,148			30,939
Bakersfield refining complex throughput (bpd)(c)		—			—			—			56,874			54,671			57,424			62,945
Salt Lake refining complex sales (bpd)		24,530			31,970			36,858			32,953			31,565			31,199			31,869
Bakersfield refining complex sales (bpd)		—			—			—			55,675			56,555			57,992			65,391
Per barrel of throughput:
Salt Lake refining complex refining margin(d)	$	4.93		$	7.04		$	8.88		$	11.10		$	14.88		$	14.83		$	26.80
Bakersfield refining complex refining margin(d)		—			—			—			8.61			4.80			8.31			10.45
Salt Lake refining complex cost of refining(e)		2.12			2.17			2.31			2.43			2.84			2.95			3.76
Bakersfield refining complex cost of refining(e)		—			—			—			5.71			5.45			5.29			5.57

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(a) Represents the results of an investment in a petroleum wax products joint venture that was dissolved effective as of January 31, 2004.

(b) Please read “—Non-GAAP Financial Measure” below for a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and cash flow from operating activities.

(c) Total refining complex throughput represents the total crude oil and other feedstock inputs in the refining complex production process.

(d) Refining margin per barrel is used to evaluate performance, allocate resources and compare profitability to other companies in the industry. Refining margin per barrel is calculated by dividing the difference between sales and cost of products by total throughput volumes. Refining margin per barrel may not be comparable to similarly titled measures used by other companies. Investors and analysts use these measures to help analyze and compare companies in the industry on the basis of operating performance.

(e) Refining cost per barrel is used to evaluate the efficiency of operations and to allocate resources. Cost of refining per barrel is calculated by dividing cost of refining by total throughput volumes. Cost of refining per barrel may not be comparable to similarly titled measures used by other companies. Investors and analysts use these measures to help analyze and compare companies in the industry on the basis of operating performance.

Non-GAAP Financial Measure

Adjusted EBITDA represents earnings before income tax expense, interest expense, depreciation and amortization, gains or losses on derivative activities and the effect of straight line rents. However, Adjusted EBITDA is not a recognized measurement under GAAP. Management believes that the presentation of Adjusted EBITDA is useful to investors because it is frequently used by security analysts, investors and other interested parties in the evaluation of companies in the refining industry. In addition, management believes that Adjusted EBITDA is useful for the following reasons:

• Adjusted EBITDA is useful in evaluating our operating performance compared to that of other companies in our industry. Our calculation of Adjusted EBITDA eliminates the effects of financing, income taxes, derivative activities and depreciation and amortization, all of which may vary for different companies for reasons unrelated to overall operating performance.

• Management uses Adjusted EBITDA as a measure of operating performance and return on capital and, therefore, public disclosure of Adjusted EBITDA calculated in the same manner is important in explaining how management evaluates our partnership.

• In computing Adjusted EBITDA under our new credit facility, we expect we will be required to include deferred revenue (which excludes the effect of straight-line rents) and exclude loss on derivative activities. We believe it is important to maintain consistency between the way we report Adjusted EBITDA and the way Adjusted EBITDA is required to be calculated for purposes of the credit agreements.

• Adjusted EBITDA is a frequently used financial measure for evaluating cash available for distribution.

Adjusted EBITDA should not be considered as an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

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The following table reconciles EBITDA and Adjusted EBITDA to net income and net cash provided by operating activities for the periods presented:

	Big West Oil Predecessor Historical
	Fiscal Year Ended January 31,															Six Months Ended July 31,
	2003			2004			2005			2006			2007			2006			2007
																(unaudited)
	(dollars in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to net income:
Net income	$	14,135		$	37,035		$	52,072		$	105,059		$	88,304		$	75,773		$	157,892
Interest expense, net		2,912			2,601			958			2,150			(219	)		581			(451	)
Income tax expense
Depreciation and amortization		4,944			6,834			6,130			19,220			18,748			8,882			13,612
EBITDA		21,991			46,470			59,160			126,429			106,833			85,236			171,053
Loss on derivative activities		(308	)		(419	)		(7,084	)		(18,106	)		(2,528	)		(2,727	)		(4,003	)
Adjusted EBITDA	$	22,299		$	46,889		$	66,244		$	144,535		$	109,361		$	87,963		$	175,056

	Big West Oil Predecessor Historical
	Fiscal Year Ended January 31,															Six Months Ended July 31,
	2003			2004			2005			2006			2007			2006			2007
																(unaudited)
	(dollars in thousands)
Reconciliation of EBITDA and Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	17,515		$	35,391		$	49,319		$	165,369		$	58,518		$	67,176		$	174,577
Interest expense, net		2,912			2,601			958			2,150			(219	)		581			(451	)
Other		(527	)		(192	)		(554	)		(1,104	)		77			(414	)		1,072
Change in working capital:
Trade receivables		6,021			3,131			3,634			50,373			(11,051	)		15,564			22,981
Trade receivables from affiliated companies		2,997			1,247			(500	)		2,167			7,620			3,321			(931	)
Inventories		4,035			8,678			15,718			34,681			9,550			25,357			11,386
Prepaid expenses and other assets		957			109			1,970			12,836			27,948			1,856			9,545
Accounts payable and accrued liabilities		(10,682	)		(7,169	)		(11,004	)		(138,115	)		14,273			(28,268	)		(44,387	)
Accounts payable to affiliated companies		(1,578	)		2,330			(576	)		(102	)		911			68			(3,376	)
Other liabilities		341			344			195			(1,826	)		(794	)		(5	)		637
EBITDA		21,991			46,470			59,160			126,429			106,833			85,236			171,053
Loss on derivative activities		(308	)		(419	)		(7,084	)		(18,106	)		(2,528	)		(2,727	)		(4,003	)
Adjusted EBITDA	$	22,299		$	46,889		$	66,244		$	144,535		$	109,361		$	87,963		$	175,056

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion together with the financial statements, pro forma financial information and the respective notes thereto included elsewhere in this prospectus. This discussion contains forward-looking statements that are based on management’s current expectations, estimates and projections about our business and operations. The cautionary statements made in this prospectus should be read as applying to all related forward-looking statements wherever they appear in this prospectus. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under “Risk Factors” and elsewhere in this prospectus. For further information, you should read “Risk Factors” and “Forward-Looking Statements.”

Partnership Overview

We are an independent refiner of petroleum products operating in North Salt Lake, Utah. We were formed as a limited partnership on December 3, 2007 by Big West Oil, LLC, or Big West, a subsidiary of Flying J Inc., or Flying J. Our assets consist of a 35.0% interest in OPCO, which will own the milli-second catalytic cracking unit and alkylation unit at the Salt Lake refining complex. We will control OPCO through our ownership of its general partner. Big West will own the remaining 65.0% interest in OPCO, our general partner and the other process units at the Salt Lake refining complex.

OPCO’s assets will consist of a milli-second catalytic cracking unit, or MSCC unit, and an alkylation unit. These two units enable the Salt Lake refining complex to process black wax and yellow wax crude oils, providing a cost advantage that has recently resulted in favorable refining margins for Big West. In connection with this offering, OPCO will enter into a 25-year refining agreement with Big West. Pursuant to the refining agreement, Big West will agree to throughput during each semi-annual period a minimum volume of gas oils from the distillation unit in the Big West facility to OPCO’s MSCC unit in return for a per barrel refining fee. Similarly, Big West will agree to offtake during each semi-annual period a minimum volume of alkylate processed at OPCO’s alkylation unit in return for a per barrel refining fee. Big West will be obligated to pay the minimum refining fees whether or not it utilizes OPCO’s units. Because OPCO will not own any of the gas oils or alkylate, and because the refining fees will not be tied to commodity prices of either feedstocks or refined products, we believe the refining agreement will substantially reduce our direct exposure to commodity price volatility. In addition, in the event that OPCO’s operating costs under its services agreements with Big West increase for any given year during the term of the refining agreement, the refining fees payable by Big West to OPCO for the following year will be increased permanently by the amount of the operating cost increase for the prior year, which will assist OPCO in maintaining its net operating profit. For a more detailed description of the refining agreement, please read “Business—Agreements with Affiliates—Refining Agreement.”

OPCO will own and operate the following process units:

• Milli-second catalytic cracking unit. The MSCC unit catalytically breaks down complex, lower value gas oils fed to it by the Salt Lake refining complex’s distillation unit into lighter, higher value liquid products such as gasoline, diesel and other higher value hydrocarbon products. The MSCC unit was installed in 2002 and uses innovative technology that increases the efficiency of catalytic reactions. The MSCC unit has a throughput capacity of 11,500 bpd. The MSCC unit underwent its most recent turnaround in April 2006, which lasted 27 days. We expect the next turnaround for this unit to occur in 2011.

• Alkylation unit. The alkylation unit combines lower value, low molecular weight olefins such as propylene, butylene or pentene with isobutane in the presence of a hydrofluoric acid catalyst to produce a higher value, high octane gasoline blending stock called alkylate. Alkylate is a key blendstock in the production of high specification reformulated gasoline. The low molecular weight olefins and a portion of the isobutane used in the alkylation process are generated as a by-product of the MSCC unit.

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Additional isobutane is produced in the butamer unit at the Salt Lake refining complex or supplied by third parties. The alkylation unit has an alkylate offtake capacity of 2,800 bpd. The alkylation unit underwent its most recent turnaround in April 2006, which lasted 29 days. We expect the next turnaround for this unit to occur in 2011.

Immediately following the closing of the offering, Big West will be OPCO’s only customer and account for all of OPCO’s sales. We expect OPCO to continue to derive at least a substantial majority, if not all, of its revenues from Big West or its affiliates for the foreseeable future.

The Salt Lake refining complex was originally constructed in 1948 and, since acquiring the complex in 1985, Big West has significantly upgraded the refining complex’s processing capability and expanded its average daily crude oil throughput from approximately 18,000 bpd to approximately 31,000 bpd. The Salt Lake refining complex’s crude oil inputs consist of black wax crude oil and yellow wax crude oil from the nearby Uinta basin in northeastern Utah, light sweet crude oil (condensate) from Southwest Wyoming, or SWWS, and synthetic crude oil, or syncrude, from Canada. Black wax and yellow wax crude oils and SWWS have generally been less expensive than other benchmark light crude oils such as West Texas Intermediate (WTI), and produce a high percentage of light, high-value refined products.

Approximately 90% of the Salt Lake refining complex’s production during the fiscal year ended January 31, 2007 was higher-value products such as gasoline and diesel, and the remainder of production was marketable by-products. Big West sells the refined products from the Salt Lake refining complex in Utah, Idaho, Nevada, Wyoming, Colorado and Oregon. The Rocky Mountain market historically has had among the highest refining margins between prices of refined products and crude oil feedstocks in the United States.

At the closing of this offering, OPCO will enter into a refining agreement with Big West under which Big West will agree to throughput feedstocks at OPCO’s units for a period of 25 years, subject to renewal. A more detailed description of this agreement appears in “Business—Agreements with Affiliates—Refining Agreement.” For the twelve months ended January 31, 2007 and the six month period ended July 31, 2007, Big West would have accounted for substantially all of OPCO’s pro forma sales and other operating revenue and 100% of its historical revenue. We expect OPCO to continue to derive at least a substantial majority, if not all, of its revenues from Big West or its affiliates for the foreseeable future.

Upon the closing of this offering, our partnership interest in OPCO will represent our only cash generating asset. We anticipate growing by acquiring additional assets directly through subsidiaries and by acquiring additional limited partnership interests in OPCO that Big West may offer us in the future.

Retained Properties

Big West will retain certain refining properties and other assets after the offering that will not be contributed to OPCO (the “Retained Properties”). The Retained Properties will include Big West’s refining complex in Bakersfield, California and all the process units and other assets located at the Salt Lake refining complex other than the MSCC unit and the alkylation unit.

We believe that certain of these retained properties will be potentially suitable over time for possible purchase by our partnership. We may have the opportunity to purchase one or more of the Retained Properties in the future, but Big West is under no legal or contractual obligation to offer or sell such properties to us and may not do so. Big West has invested in the past and intends to continue to invest significant capital to further upgrade the Bakersfield refining complex, including the addition of a 25,000 bpd gas oil hydrotreater, a 19,200 bpd fluid cat cracker, a 9,000 bpd alkylation unit and a 41 million cubic feet per day hydrogen plant. These projects are subject to various regulatory approvals, including California State and Kern County environmental

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approvals, San Joaquin Valley air control and construction permits and an EPA approval. While Big West believes it will receive the required regulatory approvals for the upgrade of the Bakersfield refining complex in the second quarter of 2008, no assurance can be given that it will receive such approvals at that time or in the future.

Factors Affecting Comparability

Big West’s financial condition and operating results have been, and our financial condition and operating results will be, influenced by the following factors, which are fundamental to understanding comparisons of period-to-period financial and operating performance:

Different Asset Bases

Big West’s historical financial condition and results of operations are based upon the financial statements of Big West Oil Predecessor. These financial statements reflect all of the assets located at the Salt Lake refining complex, as well as, for periods on and after March 15, 2005, the refining complex in Bakersfield, California that Flying J acquired from Shell Oil Company and holds through a wholly owned subsidiary of Big West Oil, LLC. The assets of our partnership, on the other hand, will consist on the closing date of the offering only of our interests in OPCO. OPCO’s assets will consist only of the MSCC unit and the alkylation unitat the Salt Lake refining complex. Accordingly, the historical financial statements will reflect significantly larger asset values and results of operations than our partnership will have on the closing date of the offering. Moreover, Big West’s historical financial statements before and after March 15, 2005 are not directly comparable, because periods subsequent to the acquisition reflect the addition of the Bakersfield refining complex’s assets and results of operations. In addition, the market in which the Bakersfield refining complex operates and the relevant crack spreads and other market drivers prevailing in Petroleum Administration for Defense District, or PADD, V, are dissimilar from those in which the Salt Lake refining complex operates or prevailing in PADD IV.

Refining Agreement

Historically, Big West Oil, LLC purchased feedstocks under crude oil supply agreements and sold refined products under offtake and other sale agreements that exposed it to significant commodity risk. Accordingly, Big West’s results of operations were substantially affected by the prevailing crack spreads in PADD IV and the Salt Lake City market in particular.

On the closing date of the offering, OPCO will enter into a refining agreement with Big West. Under the refining agreement, OPCO’s units will refine gas oils supplied by the distillation unit of the Big West facility and will supply Big West with high octane gasoline blending stock (alkylate). In return for these services, OPCO will receive per barrel refining fees based on a specified schedule. Because OPCO will not own any gas oils or alkylate, and because the refining fees will not be tied to commodity prices of either feedstocks or refined products, we expect that OPCO’s results of operations will be less directly correlated to Big West’s historical operations, which have been influenced by prevailing crack spreads and other market indicia related to commodity prices.

The refining agreement along with the master services agreement and the shared services agreement are collectively considered as one agreement for purposes of analysis under GAAP. In accordance with Emerging Issues Task Force Issue No. 01-08,Determining Whether an Arrangement Contains a Lease, this agreement is treated as a lease for accounting purposes. Under the refining agreement, OPCO receives minimum non-refundable cash payments throughout the 25-year life of the agreement. OPCO has determined that the minimum refining payments for the first 24 years qualify as fixed lease payments that are required to be recorded on a straight-line basis over the 25-year life of the agreement. Minimum required payments under the agreement in excess of the recognized revenue will be recorded as deferred revenue. OPCO estimates that $106.7 million of deferred revenue, representing cash received in excess of revenue recognized over the life of the agreement, will

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be recognized as revenue at the end of the agreement. However, the distributable cash for each year of the refining agreement will include $4.3 million in deferred revenue, which is the difference between the minimum cash payments and the revenue recognized under GAAP each year. Distributable cash in year 25 of the agreement is expected to be consistent with the prior years of the refining agreement.

Salt Lake Refining Complex Expansion

In April 2002, Big West completed construction of the MSCC unit at the Salt Lake refining complex. In November 2004, Big West upgraded the crude unit to enhance its processing and throughput capabilities, and Big West replaced the prior reformer with Cycle-X technology developed by UOP, which enables the unit to continually regenerate the reforming catalyst, and added additional throughput capacity. The addition of the MSCC unit and upgrades to the crude unit and reformer, among other things, enabled Big West to increase the average daily crude oil throughput at the Salt Lake refining complex from 19,999 bpd during the fiscal year ended January 31, 2003 to 26,729 bpd for the fiscal year ended January 31, 2007. The Salt Lake refining complex’s average daily total throughput, including other feedstocks, increased from 24,996 bpd to 30,426 bpd over the same time period. In addition, the MSCC unit enabled the Salt Lake refining complex to process greater volumes of lower cost black wax and yellow wax crude oils. The Salt Lake refining complex’s average daily throughput of black wax crude oil increased from 3,719 bpd during the fiscal year ended January 31, 2003 to 8,137 bpd for the fiscal year ended January 31, 2007. Historically, black wax crude oil has been available for purchase at a discount to the cost of other crude oil available in the same region.

Public Partnership Expenses

Our general and administrative expenses will increase as a result of becoming a public partnership following the completion of this offering. We currently anticipate that our total annual general and administrative expenses following the completion of this offering will increase by $1.5 million. Pursuant to the omnibus agreement, for three years following this offering, Big West will agree to reimburse us to the extent these expenses exceed $1.5 million per year. Factors contributing to this increase include costs associated with tax return preparation, accounting support services, preparation of annual, quarterly and periodic reports and proxy statements, increased audit and review fees, investor relations, legal fees and other matters relating to our status as a public partnership. Our financial statements for periods following the completion of this offering will reflect the impact of these increased expenses.

Major Influences on Results of Operations

Future Results of OPCO

OPCO’s results of operations will be primarily dependent on the level of volumes and refining fees under the refining agreement and incremental increases in its costs of sales and operating expenses.

Refining Agreement

Since the volumes of refined products OPCO refines under the refining agreement will comprise substantially all, if not all, of its sales, changes in these volumes will also significantly affect the amount of cash available for distribution.

General. In connection with this offering, OPCO will enter into a 25-year refining agreement with Big West. The refining agreement has a “take or pay” feature requiring Big West to pay a minimum amount of refining fees to OPCO during each semi-annual period whether or not Big West actually throughputs volumes that would accrue such fees.

Gas oil throughput commitment. Big West will agree to throughput in OPCO’s MSCC unit an average of at least 10,000 bpd of gas oil during each semi-annual period (the “MSCC Commitment”) or pay the related

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refining fee as if it had throughput these volumes. Subject to Big West’s right of first refusal with respect to any excess capacity, OPCO will have the right to use any excess capacity in the MSCC unit to process for itself or third parties. OPCO may enter into contracts of up to six months duration with any third party with respect to such excess capacity without Big West’s consent if Big West has failed to pay for the MSCC Commitment for six consecutive months. During the six months ended July 31, 2007, Big West throughput an average of 11,304 bpd of gas oil through the MSCC unit.

The fee for refining barrels of gas oil delivered by Big West to OPCO in any semi-annual period up to the MSCC Commitment will be (i) $29.00 multiplied by (ii) 10,000 multiplied by (iii) the number of days in such semi-annual period (such fee, the “MSCC Refining Fee”). For barrels of gas oil delivered by Big West to OPCO in excess of the MSCC Commitment, if any, the refining fee will be $5.00 per barrel (the “Excess Barrels Refining Fee”). Big West will pay the MSCC Refining Fee in estimated installments on a monthly basis, adjusted monthly and at the end of each semi-annual period. Big West will pay the Excess Barrels Refining Fee, if any, monthly in accordance with the refining agreement. If estimated monthly payments for MSCC Refining Fees by Big West in any semi-annual period fail to meet the minimum MSCC Refining Fee due for such semi-annual period, Big West will be required to pay OPCO cash in the amount of any shortfall. If estimated monthly payments for MSCC Refining Fees paid by Big West in any semi-annual period exceed the actual amount due for such semi-annual period, OPCO will be required to pay Big West cash in the amount of any excess.

Alkylation offtake commitment. Big West will be obligated to offtake an average of at least 2,000 bpd of alkylation product during each semi-annual period (the “Required Offtake Commitment”) or pay the related fee as if it had received these volumes. Subject to Big West’s right of first refusal with respect to any excess capacity, OPCO shall have the right to use the excess capacity of the alkylation unit to process alkylation feedstock for itself or third parties on a spot market basis. OPCO may enter into contracts of up to six months duration with any third party with respect to such excess capacity without Big West’s consent if Big West has failed to pay for its Required Offtake Commitment for six consecutive months. During the six months ended July 31, 2007, Big West received an average of 2,661 bpd of alkylate from the alkylation unit.

The fee for processing Big West’s alkylation feedstock in any semi-annual period up to the Required Offtake Commitment will be (i) $19.00 multiplied by (ii) 2,000 multiplied by (iii) the number of days in such semi-annual period (such fee, the “Alkylation Refining Fee”). For barrels of alkylation product received by Big West above the Required Offtake Commitment, if any, the Alkylation Refining Fee will be $3.00 per barrel (the “Excess Alkylation Refining Fee”). Big West will pay the Alkylation Refining Fee in estimated installments on a monthly basis, adjusted monthly and at the end of each semi-annual period. Big West will pay the Excess Alkylation Offtake Fee, if any, monthly in accordance with the refining agreement. If estimated monthly payments for Alkylation Refining Fees by Big West for any semi-annual period fail to meet the minimum Alkylation Refining Fee due for such semi-annual period, Big West will be required to pay OPCO cash in the amount of any shortfall. If estimated monthly payments for the Alkylation Refining Fees paid by Big West in any semi-annual period exceed the actual amount due for such semi-annual period, OPCO will be required to pay Big West cash in the amount of any excess.

Shortfall payment. A shortfall payment by Big West for unused capacity in any semi-annual period will be applied as credit entitling Big West to have feedstock refined for it by OPCO during the following twelve-month period, subject to certain conditions.

Refining fee increase. In the event that OPCO’s aggregate operating expenses under its services agreements with Big West increase for any given year during the term of the refining agreement, the refining fees payable by Big West to OPCO for the following year will be increased by the amount of the operating cost increase for the prior year. This refining fee increase will be permanent and is intended to offset increases in OPCO’s operating expenses during the term of the refining agreement that would otherwise decrease OPCO’s operating net profit.

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Operating Costs

The results of operations for OPCO’s units are also affected by OPCO’s operating costs. Pursuant to OPCO’s services agreements with Big West, OPCO will reimburse Big West for the cost of natural gas, utilities and other site services and payments for seconded employees. Natural gas prices have historically been volatile. For example, the price of natural gas on the NYMEX ranged between $4.20 and $8.87 per MMBTU during the fiscal year ended January 31, 2007 and $5.86 and $8.19 per MMBTU during the six months ended July 31, 2007. Electricity prices typically fluctuate with natural gas prices. Pursuant to the refining agreement, in the event that OPCO’s operating costs increase for any given year during the term of the refining agreement, the refining fees payable by Big West to OPCO for the following year will be increased permanently by the amount of the operating cost increase for the prior year, as described above. Cost increases for OPCO’s capital expenditures and certain general and administrative expenses will not result in any increase in refining fees.

Seasonality

Operations at the Salt Lake refining complex do not vary significantly over the course of a year.

Safety and Reliability

The safety and reliability of OPCO’s operations and those of the Big West facility are critical to our financial performance. Unplanned downtime historically has resulted in lost refining margin opportunity, increased maintenance costs and a temporary increase in working capital investment and inventory. The financial impact of planned downtime at the Big West facility, such as a turnaround or major maintenance project, is mitigated through a diligent planning process that considers product availability, refining margin environment and the availability of resources to perform the required maintenance. OPCO’s MSCC Unit and alkylation unit underwent their most recent turnarounds in April 2006. We expect the next turnaround for each of these units will occur in 2011. Turnarounds typically occur every five years. The next planned turnaround for the distillation unit that feeds gas oil to the MSCC unit is scheduled to occur in 2014.

Historical Results of Big West

Big West’s historical results of operations have been largely dependent on prevailing refining margins, as discussed below, as well as major components of its cost of refining.

General

Historical earnings and cash flow from the Salt Lake refining complex and Bakersfield refining complex are primarily affected by the difference between refined products sales prices and the costs of crude oil and other feedstocks, which is referred to as refining margin. The cost to acquire feedstocks and the prices of the refined products Big West ultimately sells depend on numerous factors beyond its control, including the supply of, and demand for, crude oil, gasoline and other refined products, which, in turn, depend on, among other factors, domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and government regulation. While sales and operating revenues fluctuate significantly with movements in crude oil and refined products prices, it is the spread between crude oil and refined products prices, and not necessarily fluctuations in those prices, that affects Big West’s earnings.

In order to measure historical operating performance, Big West compares its per barrel refining margin to certain industry benchmarks, specifically PADD IV and PADD V 3/2/1 crack spreads. PADDs are the five Petroleum Administration for Defense Districts in the United States. A 3/2/1 crack spread in a given region is calculated assuming that one barrel of a benchmark crude oil is converted, or cracked, into two-thirds of a barrel of gasoline and one-third of a barrel of diesel. Big West calculates the PADD IV 3/2/1 crack spread using the

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market price of Salt Lake City unleaded gasoline and ultra low sulfur diesel and the market price of WTI crude oil. Big West calculates the PADD V 3/2/1 crack spread using the market prices of LA CARBOB unleaded gasoline and LA CARB ultra low sulfur diesel and the market price of ANS crude oil. The PADD IV and PADD V 3/2/1 crack spreads are intended to represent the per barrel refining margin that a hypothetical crude oil refiner situated in PADD IV or PADD V, respectively, would expect to earn if it refined WTI and ANS crude oil, respectively, and sold gasoline and diesel. Although Big West measures the operating performance of the Bakersfield refining complex against PADD V 3/2/1 crack spreads, prices for gasoline and diesel sold in Bakersfield have typically been higher than the market prices for LA CARBOB unleaded gasoline and LA CARB ultra low sulfur diesel, primarily due to transportation costs. Consequently, Bakersfield crack spreads have typically been higher than PADD V 3/2/1 crack spreads.

Refining Margins

PADD IV benchmark refining margins have historically been higher than benchmark refining margins for the Gulf Coast and East Coast. The Salt Lake refining complex processes substantial amounts of black wax crude oil, yellow wax crude oil, SWWS crude oil and sweet synthetic Canadian crude oil. Historically, overall average realized prices for these crude oils have been typically greater than WTI crude oil. However, more recently the average price of these crude oils have been at substantial discounts to WTI crude oil pricing. The wax crude oils have had the greatest reduction in price due to the increasing supply of Canadian oil in this market and a corresponding decrease in demand for lower quality wax crude oil. SWWS, a byproduct of natural gas production in the Rocky Mountain region, has also been trading at discounts to WTI because of excess supply resulting from increases in natural gas production in the region and the lack of pipeline infrastructure to transport this crude oil to other markets. In addition, the Salt Lake City market has historically realized better average pricing of gasoline and diesel due to the lack of pipeline capacity that limits the import of refined products into this market.

The Bakersfield refining complex is capable of processing substantial volumes of heavy crude oil, which historically has cost less than intermediate and light crude oils. Big West measures the cost advantage of refining heavy crude oil by calculating the difference between the value of WTI crude oil and San Joaquin Valley, or SJV, heavy crude oil. Big West refers to this differential as the light / heavy spread. A widening of the light / heavy spread tends to increase the Bakersfield refining margin and a tightening of the light / heavy spread tends to decrease the Bakersfield refining margin. Historically, 25.0% to 35.0% of the Bakersfield refining complex’s production has been gas oils, which sell at a lower price than gasoline or diesel. As a result, the Bakersfield refining complex margin per barrel is generally less than the PADD V benchmark 3/2/1 crack spread even though the Bakersfield refining complex 3/2/1 crack spread is technically higher than the PADD V benchmark 3/2/1 crack spread. PADD V benchmark refining margins have historically been higher than benchmark refining margins for the Gulf Coast and East Coast.

Inventories and Commodity Prices

The nature of Big West’s business requires it to maintain substantial quantities of crude oil and refined products inventories. Because crude oil and refined products are essentially commodities, Big West has no control over the changing market value of these inventories. Big West values its inventory at the lower of cost or market value under the FIFO inventory valuation methodology. For periods in which commodity prices increase, Big West will report higher net income than it would if Big West were using the LIFO inventory valuation methodology. For periods in which commodity prices decrease, Big West reports lower net income than if it were using the LIFO inventory valuation methodology.

Big West has historically made limited use of derivative instruments to manage a portion of the risks associated with commodity price fluctuations. In particular, Big West has historically used commodity forward contracts to hedge portions of its refined products inventories in excess of targeted levels of such inventories against possible decreases in prices for refined products. These arrangements are intended to offset any decreases

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in prices for the hedged inventory by profits under the forward contracts. Conversely, increases in the prices for the hedged inventory would be offset by losses under the forward contracts. The losses that Big West historically has incurred under these forward contracts represent an offset to the increased revenues that Big West realized from increases in refined products prices.

Critical Accounting Policies

A discussion of Big West’s significant accounting policies is included in the notes to the historical financial statements contained elsewhere in this prospectus. While all of these are important to understand when reading Big West’s financial statements, there are several policies, which are discussed below, that Big West has adopted and implemented from among acceptable alternatives that could lead to different financial results had another policy been chosen. In addition, several of the accounting policies discussed below require significant judgments, assumptions and estimates, which could result in actual results differing materially from those presented in the historical financial statements.

Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its estimated undiscounted future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. Assets to be disposed of would be separately presented in the balance sheet at the lower of the carrying amount or fair value less costs to sell. These future cash flows and fair values are estimates based on our judgment and assumptions.

TurnaroundCosts. The cost of planned major refinery maintenance, referred to as turnarounds, is recorded in other assets in the balance sheet. Turnaround costs are currently deferred and amortized on a straight-line basis beginning upon the completion of the turnaround and ending immediately prior to the next scheduled turnaround. Amortization of turnaround costs is presented in depreciation and amortization in the statements of income.

Environmental Expenditures. Costs associated with environmental remediation obligations are accrued when such costs are probable and can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at Big West’s properties. These estimates are based on internal and third-party assessments of the extent of the contamination, the selected remediation technology and review of applicable environmental regulations. Big West has certain environmental obligations for which it will continue to re-evaluate these accruals based upon changes in facts, circumstances or the law.

Revenue Recognition. Revenues for products sold are recorded upon delivery of the products to their customers, which is the point at which title to the products is transferred, customer has assumed risk of loss, and when payment has either been received or collection is reasonably assured. These revenues are recorded net of sales and excise tax. Big West enters into certain product exchange arrangements, which involve the receipt and delivery of products, the purpose of which are to address location, quality or grade requirements and economics. These transactions are made in contemplation of one another and are viewed as a single transaction. As a result, revenues and cost of sales are netted against each other and are not reflected in the statements of income in accordance with EITF 04-13Accounting for purchases and sales of inventory with the same counterparty. Big West enters into refined product exchange transactions to fulfill sales contracts with its customers by accessing refined products in markets where it does not operate its own refinery. These product exchanges are accounted for as exchanges of non-monetary assets, and no revenues are recorded on these transactions in accordance with EITF 04-13Accounting for purchases and sales of inventory with the same counterparty.

Hedging Activities. Big West considers all forwards, futures, and option contracts to be part of its risk management strategy. Big West has elected not to designate derivative contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized gains and losses for changes in the fair value on open derivative contracts are recognized as gains or losses on derivative activities in Big West’s statement of income.

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Results of Operations

Sales

Sales consist primarily of sales of refined petroleum products through Big West’s refining and marketing operations, including sales of refined petroleum products purchased from other refineries and sold to Big West’s customers. Big West’s sales are mainly affected by crude oil and refined products prices and volume changes caused by changes in utilization rates of its refineries.

Cost of Products

Cost of products includes crude oil and other raw materials, inclusive of transportation costs as well as cost of refined petroleum products purchased from other refineries.

Cost of Refining

Cost of refining includes the costs associated with the actual operations of Big West’s refineries, such as energy and utility costs, labor, routine maintenance, amortization of catalyst costs, insurance and environmental compliance costs. Environmental compliance costs, including monitoring, disposition of waste and routine maintenance, are expensed as incurred. Cost of refining excludes depreciation and amortization of turnaround costs.

Selling, General and Administrative Expenses

Selling, general and administrative expenses consist primarily of costs relating to Big West’s corporate overhead and marketing expenses.

Depreciation and Amortization

Depreciation and amortization primarily consists of depreciation of the refinery units as well as amortization of refinery turnarounds.

Summary Financial and Operating Data

The following tables provide summary financial data, selected key operating statistics and market data:

Big West Oil Predecessor Historical

Statement of Income Data

	Fiscal Year Ended January 31,									Six Months Ended July 31,
	2005			2006			2007			2006			2007
	(in thousands)
Sales	$	715,700		$	2,016,973		$	2,410,078		$	1,286,035		$	1,412,664
Operating costs and expenses:
Cost of products		619,726			1,729,022			2,149,090			1,121,375			1,143,500
Cost of refining		24,945			133,200			140,257			70,516			84,578
Selling, general and administrative expenses		4,785			10,216			12,208			6,181			11,738
Depreciation and amortization		6,130			19,220			18,748			8,882			13,612
Gain on sale of other assets		—			—			(838	)		—			(2,208	)
Total operating costs and expenses		655,586			1,891,658			2,319,465			1,206,954			1,251,220
Income from operations		60,114			125,315			90,613			79,081			161,444
Interest expense, net		(958	)		(2,150	)		219			(581	)		451
Loss on derivative activities(a)		(7,084	)		(18,106	)		(2,528	)		(2,727	)		(4,003	)
Total other (expenses)		(8,042	)		(20,256	)		(2,309	)		(3,308	)		(3,552	)
Net income	$	52,072		$	105,059		$	88,304		$	75,773		$	157,892

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(a) Loss on derivative activities represents losses under derivatives as a result of increases in the prices for our inventory subject to such contracts and offsets the increased revenues that we realized from increases in refined products prices.

The following chart shows the historical Salt Lake refining complex 3/2/1 crack spread relative to the Gulf Coast 3/2/1 crack spread over the corresponding period. The Salt Lake refining complex 3/2/1 crack spread was at a $13.05 per barrel premium to the Gulf Coast 3/2/1 crack spread during the six-month period ended July 31, 2007. The corresponding premiums for the fiscal years ended January 31, 2005, 2006 and 2007 were $4.78, $2.91 and $10.01 per barrel, respectively.

	Fiscal Year Ended January 31,									Six Months Ended July 31, 2007
	2005			2006			2007
	(per barrel)
Gulf Coast 3/2/1 crack spread	$	6.94		$	11.66		$	12.02		$	20.06
Crude quality differential vs. WTI		(0.71	)		(1.39	)		2.18			5.56
Product pricing differential:
Salt Lake City market vs. Gulf Coast		6.52			5.32			9.78			8.65
Big West facility vs. Salt Lake City market		(1.02	)		(1.02	)		(1.95	)		(1.16	)
Salt Lake refining complex vs. Gulf Coast	$	5.50		$	4.30		$	7.83		$	7.49
Salt Lake refining complex 3/2/1 crack spread	$	11.72		$	14.57		$	22.03		$	33.11
Premium to Gulf Coast 3/2/1 crack spread	$	4.78		$	2.91		$	10.01		$	13.05

The Salt Lake refining complex processes a variety of crude oils including black wax, yellow wax, SWWS and syncrude. The average realized price of the Salt Lake refining complex’s crude slate has varied relative to the price of WTI over the corresponding period. In the fiscal years ending January 31, 2005 and 2006, the average realized price of the Salt Lake refining complex’s crude slate was $0.71 and $1.39 higher than the price of WTI. During these periods, the average realized price of Big West’s crude slate was impacted by the terms of historical crude supply contracts which expired in January 2006. In January 2006, the Salt Lake refining complex negotiated new black wax supply contracts under which the black wax crude oil is procured based on more favorable market prices, which reflect the changing black wax crude supply dynamics in the Salt Lake City market. The local posted spot market pricing of black wax has been at a significant discount to WTI due to the increasing production and availability of this lower quality crude oil in the Salt Lake City market. In addition, Big West has changed its crude slate to run a higher volume of SWWS (condensate) in the past 18 months. The supply of SWWS in the Salt Lake market has been increasing due to the growth of natural gas production in the Rocky Mountain region and the lack of pipeline infrastructure to transport the condensate to other regions of the United States. As a consequence of the above factors, the average realized price for the Salt Lake refining complex’s crude slate to WTI has been improving over the past 18 months. Big West believes that this recent trend is currently sustainable as discounted crude oils continue to be increasingly available in the Salt Lake City market.

Refined product pricing in the Salt Lake City market is typically at a premium relative to the Gulf Coast market due to the limited refining capacity in the Salt Lake market and the lack of pipeline infrastructure to import products from other regions of the United States. This trend is evident in the historical data presented in the above table.

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The following chart shows the historical Bakersfield refining complex 3/2/1 crack spread relative to the Gulf Coast 3/2/1 crack spread over the corresponding period. The Bakersfield refining complex 3/2/1 crack spread of $37.69 per barrel was at a $17.63 per barrel premium to the Gulf Coast 3/2/1 crack spread of $20.06 per barrel during the six month period ending July 31, 2007. The corresponding premiums for the fiscal years ending January 31, 2006 and 2007 were $15.36 and $17.15 per barrel, respectively.

	Eleven Months Ended January 31, 2006(1)		Fiscal Year Ended January 31, 2007		Six Months Ended July 31, 2007
	(per barrel)
Gulf Coast 3/2/1 crack spread	$	12.20	$	12.02	$	20.06
Crude quality differential vs. WTI		7.62		5.63		4.93
Product pricing differential:
Los Angeles market vs. Gulf Coast		6.50		8.55		11.46
Bakersfield refining complex vs. Los Angeles market		1.24		2.97		1.24
Bakersfield refining complex vs. Gulf Coast	$	7.74	$	11.52	$	12.70
Bakersfield refining complex 3/2/1 crack spread	$	27.56	$	29.17	$	37.69
Premium to Gulf Coast 3/2/1 crack spread	$	15.36	$	17.15	$	17.63

(1) Reflects the 11-month period that Big West owned the Bakersfield refining complex.

The Bakersfield refining complex crude quality differential vs. WTI decreased to $4.93 for the period ended July 31, 2007 from $7.62 and $5.63 per barrel from the periods ended January 31, 2006 and 2007, respectively. The reduction in crude quality differential in recent periods is because the refining complex has increased the use of SJV light crude oil. Big West is running a higher percentage of SJV light crude oil to enhance the yield of high value products such as gasoline and diesel. Big West plans to invest significant capital to upgrade the Bakersfield refining complex to process greater volumes of the heavily discounted SJV heavy crude oil and maximize the yield of gasoline and diesel. Big West expects this upgrade project to be completed by the fourth quarter of 2009.

In the Bakersfield market, refined products such as gasoline and diesel are priced at a premium relative to the Gulf Coast. As show in the table, the premiums were $7.74, $11.52 and $12.70 per barrel during the 11 months ended January 31, 2006, fiscal year ended January 31, 2007 and the six months ended July 31, 2007. The premiums reflect the relatively more stringent product quality and environmental specifications of the California market, the protected nature of the West Coast market in general, and transportation costs to move product from the Los Angeles hub into the Bakersfield market.

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The table below sets forth posted prices and differentials for crude oil as published by unrelated third parties. These posted prices and differentials do not necessarily reflect Big West’s realized prices and differentials, but demonstrate market trends in the corresponding markets.

Market Reference Prices and Differentials^(a)

	Fiscal Year Ended January 31,							Six Months Ended July 31,
	2005		2006			2007		2006		2007
Crude Oil Prices and Differentials (per barrel):
WTI Crude Oil	$	42.45	$	58.19		$	65.33	$	68.51	$	64.95
WTI less SJVH		9.18		11.78			11.89		12.00		10.19
WTI less SJVL		4.95		6.71			6.45		6.77		4.24
WTI less ANS		2.91		2.88			2.75		2.01		(0.15	)
WTI less Black Wax(b)		3.47		4.50			10.60		9.31		13.18
WTI less Yellow Wax(b)		0.11		0.76			7.30		3.20		12.80
WTI less SWWS(b)		0.82		0.93			1.78		1.09		4.57
WTI less Syn Crude(b)		0.14		(1.22	)		1.22		0.34		(3.76	)
Salt Lake City (per barrel):
Conventional 87 gasoline less WTI	$	13.13	$	13.54		$	18.38	$	17.21	$	31.55
Low sulfur diesel less WTI		14.11		23.84			28.64		25.60		31.49
Los Angeles (per barrel):
CARBOB regular gasoline less ANS	$	20.44	$	20.84		$	22.77	$	28.10	$	34.32
LA CARB ultra low sulfur diesel less ANS		16.84		22.48			24.40		24.68		25.52
Product prices (per barrel):
NYMEX regular unleaded gasoline (cpg)		122.18		164.90			180.51		197.69		208.85
NYMEX No. 2 heating oil (cpg)		115.06		167.95			182.24		189.91		187.68
NYMEX natural gas (per MMBTU)	$	6.17	$	9.25		$	6.79	$	6.78	$	7.35

(a) All price information represents average prices for the periods presented as published by unrelated third parties. The average market reference prices and differentials, unless otherwise noted, are based on posted prices from Platt’s. The average market reference prices and differentials are presented to provide readers with economic indicators that significantly affect Big West’s results of operations and profitability.

(b) Local posted Salt Lake City market prices.

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The tables below provide certain refining and marketing data for the Salt Lake and Bakersfield refining complexes during the time periods indicated.

Summary Refining and Marketing Data

	Year Ended January 31,						Six Months Ended July 31,
	2005		2006		2007		2006		2007
Salt Lake refining complex throughput (bpd)		29,520		32,027		30,426		29,148		30,939
Bakersfield refining complex throughput (bpd)		—		56,874		54,671		57,424		62,945
Big West throughput (bpd)		29,592		88,902		85,097		86,572		93,884
Salt Lake refining complex sales (bpd)		36,858		32,953		31,565		31,199		31,869
Bakersfield refining complex sales (bpd)		—		55,675		56,555		57,992		65,391
Big West sales (bpd)		36,858		88,628		88,120		89,191		97,260
Salt Lake refining complex refining margin (per barrel of throughput)	$	8.88	$	11.10	$	14.88	$	14.83	$	26.80
Bakersfield refining complex refining margin (per barrel of throughput)		—		8.61		4.80		8.31		10.45
Big West consolidated refining margin (per barrel of throughput)		8.88		9.58		8.40		10.51		15.84
Salt Lake refining complex per barrel cost of refining	$	2.31	$	2.43	$	2.84	$	2.95	$	3.76
Bakersfield refining complex per barrel cost of refining		—		5.71		5.45		5.29		5.57
Big West consolidated cost of refining	$	2.31	$	4.43	$	4.52	$	4.50	$	4.98

Summary Refining Throughput and Yields

	Fiscal Year Ended January 31,									Six Months Ended July 31,
	2005(a)			2006			2007			2006			2007
	Bpd	%		Bpd	%		Bpd	%		Bpd	%		Bpd	%
Refining Throughput:
SJV heavy crude	—	—		24,314	27.3	%	20,538	24.1	%	22,756	26.3	%	20,201	21.5	%
SJV light crude	—	—		21,904	24.6		10,446	12.3		8,593	9.9		14,651	15.6
Blend crude	—	—		—	—		13,311	15.6		14,400	16.6		13,618	14.5
Fuel oil, resid ssg	—	—		1,879	2.1		232	0.3		442	0.5		—	—
Black wax	7,631	25.9	%	8,509	9.6		8,137	9.6		7,342	8.5		11,418	12.2
Other light crude	16,309	55.2		19,780	22.2		18,592	21.8		18,758	21.7		16,407	17.5
Total crude oil	23,940	81.1		76,386	85.9		71,256	83.7		72,291	83.5		76,295	81.3
Intermediate and blendstocks	5,580	18.9		12,516	14.1		13,841	16.3		14,280	16.5		17,589	18.7
Total refining throughput	29,520	100.0	%	88,902	100.0	%	85,097	100.0	%	86,572	100.0	%	93,884	100	%
Refining Yield:
LPG	268	0.9	%	2,314	2.6	%	2,230	2.6	%	4,155	4.8	%	2,813	3.0	%
Gasoline	15,560	52.7		34,658	39.0		34,215	40.2		32,635	37.7		38,517	41.0
Diesel	10,150	34.4		22,768	25.6		22,219	26.1		22,913	26.5		26,156	27.9
Gas oils	—	—		14,774	16.6		12,326	14.5		12,745	14.7		13,075	13.9	%
Fuel oil, residual	531	1.8		5,534	6.2		6,378	7.5		7,215	8.3		6,247	6.7
Wax	2,228	7.5		2,480	2.8		1,522	1.8		1,918	2.2		212	0.2
Other	—	—		4,884	5.5		4,898	5.8		3,838	4.4		5,489	5.8
Total refining yield	28,737	97.3	%	87,412	98.3	%	83,788	98.5	%	85,419	98.7	%	92,509	98.5	%

(a) Salt Lake refining complex only.

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Six Months Ended July 31, 2007 Compared to the Six Months Ended July 31, 2006

Sales

Sales for the six months ended July 31, 2007 were $1,412.7 million, compared to $1,286.0 million for the six months ended July 31, 2006, an increase of $126.7 million or 9.8%. This increase was due to both increased sales volumes and higher refined products pricing. Average sales volume for the six months ended July 31, 2007 increased to 97,260 bpd from 89,191 bpd for the six months ended July 31, 2006 due to increased production at Big West’s Salt Lake refining complex and Bakersfield refining complex. The average price per barrel sold at the Salt Lake refining complex and Bakersfield refining complex were $94.75 and $77.16 for the six months ended July 31, 2007 compared to $82.69 and $73.61 for the six months ended July 31, 2006.

Cost of Products

Cost of products was $1,143.5 million for the six months ended July 31, 2007, compared to $1,121.4 million for the six months ended July 31, 2006, an increase of $22.1 million or 2.0%. This increase was due primarily to higher crude oil prices and an 8.4% increase in refinery throughput to 93,884 bpd for the six months ended July 31, 2007 from 86,572 bpd for the six months ended July 31, 2006.

Cost of Refining

Cost of refining was $84.6 million for the six months ended July 31, 2007, compared to $70.5 million for the six months ended July 31, 2006, an increase of $14.1 million or 20.0%. This increase was due to both higher throughput volumes at the Salt Lake refining complex and Bakersfield refining complex and higher cost of refining per barrel. The total refining throughput was 93,884 bpd for the six months ended July 31, 2007 compared to 86,572 bpd for the six months ended July 31, 2006. Big West’s cost of refining per barrel for the six months ended July 31, 2007 was $4.98, compared to $4.50 per barrel for the six months ended July 31, 2006. This increase was due to an increase in natural gas prices and refinery maintenance. The average price of NYMEX natural gas was $7.35 per MMBTU for the six months ended July 31, 2007, compared to $6.78 per MMBTU for the six months ended July 31, 2006.

Selling, General and Administrative Expenses

Selling, general and administrative expenses for the six months ended July 31, 2007 were $11.7 million, compared to $6.2 million for the six months ended July 31, 2006, an increase of $5.5 million or 88.7%. The increase resulted primarily from a $4.6 million increase in employee incentive compensation.

Depreciation and Amortization

Depreciation and amortization for the six months ended July 31, 2007 was $13.6 million, compared to $8.9 million for the six months ended July 31, 2006. The increase in depreciation and amortization is mainly due to increased amortization of refinery turnaround costs in the six months ended July 31, 2007.

Income from Operations

Income from operations for the six months ended July 31, 2007 was $161.4 million, compared to $79.1 million for the six months ended July 31, 2006, an increase of $82.3 million or 104.2%. This increase was primarily due to higher refining margins. Refining margins for the six months ended July 31, 2007 increased to $15.84 per barrel of throughput, compared to $10.51 per barrel of throughput for the six months ended July 31, 2006. The increase in refining margins was primarily attributable to increased gasoline and diesel crack spreads in the Salt Lake City market. The average spread between Salt Lake City conventional 87 gasoline and WTI crude oil increased to $31.55 per barrel for the six months ended July 31, 2007 from $17.21 per barrel for the six months ended July 31, 2006. The average spread between Salt Lake City low sulfur diesel and WTI crude oil increased to $31.49 per barrel for the six months ended July 31, 2007 from $25.60 per barrel for the six months ended July 31, 2006.

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Interest Expense, Net

Interest revenue, net was $ 0.5 million for the six months ended July 31, 2007, compared to expense of $0.6 million for the six months ended July 31, 2006, a increase of $1.1 million. Net interest expense excluding capitalized interest increased $5.1 million to $6.8 million for the six months ended July 31, 2007 compared to $1.8 million for the six months ended July 31, 2006. This increase is due primarily to increased borrowings associated with the upgrade of the Bakersfield refining complex. Increased capitalized interest due to the upgrade of the Bakersfield refining complex offset net interest expense by $7.3 million for the six months ended July 31, 2007 compared to $1.2 million for the six months ended July 31, 2006.

Loss on Derivative Activities

Big West recognized a loss on derivative activities of $4.0 million for the six months ended July 31, 2007, compared to a loss of $2.7 million for the six months ended July 31, 2006. This increased loss was the result of increased commodity price fluctuations.

Net Income

Net income was $157.9 million for the six months ended July 31, 2007, compared to $75.8 million for the six months ended July 31, 2006, an increase of $82.1 million. This increase was attributable to the factors discussed above.

Fiscal Year Ended January 31, 2007 Compared to Fiscal Year Ended January 31, 2006

Sales

Sales for the fiscal year ended January 31, 2007 were $2,410.1 million, compared to $2,017.0 million for the fiscal year ended January 31, 2006, an increase of $393.1 million or 19.5%. This increase was primarily due to higher refined products pricing and was partially offset by a decrease in sales volumes. Big West’s average sales volume for the fiscal year ended January 31, 2007 decreased slightly to 88,120 bpd from 88,628 bpd for the fiscal year ended January 31, 2006. The average price per barrel sold at the Salt Lake refining complex and Bakersfield refining complex were $80.71 and $63.75 for the fiscal year ended January 31, 2007 compared to $69.91 and $60.09 for the fiscal year ended January 31, 2006.

Cost of Products

Cost of products was $2,149.1 million for the fiscal year ended January 31, 2007, compared to $1,729.0 million for the fiscal year ended January 31, 2006, an increase of $420.1 million or 24.3%. This increase was primarily due to higher crude oil prices, and increased throughput volumes at the Bakersfield refining complex.

Cost of Refining

Cost of refining was $140.3 million for the fiscal year ended January 31, 2007, compared to $133.2 million for the fiscal year ended January 31, 2006, an increase of $7.1 million or 5.4%. This increase was primarily due to a full year of throughput volumes at the Bakersfield refining complex. The cost of refining for the fiscal year ended January 31, 2007 was $4.52 per barrel of throughput, compared to $4.43 per barrel of throughput for the fiscal year ended January 31, 2006.

Selling, General and Administrative Expenses

Selling, general and administrative expenses for the fiscal year ended January 31, 2007 were $12.2 million, compared to $10.2 million for the fiscal year ended January 31, 2006, an increase of $2.0 million or 19.6%. This increase resulted primarily from corporate support expenses increasing $2.8 million over the prior year. The increase is partially associated with a full year versus a partial year of operations at the Bakersfield refining complex.

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Depreciation and Amortization

Depreciation and amortization for the fiscal year ended January 31, 2007 was $18.7 million, compared to $19.2 million for the fiscal year ended January 31, 2006. The lower depreciation and amortization in the fiscal year ended January 31, 2007 was primarily due to turnaround costs that fully amortized, partially offset by additional depreciation associated with the completion of various capital projects in the fiscal years ended January 31, 2006 and 2007.

Income from Operations

Income from operations for the fiscal year ended January 31, 2007 was $90.6 million, compared to $125.3 million for the fiscal year ended January 31, 2006, a decrease of $34.7 million or 27.7%. This decrease was driven primarily by Bakersfield gas oil contracts expiring in the fiscal year ended January 31, 2007 resulting in significant margin erosion. Refining margins for the fiscal year ended January 31, 2007 decreased to $8.40 per barrel of throughput, compared to $9.58 per barrel of throughput for the fiscal year ended January 31, 2006. The decrease in refining margins was partially offset by an increase in gasoline and diesel crack spreads in Salt Lake City. The average spread between Salt Lake City low sulfur diesel and WTI crude oil increased to $28.64 per barrel for the fiscal year ended January 31, 2007 from $23.84 per barrel for the fiscal year ended January 31, 2006. The average spread between Salt Lake City conventional 87 gasoline and WTI crude oil increased to $18.38 per barrel for the fiscal year ended January 31, 2007 from $13.54 per barrel for the fiscal year ended January 31, 2006.

Interest Expense, Net

Interest revenue, net was $0.2 million for the fiscal year ended January 31, 2007, compared to an expense of $2.2 million for the fiscal year ended January 31, 2006, a decrease of $2.4 million or 109.1%. This decrease in interest expense is due to the increase in capitalized interest.

Loss on Derivative Activities

Big West recognized a loss on derivative activities of $2.5 million for the fiscal year ended January 31, 2007, compared to $18.1 million for the fiscal year ended January 31, 2006. This decreased loss was the result of decreased commodity price fluctuations

Net Income

Net income was $88.3 million for the fiscal year ended January 31, 2007, compared to $105.1 million for the fiscal year ended January 31, 2006, a decrease of $16.8 million. This decrease was attributable to the factors discussed above.

Fiscal Year Ended January 31, 2006 Compared to Fiscal Year Ended January 31, 2005

Sales

Sales for the fiscal year ended January 31, 2006 were $2,017.0 million, compared to $715.7 million for the fiscal year ended January 31, 2005, an increase of $1,301.3 million or 181.8%. This increase was due to both increased sales volumes and higher refined products pricing. Average sales volume for the fiscal year ended January 31, 2006 increased to 88,628 bpd from 36,858 bpd for the fiscal year ended January 31, 2005 due to the acquisition of the Bakersfield refining complex and increased production at the Salt Lake refining complex. The average price per barrel sold at the Salt Lake refining complex was $69.91 for the fiscal year ended January 31, 2006 compared to $54.34 for the fiscal year ended January 31, 2005.

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Cost of Products

Cost of products was $1,729.0 million for the fiscal year ended January 31, 2006, compared to $619.7 million for the fiscal year ended January 31, 2005, an increase of $1,109.3 million or 179.0%. This increase was due to the acquisition of the Bakersfield refining complex, increased throughput at the Salt Lake refining complex and higher crude oil and feedstock costs.

Cost of Refining

Cost of refining was $133.2 million for the fiscal year ended January 31, 2006, compared to $24.9 million for the fiscal year ended January 31, 2005, an increase of $108.3 million or 434.9%. This increase was due to the acquisition of the Bakersfield refining complex and increased expenses resulting from higher throughput at the Salt Lake refining complex. Big West’s cost of refining per barrel for the fiscal year ended January 31, 2006 was $4.43 compared to $2.31 per barrel for the fiscal year ended January 31, 2005. This increase was due to the acquisition of the Bakersfield refining complex which has a higher per barrel cost of refining than the Salt Lake refining complex as well as increased natural gas prices. The average price of NYMEX natural gas was $9.25 per MMBTU for the fiscal year ended January 31, 2006, compared to $6.17 per MMBTU for the fiscal year ended January 31, 2005. Also contributing to the increase were costs associated with hiring contractors to operate the Bakersfield refining complex while new employees were in training and retention bonuses paid to employees.

Selling, General and Administrative Expenses

Selling, general and administrative expenses for the fiscal year ended January 31, 2006 were $10.2 million, compared to $4.8 million for the fiscal year ended January 31, 2005, an increase of $5.4 million or 112.5%. This increase resulted primarily from corporate support expenses increasing $2.6 million due to the acquisition of the Bakersfield refining complex.

Depreciation and Amortization

Depreciation and amortization for the fiscal year ended January 31, 2006 was $19.2 million, compared to $6.1 million for the fiscal year ended January 31, 2005. The increase in depreciation is due to the acquisition of the Bakersfield refining complex and completion of various Salt Lake refining complex capital projects in the fiscal years ended January 31, 2005 and 2006.

Income from Operations

Income from operations for the fiscal year ended January 31, 2006 was $125.3 million, compared to $60.1 million for the fiscal year ended January 31, 2005, an increase of $65.2 million or 108.5%. This increase was primarily due to ten and one-half months of financial contributions from the Bakersfield refining complex and higher refining margins at the Salt Lake refining complex. Refining margins for the fiscal year ended January 31, 2006 increased to $9.58 per barrel of throughput, compared to $8.88 per barrel of throughput for the fiscal year ended January 31, 2005. This increase was primarily attributable to increased gasoline and diesel crack spreads. The average spread between Salt Lake City conventional 87 gasoline and WTI crude oil increased to $13.54 per barrel for the fiscal year ended January 31, 2006 from $13.13 per barrel for the fiscal year ended January 31, 2005. The average spread between Salt Lake City low sulfur diesel and WTI crude oil increased to $23.84 per barrel for the fiscal year ended January 31, 2006 from $14.11 per barrel for the fiscal year ended January 31, 2005.

Interest Expense, Net

Interest expense, net was $2.2 million for the fiscal year ended January 31, 2006, compared to $1.0 million for the fiscal year ended January 31, 2005, an increase of $1.2 million or 120.0%. This increase was primarily attributable to the increase in borrowings under Big West’s revolving credit facility as a result of the acquisition of the Bakersfield refining complex in March 2005.

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Loss on Derivative Activities

Big West recognized a loss on derivative activities of $18.1 million for the fiscal year ended January 31, 2006, compared to $7.1 million for the fiscal year ended January 31, 2005. This increased loss was the result of increased commodity price fluctuations.

Net Income

Net income was $105.1 million for the fiscal year ended January 31, 2006, compared to $52.1 million for the fiscal year ended January 31, 2005, an increase of $53.0 million. This increase was attributable to the factors discussed above.

Liquidity and Capital Resources

Big West’s historical sources of liquidity are cash generated from operating activities and borrowings under its term loan and revolving credit facility. Big West’s principal uses of cash have included capital expenditures, working capital and debt service. Our primary sources of liquidity will be cash distributions from OPCO and borrowings available under our new credit facility. We believe that these sources of liquidity will be sufficient to satisfy our anticipated cash requirements for the foreseeable future. OPCO’s ability to make distributions to us will depend on its ability to generate sufficient cash from operating activities, which is subject to general economic, political, financial, competitive and other factors beyond our control. OPCO’s and our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors, including any expansions through organic growth projects or acquisitions.

Big West Cash Flows

The following table sets forth Big West’s cash flows for the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2006 and 2007:

	Fiscal Year Ended January 31,									Six Months Ended July 31,
	2005			2006			2007			2006			2007
	(dollars in thousands)
Net cash provided by (used in)
Operating activities	$	49,319		$	165,369		$	58,518		$	67,176		$	174,577
Investing activities		(31,726	)		(211,277	)		(150,328	)		(38,996	)		(91,883	)
Financing activities		(19,856	)		47,250			90,480			(28,499	)		(25,462	)
Increase (decrease) in cash and cash equivalents	$	(2,263	)	$	1,342		$	(1,330	)	$	(319	)	$	57,232

Cash Flows Provided By Operating Activities. Net cash provided by operating activities for the six months ended July 31, 2007 was $174.6 million, compared to $67.2 million cash provided in the six months ended July 31, 2006. The $107.4 million increase was primarily attributable to an $82.1 million increase in net income and a $22.0 decrease in working capital requirements. Negative working capital was $4.1 million at July 31, 2007, compared to working capital of $17.9 million at July 31, 2006. The most significant sources of cash from operating activities for the six months ended July 31, 2007 were net income of $157.9 million and a $44.4 million increase in accounts payable and accrued liabilities. The most significant use of cash in operating activities for the six months ended July 31, 2007 was a $23.0 million increase in trade receivables and a $11.4 million increase in inventories. The most significant source of cash from operating activities for the six months ended July 31, 2006 was net income of $75.8 million and a $28.3 million increase in accounts payable and accrued liabilities. The most significant uses of cash in operating activities for the six months ended July 31, 2006 were a $25.4 million increase in inventories and an $18.9 million increase in trade receivables. The increases in accounts payable and accrued liabilities and inventories were primarily due to higher commodity prices.

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Net cash provided by operating activities for the fiscal year ended January 31, 2007 was $58.5 million, compared to $165.4 million for the fiscal year ended January 31, 2006. The $106.9 million decrease was primarily attributable to a $16.8 million decrease in net income and a $88.5 million increase in working capital. The most significant sources of cash from operating activities for the fiscal year ended January 31, 2007 were net income of $88.3 million and a $11.1 million increase in trade receivables. The most significant uses of cash in operating activities for the fiscal year ended January 31, 2007 were a $27.9 million increase in prepaid expenses and other assets and a $9.6 million increase in inventories. The increases in inventories were primarily due to higher commodity prices.

Net cash provided by operating activities for the fiscal year ended January 31, 2006 was $165.4 million compared to $49.3 million for the fiscal year ended January 31, 2005. The $116.1 million increase was primarily attributable to a $53.0 million increase in net income and a $49.4 million decrease in working capital requirements. The most significant sources of cash from operating activities for the fiscal year ended January 31, 2006 were net income of $138.1 million and a $140.1 million increase in accounts payable and accrued liabilities. The most significant uses of cash in operating activities for the fiscal year ended January 31, 2006 were a $52.5 million increase in trade receivables and a $34.7 million increase in inventories. The increases in accounts payable and accrued liabilities, inventories and trade receivables were primarily due to the acquisition of the Bakersfield refining complex and increased commodity prices.

Cash Flows Used in Investing Activities. Net cash used in investing activities for the six months ended July 31, 2007 was $91.9 million compared to $39.0 million for the six months ended July 31, 2006. Big West’s primary investments for the six months ended July 31, 2007 were $55.1 million for the upgrade of the Bakersfield refining complex, $8.1 million for upgrading the heaters in several units at the Bakersfield refining complex to comply with emission requirements, $7.3 million in capitalized interest, $5.5 million in bringing on line the mild hydrocracker at the Bakersfield refining complex, with the remaining increase due to increasing operating efficiencies and to sustaining capital needs and growth opportunities at the Salt Lake refining complex and Bakersfield refining complex.

Net cash used in investing activities decreased to $150.3 million for the fiscal year ended January 31, 2007 from $211.3 million for the fiscal year ended January 31, 2006. Big West’s primary investments during the fiscal year ended January 31, 2007 included $103.7 million for the upgrade of the Bakersfield refining complex, $10.7 million for expansion of the alkylation unit at the Salt Lake refining complex, $5.5 million in capitalized interest, and the remaining increase due to increase operating efficiencies and to sustaining capital needs and growth opportunities at the Salt Lake refining complex and Bakersfield refining complex.

Net cash used in investing activities increased to $211.3 million for the fiscal year ended January 31, 2006 from $31.7 million for the fiscal year ended January 31, 2005. Big West’s primary investments during the fiscal year ended January 31, 2006 were $176.7 million for the acquisition of the Bakersfield refining complex, $20.0 million for the upgrade of the Bakersfield refining complex, and the remaining increase due to increase operating efficiencies and to sustaining capital needs and growth opportunities at the Salt Lake refining complex and Bakersfield refining complex.

Cash Flows Provided By / Used In Financing Activities. Net cash used in financing activities was $25.5 million during the six months ended July 31, 2007 compared to net cash used in financing activities of $28.5 million during the six months ended July 31, 2006. Cash used in financing activities in the six months ended July 31, 2007 included $143.3 million from net payments on the revolving line of credit and $57.5 million in distributions, partially offset by $180.0 million in proceeds under notes payable. Cash used in financing activities in the six months ended July 31, 2006 included $26.0 million from net payments on the revolving line of credit and $3.0 million of debt repayments.

Net cash provided by financing activities was $90.5 million for the fiscal year ended January 31, 2007 compared to $47.3 million for the fiscal year ended January 31, 2006. Cash provided by financing activities for

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the fiscal year ended January 31, 2007 included $117.3 million from net proceeds on the revolving line of credit and $5.5 million on proceeds from affiliated companies, partially offset by $26.0 million in distributions and $6.1 million of debt repayments. Cash provided by financing activities for the fiscal year ended January 31, 2006 included a $90.0 million contribution from Flying J for the acquisition of the Bakersfield refining complex and $26.0 million from net proceeds on the revolving line of credit, partially offset by a $43.4 million tax distribution to Flying J, $12.8 million of debt repayments and $11.5 million on payments to affiliated companies.

Net cash provided by financing activities for the fiscal year ended January 31, 2006 was $47.3 million compared to net cash used in financing activities of $19.9 million for the fiscal year ended January 31, 2005. The cash used in financing activities in the fiscal year ended January 31, 2005 reflected the principal payments on long-term debt of $7.6 million and tax distributions to members of $35.7 million, partially offset by contributions from Flying J of $20.0 million and proceeds from notes payable to affiliated companies of $4.2 million.

Big West Cash Position and Indebtedness

As of July 31, 2007, Big West’s total cash was $57.6 million, and total indebtedness was $180.0 million.

Summary of Indebtedness. The following table sets forth the principal amounts outstanding as of July 31, 2007 under Big West’s existing revolving credit facility and term loan:

	As of July 31, 2007
	(dollars in thousands)
Revolving credit facility	$	—
Term loan		180,000
Total obligations	$	180,000

Big West Term Loan. On May 15, 2007, Big West entered into a $400 million secured term loan credit agreement with a syndicated group of lenders. Big West initially drew $180 million under the facility and can make two additional draws up to the $400 million limit no later than August 31, 2008. Big West can borrow under the revolving credit facility using base rate loans, eurodollar rate loans, or a combination of both. The borrowings under the base rate loans bear interest at the Federal Funds rate plus an amount that varies from 1.00% to 2.00% per annum based on a leverage ratio. The borrowings under the credit facility are secured by all of Big West’s assets, including the Salt Lake refining complex. The credit facility contains representations and warranties, affirmative, negative and financial covenants and events of default that Big West believes are customary for financing of this kind. The term loan expires May 15, 2014. Big West intends to repay the term loan upon the closing of the offering.

Existing Big West Revolving Credit Facility. On March 15, 2005, Big West entered into a $130 million revolving credit facility with a non-affiliated lender. Big West exercised its ability to increase the facility up to $200 million by receiving additional commitments from the nonaffiliated lenders. Borrowing availability under the revolving credit facility is limited at any time to an amount equal to the lower of $200 million and the amount of the borrowing base. As of January 31, 2007, the borrowing base under the revolving credit facility was limited to $167.4 million. Big West can borrow under the revolving credit facility using base rate loans, eurodollar rate loans, or a combination of both. The borrowings under the base rate loans bear interest at the Federal Funds rate plus 0.5%, and the borrowings under the eurodollar rate loans bear interest at the Eurodollar rate plus an amount that varies from 1.00% to 2.00% per annum based on a leverage ratio. The average borrowing rate for thefiscal year ended January 31, 2007was approximately 7.32%. The borrowings under the revolving credit facility are secured by the Big West’s accounts receivable and inventory. The revolving credit facility contains representations and warranties, affirmative, negative and financial covenants and events of default that Big West believes are customary for financings of this kind. The revolving credit facility expires on March 15, 2010. As of January 31, 2007 and July 31, 2007, the outstanding balance on the revolving credit facility was $143.3 million

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and $0, respectively, and there were no outstanding letters of credit. The existing revolving credit facility will remain in place after the closing of the offering; however, neither we nor OPCO will guarantee Big West’s debt or be deemed restricted subsidiaries under the facility.

Our New Credit Facility. In connection with the closing of this offering, we expect to enter into a new credit facility. The facility will consist of two term loans:

• a senior secured term loan of $130.0 million; and

• a senior unsecured term loan of $151.0 million.

We anticipate that the new credit facility will contain restrictive covenants which will limit our ability to, among other things:

• grant liens;

• make certain loans or investments;

• incur additional indebtedness or guarantee other indebtedness;

• make any material change to the nature of our business;

• make any material dispositions of assets; or

• enter into a merger, consolidation, sale leaseback transaction or purchase of assets.

We anticipate that the credit facility will prohibit us from paying distributions to our unitholders if we are not in compliance with certain financial covenants or upon the occurrence of an event of default. We anticipate that events of default under our new credit facility will include:

• failure to pay any principal, interest, fees, expenses or other amounts when due;

• breach of certain financial covenants;

• failure to observe any other agreement, security instrument, obligation or covenant beyond specified cure periods in certain cases;

• default under other indebtedness;

• bankruptcy or insolvency events; and

• failure of any representation or warranty to be materially correct.

We will borrow $130.0 million under the secured term loan facility at closing and will purchase and pledge $130.0 million of certificates of deposit which will initially secure the secured term loan facility. We anticipate that these certificates of deposit may be liquidated, subject to limited re-investment rights, for the purpose of funding permitted acquisitions and permitted capital expenditures. In the event the underwriters exercise the option to purchase additional common units, we will make additional borrowings under the secured term loan facility and purchase and pledge an equal amount of certificates of deposit to further secure the term loan facility. See “Use of Proceeds.” Our obligations under the $151.0 million senior loan will be unsecured.

Capital Spending

OPCO’s operations are capital intensive, requiring investments to expand, upgrade or enhance existing operations and to meet environmental and operations regulations. Capital requirements have consisted of and are expected to continue to consist primarily of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the operating capacity of existing assets and extend their useful lives. Expansion capital expenditures

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represent capital expenditures to expand the operating capacity of existing or new assets, whether through construction or acquisition. Repair and maintenance expenses associated with existing assets that are minor in nature and do not extend the useful life of existing assets are charged to operating expenses as incurred. Maintenance capital expenditures include expenditures for turnarounds and other expenditures required to maintain equipment reliability and safety and to address environmental regulations. Expansion capital expenditures include expenditures to acquire assets and to expand existing facilities, such as projects that increase throughput capacity.During the three years ended January 31, 2007 and the six months ended July 31, 2007, a total of $2.0 million in maintenance capital expenditures and $17.0 million for acquisitions and expansion and/or upgrades was expended for OPCO’s units.

Over the five years following the date of this offering, we estimate that OPCO will need to reserve an average of approximately $1.5 million per year for direct turnaround costs, other maintenance capital expenditures and loss of revenues from a turnaround.

OPCO’s partnership agreement requires it to distribute all of its available cash each quarter. In determining the amount of cash available for distribution, the board of directors of our general partner, on our behalf, determines the amount of cash reserves to set aside, including reserves for turnarounds, future maintenance capital expenditures, working capital and other matters. OPCO’s estimated initial annual maintenance capital expenditures and turnaround reserves are $1.5 million per year, which includes direct turnaround costs and reserves related to lost revenues from the turnaround. We estimate OPCO’s units will require a turnaround every five years and that each turnaround will result in approximately four weeks of lost revenue. The actual cost of a turnaround will depend on a number of factors. Our partnership agreement requires our general partner to deduct from our operating surplus each quarter estimated maintenance capital expenditures, as opposed to actual maintenance capital expenditures, in order to reduce disparities in operating surplus caused by fluctuating maintenance capital expenditures. The board of directors of our general partner with the approval of its conflicts committee may change the annual amount of our estimated maintenance capital expenditures and turnaround reserves. In years when estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus.

We anticipate that future expansion capital requirements will be provided through long-term borrowings or other debt financings and/or equity capital offerings.

Tier II Requirements. The Salt Lake refining complex is currently in compliance with the Federal Clean Air Act regulations requiring a reduction in sulfur content in gasoline to no more than 30 ppm and a reduction in sulfur in diesel to no more than 15 ppm for at least 80% of our diesel fuels. Big West may need to install additional equipment at the Big West facility to enable all of its diesel product to meet the new sulfur standard that is expected to take effect in June 2010. The Salt Lake refining complex has not been classified as a small refinery and compliance with these requirements is not based upon such a classification. Big West is continuing to review its options for complying with the 2010 standard, although we do not expect OPCO’s units will be affected by such regulations.

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Contractual Obligations and Commercial Commitments

Information regarding Big West’s known contractual obligations of the types described below as of January 31, 2007 is set forth in the following table. As of January 31, 2007, Big West did not have any capital lease obligations but did have agreements to purchase feedstocks that were binding on Big West and that specified all significant terms. Certain purchase obligations for feedstock totalling $2.5 billion are not included in the table below as they are cancelable. The $180.0 million outstanding balance of long-term debt is as of July 31, 2007 following a financing completed on May 15, 2007. See “—Liquidity and Capital Resources—Big West Cash Position and Indebtedness.”

	Payments Due By Period
	Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years		Total
	(dollars in thousands)
Contractual obligations:
Long term debt obligations	$	2,000	$	8,000	$	8,000	$	162,000	$	180,000
Interest on long term debt obligations		10,035		25,978		24,750		26,819		87,582
Purchase obligations		159,425		338,048		2,500		—		499,973
Other commitments		1,426		654		436		1,091		3,607
Total obligations	$	172,886	$	372,680	$	35,680	$	189,910	$	771,162

On a pro forma basis, after giving effect to the offering, borrowings under the new credit facility and the application of the proceeds therefrom, our contractual obligations at July 31, 2007 would have been as follows:

	Payments Due By Period
	Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years		Total
	(dollars in thousands)
Contractual obligations:
Long term debt obligations	$	—	$	130,000	$	—	$	151,000	$	281,000
Interest on long term debt obligations		16,725		33,450		20,060		20,060		90,295
Total obligations	$	16,725	$	163,450	$	20,060	$	171,060	$	371,295

In the ordinary conduct of Big West’s business, it is subject to periodic lawsuits, investigations and claims, including, environmental claims and employee related matters. Although Big West cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against it, Big West does not believe that any currently pending legal proceeding or proceedings to which it is a party will have a material adverse effect on its or our business, results of operations, cash flows or financial condition.

Big West has defined benefit pension plans that cover substantially all of its contract hourly employees and postretirement benefit obligations for its qualified employees at the Bakersfield refinery. For most of these liabilities, timing of the payment of such liabilities is not fixed and therefore cannot be determined as of January 31, 2007. However, certain expected payments related to expected pension contributions in 2007 and postretirement obligations are discussed in Note 9 of the historical financial statements included elsewhere in this prospectus. For purposes of reflecting amounts for other commitments in the table above, we have made our best estimate of expected payment based on available information as of January 31, 2007.

Off-Balance Sheet Arrangements

Big West has no off-balance sheet arrangements and OPCO does not anticipate entering into off-balance sheet arrangements.

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Quantitative and Qualitative Disclosure about Market Risk

Historically, changes in commodity prices, purchased fuel prices and interest rates were Big West’s primary sources of market risk.

Interest Rate Risk

The carrying value for certain short-term financial instruments that mature or re-price frequently at market rates approximates fair value. Such financial instruments include cash, trade and other receivables, other assets, revolving lines of credit, accounts payable and other accrued liabilities. Because the blended interest rate of debt approximates the current interest rates available, the carrying value of debt instruments also approximates fair market value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.

Commodity Price Risk

Historically, Big West has been exposed to market risks related to the volatility of crude oil and refined products prices, as well as volatility in the price of natural gas used in the operation of its refineries. To the extent such factors may affect the volumes Big West puts through OPCO’s units, our financial results can be affected by fluctuations in these prices, which depend on many factors, including demand for crude oil, gasoline and other refined products, changes in the economy, worldwide production levels, worldwide inventory levels and governmental regulatory initiatives. Big West’s risk management strategy identifies circumstances in which it may utilize the commodity futures market to manage risk associated with these price fluctuations.

In the past, circumstances have occurred, such as turnaround schedules or shifts in market demand, that have resulted in variances between Big West’s actual inventory level and its desired inventory level. In such circumstances, Big West has utilized and may continue to utilize commodity derivatives to manage price exposure to these inventory positions. The commodity derivative instruments may take the form of forward contracts and are entered into with counterparties that Big West believes to be creditworthy. In accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, all commodity forward contracts are recorded at fair value and any changes in fair value between periods are recorded in the gain or loss on derivative activities line item on the income statement. Historically, Big West has elected not to designate these instruments as cash flow hedges for financial accounting purposes. Therefore, changes in the fair value of these derivative instruments are included in income in the period of change. Net gains or losses are reflected in gain (loss) on derivative activities at the end of each period. For the fiscal year ended January 31, 2007, Big West had $2.5 million in net realized and unrealized losses accounted for using mark-to-market accounting.

During the fiscal year ended January 31, 2007, Big West did not have any derivative instruments that were designated and accounted for as hedges. Neither OPCO nor we expect to utilize commodity derivatives with respect to feedstocks put through OPCO’s units or refined products it produces under the refining agreement, because neither OPCO nor we will not have title to such feedstocks or refined products.

Concentration of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. We place our cash and cash equivalent investments with high-quality financial institutions and limit the amount of credit exposure to any one financial institution. Concentrations of credit risk with respect to trade receivables result from sales of refined products to companies affiliated with Flying J. Big West will account for all our revenue under the refining agreement. See “Risk Factors—Risks Related to Our Business—OPCO is subject to the credit risk of Big West on all of its revenues, and Big West’s leverage and creditworthiness could adversely affect our ability to make distributions to our unitholders.” In the event we were to sell refined products to persons other than Big West, the remaining trade receivables would be

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due from such customers. Big West has routinely performed credit evaluations of its customers and maintained allowances for potential credit losses, and we expect to do the same if we acquire customers unrelated to Flying J.

Standards Issued Not Yet Adopted

In September 2006, the FASB published SFAS No. 157,Fair Value Measurements (SFAS No. 157), to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS No. 157 retains the exchange price notion in earlier definition of fair value, but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or liability in the principal or most advantageous market for the asset or liability. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price), as opposed to the price that would be paid to acquire the asset or received to assume the liability at the measurement date (an entry price). SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in this Statement applies for derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, although earlier application is encouraged. The FASB has deferred until fiscal years beginning after November 15, 2008 the statement’s measurement requirements for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. Big West is evaluating the impact, if any, that SFAS No. 157 will have on its financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159), which permits entities to measure many financial instruments and certain other items at fair value at specified election dates that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected should be reported in earnings at each subsequent reporting date. The provisions of SFAS No. 159 are effective for Big West as of January 1, 2008. Big West is currently evaluating the impact this standard will have on its financial position and results of operations.

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REFINING INDUSTRY OVERVIEW

Oil refining is the process of converting the hydrocarbon molecules present in crude oil into marketable finished petroleum products, such as gasoline, diesel, jet fuel, liquefied petroleum gas (LPG), gas oil, fuel oil and heating oil. Refining is primarily a margin-based business where both the feedstocks and refined finished petroleum products are commodities. Refiners create value by selling refined petroleum products at prices higher than the costs of acquiring crude oil and other feedstocks.

Refining Process

A typical refinery uses multiple process units. The number and complexity of the process units is dictated by the quality of crude oil inputs and the desired end product specifications.

Fractional Distillation

The first step in refining is fractional distillation in a crude unit. This step is based on the fundamental physical characteristic that different hydrocarbons boil at different temperatures. In general, the more carbon atoms in the hydrocarbon molecule, the higher the temperature at which it boils and vaporizes. For example, methane has one carbon atom per molecule and would boil at a lower temperature than gasoline, which has 6 to 12 carbon atoms per molecule.

A crude unit is generally comprised of an atmospheric distillation unit and a vacuum distillation unit. Within the atmospheric and vacuum distillation units are tall columns called fractionating columns that are divided inside at intervals by horizontal trays. As the crude oil boils, it vaporizes. Each hydrocarbon fraction rises to a tray at a temperature just below its own boiling point where it cools and turns back into a liquid. The low boiling liquids (such as LPG) vaporize and exit the top of the atmospheric distillation unit, medium boiling liquids (such as unfinished gasoline and diesel) settle in the middle trays, while heavy hydrocarbons such as gas oils are separated in the bottom trays of the crude unit. Big West does not currently utilize the vacuum distillation unit at its Salt Lake refining complex.

Cracking

Cracking is a chemical process in which gas oils from the crude unit are converted into lighter hydrocarbon combinations and more desirable finished products. Cracking uses extreme heat and pressure to break or “crack” higher boiling point molecules to make the smaller, lighter, lower boiling point molecules of LPG, gasoline and diesel.

There are three main types of cracking processes. Catalytic cracking or “cat cracking” employs intense heat, pressure, and a catalyst to create a chemical reaction. Hydrocracking is a variation that uses hydrogen as well as heat, pressure and catalyst. Thermal cracking, also known as coking, uses elevated temperatures and similar technology as a catalytic cracker and converts residual or vacuum bottoms into naphtha, distillate and gas oil. OPCO’s MSCC unit is a cat cracking unit.

Desulfurization and Reforming

Naphtha and gasoline are purified by heating, pressurizing and introducing hydrogen through a hydrotreater in order to remove impurities such as sulfur. The resulting naphtha and gasoline are then processed through units such as isomerization units and reformers to create gasoline blendstocks. Isomerization rearranges molecules without changing their size or physical structure. Reformers also rearrange molecules by converting low-octane naphtha fractions into high-octane gasoline blendstocks.

Distillates such as diesel, jet fuel and kerosene fractionated from the crude units are generally processed through a hydrodesulfurization unit. This unit uses hydrogen and generally a nickel or cobalt catalyst to remove

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sulfur from the distillates. The resulting desulfurized distillates can then be sold as finished products or introduced into the distillate blending pool to lower the pour point of diesels to meet seasonal specifications.

LPGs such as propane, butane and propylene generated in the distillation and cracking processes can be burned as refinery fuel, sold as heating products to customers (propane), sold to chemical plants to produce petrochemicals, or further transformed into a high octane gasoline blendstock (alkylate) at the refinery. The transformation is achieved in an alkylation unit where the smaller, lighter LPG hydrocarbon molecules are combined with isobutane in the presence of a sulfuric or hydrofluoric acid catalyst. The alkylation process yields butane, propane and alkylate. OPCO’s alkylation unit yields propane and alkylate.

Market Trends

The U.S. refining industry is currently characterized by limited refining capacity, high utilization rates, increased crack spreads, strong demand fundamentals, dependence on imports, increased light/heavy crude oil spreads, increased supply of Canadian crude oil and higher refining margins in the Rocky Mountain and West Coast regions than in other regions of the United States.

Strong Demand Fundamentals

The supply and demand fundamentals of the domestic refining industry have improved since the 1990s and are expected to remain favorable as the growth in demand for refined products continues to exceed increases in refining capacity. Over the next twenty-five years, the Department of Energy’s Energy Information Administration, or EIA, projects that U.S. demand for refined products will grow at an average of 1.1% per year compared to total domestic refining capacity growth of only 0.63% per year. Approximately 93.4% of the projected demand growth is expected to come from the increased consumption of light refined products (including gasoline, diesel, jet fuel, kerosene, and distillate), which are more difficult and costly to produce than heavy refined products (including asphalt and carbon black oil).

Limited U.S. Refining Capacity

In the 1980s, decreasing petroleum product demand and deregulation of the domestic refining industry, along with new fuel standards introduced in the early 1990s, contributed to decreased domestic refining capacity in the United States. According to the EIA, domestic refining capacity decreased approximately 7% between January 1981 and January 2007, from 18.6 million bpd to 17.4 million bpd. The primary factor contributing to this decline was a decrease in the number of U.S. refineries, from a peak of 324 in 1981 to 149 in January 2007. The last major new oil refinery in the United States was built in 1976. According to the EIA, while domestic refining capacity has decreased approximately 7% from 6.8 billion barrels in 1981 to 6.4 billion barrels in 2007, domestic demand for refined fuels has increased approximately 29%, from 5.9 billion barrels to 7.6 billion barrels, over the same period.

High Utilization Rates

According to the EIA, between 1985 and 2006, refinery utilization increased from 78% to 89% and is approaching an effective maximum rate. The trend toward greater capacity utilization has been driven by several factors, including (1) no new major refineries have been built in the United States since 1976, (2) increasing demand for refined products, (3) many small refineries have been closed, and (4) permitting requirements have constrained refiners’ ability to increase capacity. Over the next 25 years, the EIA projects that utilization rates will remain high relative to historic levels, ranging from 89% to 94% of design capacity.

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Number of U.S. Refineries vs. Utilization

Source: EIA

Increased Crack Spreads

The fundamental drivers of profitability in the refining industry have improved since the late 1990s, which has resulted in a general widening between the prices for finished petroleum products and the costs of crude oil. By way of demonstrating the improved industry environment, the Gulf Coast 3/2/1 crack spread averaged $2.84 per barrel between 1996 and 1999 as compared to $4.41 per barrel from 2000 to 2003 and $12.66 per barrel for 2004 to the six months ended June 30, 2007.

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The following chart shows the Gulf Coast 3/2/1 crack spreads since 1996, together with the average margins per barrel stated above for the periods from 1996 to 1999, 2000 to 2003 and 2004 to YTD 2007. This data is presented for illustrative purposes and does not necessarily represent our average margins per barrel.

Gulf Coast 3/2/1 Crack Spreads

Source: Platt’s

Dependence on Imports

Due to lack of sufficient domestic refining capacity, the United States is a net petroleum product importer. Imports of petroleum products, largely from Northwest Europe and Asia, accounted for almost 15% of total U.S. consumption in 2004 and 18% for 2005. Increased imports generally occur primarily during periods when oil processing prices in the United States are materially higher than in Europe and Asia. Based on the strong fundamentals for the global refining industry, capital investments for refinery expansions and new refineries in international markets have increased in recent months. However, the competitive threat faced by domestic refiners is limited by increasingly stringent U.S. fuel specifications and increasing foreign demand for refined products, particularly for light transportation fuels.

Increased Crude Oil Quality Differentials

As the global economy has improved, world-wide crude oil demand has increased, and the incremental production from OPEC and other producers has tended to be heavy crude oils which are lower quality and more difficult to process compared to lighter crude oils like WTI. At the same time, many refiners have turned to lighter crude oils to maximize yields of light transportation fuels, resulting in increased supplies of heavy crude oils. These factors have caused the discounts for heavy crude oils, relative to the prices of light crude oils, to increase. The average differential between WTI crude oil and Maya, a heavy Mexican crude oil used in various refineries along the Gulf Coast, averaged $13.23 per barrel for 2006 compared to $13.67 per barrel in 2005 and $9.64 per barrel in 2004. Similarly, the average differential between WTI crude oil and Lloydminster, a blend of heavy Canadian crude oils, averaged $19.84 per barrel for 2006 compared to $20.49 per barrel in 2005 and $12.24 per barrel in 2004. We believe

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that greater worldwide supplies of lower-quality heavy crude oils and increased demand for light crude oils will continue to provide a cost advantage to refineries with complex configurations that are able to process the lower quality crude oils.

The Salt Lake refining complex has access to black wax and yellow wax crude oils from producers in the Uinta basin of Utah. These crude oils are lower quality compared to WTI and require relatively complex equipment to achieve conversion to high value light products like gasoline and diesel. The supply of these crude oils in the Salt Lake market currently exceeds the local demand. Wax crude oils cannot be transported via pipeline without blending with other feedstocks because they will begin to solidify at temperatures less than approximately 100 degrees Fahrenheit. The wax crude oils are shipped directly from the producers to the Salt Lake refining complex via insulated tanker trucks. Other refineries in the region currently process a very limited quantity of these crude oils due to the fact that they lack adequate catalytic cracking units. Due to the local market supply / demand dynamics and the logistical challenges associated with transporting the crude oil to other markets, these wax crude oils have been available to the Salt Lake refining complex at a significant discount relative to the price of WTI crude oil over the past 18 months.

Canadian Crude Oil

The Canadian Association of Petroleum Producers, or CAPP, and the Alberta Energy and Utilities Board, or AEUB, estimate there are 315 billion barrels of potential crude bitumen in place in the bitumen-soaked sands, or oil sands, of western Canada. Of that, the AEUB estimates 174 billion barrels of reserves are under active development areas. Recent technological advances and increased crude oil prices have substantially enhanced the feasibility of producing crude oil from these oil sands. CAPP estimates that production from these oil sands will reach approximately 3.5 million bpd by 2015. Numerous projects to transport this increased production to U.S. refineries are being developed. Additionally, Enbridge Energy Inc. and Canadian government officials are evaluating construction plans for a waterborne export facility on Canada’s West Coast that would facilitate significant incremental crude oil shipments to California and other international locations. Many U.S. refineries have recently announced projects that will enable them to refine Canadian crude oils.

Refineries in the Salt Lake region currently receive heavy Canadian crude oil via Kinder Morgan’s Express pipeline connecting to Plains All American Pipeline’s Salt Lake City Core system. The Salt Lake City Core system is an interstate and intrastate common carrier crude oil pipeline system that consists of 955 miles of trunk pipelines with a combined throughput capacity of approximately 114,000 bpd. Plains All American Pipeline and Holly Energy Partners are also collaborating on a new 95-mile intrastate pipeline system, currently being constructed by Plains, for the shipment of up to 120,000 barrels per day of crude oil from Wyoming and Utah which is currently flowing on Plains’ Rocky Mountain Pipeline into the Salt Lake City area. The pipeline would be owned by a new joint venture company which would be owned 75.0% by Plains and 25.0% by Holly Energy. The pipeline is expected to become fully operational in the first quarter of 2008. Upon completion of this pipeline, refiners in the region will have significant access to Canadian crude oil. We expect that the increasing supply of Canadian crude oils within the region will likely support the wide quality cost differentials relative to WTI of lower quality indigenous crude oils produced in the Rocky Mountain region such as black wax and yellow wax.

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Rocky Mountain Region Refining Margins

A refinery’s location has an impact on its refining margins because regional infrastructure and fuel specifications impact the availability and price of crude oils and refined products. The map below shows the five PADDs in the United States, which have historically experienced varying levels of refining margins due to regional market conditions.

U.S. Petroleum Administration for Defense Districts (PADDs)

Source: EIA

Approximately 49.0% of domestic refining capacity is located in PADD III (Gulf Coast). The available supply of finished petroleum products significantly exceeds the demand within this region and it is therefore a net exporter of finished petroleum products. As a consequence, absent any significant disruptions (e.g., hurricanes) that impact supply, PADD III refining margins are usually the lowest compared to other regions of the US. Refining margins in PADD I (East Coast) are typically higher because this region is a net importer of finished petroleum products and the premiums relative to PADD III refining margins are due to transportation / logistical costs associated with importing products into this market via pipeline from PADD III as well as waterborne from international sources (Eastern Canada, Europe, Middle East and Latin America). PADD II (Midwest) has higher margins due to transportation costs of importing product via pipeline from PADD III, despite having a relatively balanced supply / demand dynamic.

PADD IV (Rocky Mountain) is product short compared to other regions of the domestic market. Due to the lack of adequate logistical infrastructure (pipelines) to efficiently move finished petroleum products from PADD III or PADD V (West Coast) into this region, PADD IV usually experiences some of the highest refining margins in the US. Likewise, PADD V, though a net exporter, lacks adequate logistical infrastructure to efficiently move finished petroleum products. Furthermore, the region has the most stringent product specifications. For these reasons, PADD V also experiences higher refining margins than other regions of the United States.

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The following chart shows the benchmark crack spreads by region for the periods presented below. The regional 3/2/1 crack spread represents the price per barrel of a local product slate comprised of two parts gasoline and one part diesel less the price per barrel of a benchmark crude oil for that region. The PADD I crack spreads were calculated using the market prices of New York Harbor 87 octane unleaded gasoline, New York Harbor low sulfur diesel and New York Harbor Brent crude oil. The PADD II crack spreads were calculated using the market prices of Chicago Hub unleaded gasoline, Chicago Hub low sulfur diesel and WTI crude oil. The PADD III crack spreads were calculated using the market prices of Gulf Coast 87 octane unleaded gasoline, Gulf Coast low sulfur diesel and WTI crude oil. The PADD IV crack spreads were calculated using the market prices of Salt Lake City unleaded gasoline, ultra low sulfur diesel and WTI crude oil. The PADD V crack spreads were calculated using the market prices of LA CARBOB 87 unleaded gasoline, LA CARB ultra low sulfur diesel and ANS crude oil. This data is presented for illustrative purposes and does not necessarily represent spreads or margins realized by our Salt Lake refining complex.

Crack Spreads by Region

Data calculated based upon information obtained from Platt’s

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The following table shows the historical 3/2/1 crack spread at the Salt Lake refining complex relative to the Gulf Coast crack spread over the corresponding period. The refining crack spread was at a $13.05 premium to the Gulf Coast crack spread during the six month period ending July 31, 2007. The corresponding premiums for the fiscal years ending January 31, 2005, 2006 and 2007 were $4.78, $2.91 and $10.01, respectively.

	Fiscal Years Ended January 31,									Six Months Ended July 31,
	2005			2006			2007			2007
	(per barrel)
Gulf Coast 3/2/1 Crack Spread	$	6.94		$	11.66		$	12.02		$	20.06
Crude quality differential vs. WTI		(0.71	)		(1.39	)		2.18			5.56
Product pricing differential:
Salt Lake City market vs. Gulf Coast		6.52			5.32			9.78			8.65
Big West facility vs. Salt Lake City market		(1.02	)		(1.02	)		(1.95	)		(1.16	)
Salt Lake refining complex vs. Gulf Coast	$	5.50		$	4.30		$	7.83		$	7.49
Salt Lake refining complex 3/2/1 Crack Spread	$	11.72		$	14.57		$	22.03		$	33.11
Premium to Gulf Coast 3/2/1 Crack Spread	$	4.78		$	2.91		$	10.01		$	13.05

The following table shows the historical 3/2/1 crack spread at the Bakersfield refining complex relative to the Gulf Coast crack spread over the corresponding period. The refining crack spread was at a $17.63 premium to the Gulf Coast crack spread during the six month period ending July 31, 2007. The corresponding premiums for the eleven months ended January 31, 2006 and the fiscal year ended January 31, 2007 were $15.36 and $17.15, respectively.

	Eleven Months Ended January 31,		Fiscal Year Ended January 31,		Six Months Ended July 31,
	2006(1)		2007		2007
	(per barrel)
Gulf Coast 3/2/1 Crack Spread	$	12.20	$	12.02	$	20.06
Crude quality differential vs. WTI		7.62		5.63		4.93
Product pricing differential
Los Angeles market vs. Gulf Coast		6.50		8.55		11.46
Bakersfield refining complex vs. Los Angeles market		1.24		2.97		1.24
Bakersfield refining complex vs. Gulf Coast	$	7.74	$	11.52	$	12.70
Bakersfield refining complex 3/2/1 Crack Spread	$	27.56	$	29.17	$	37.69
Premium to Gulf Coast 3/2/1 Crack Spread	$	15.36	$	17.15	$	17.63

(1) Reflects the eleven month period that Big West owned the Bakersfield refining complex.

It may be noted that the 3/2/1 premiums at the Salt Lake refining complex and the Bakersfield refining complex are largely due to the typically superior product (gasoline, diesel) pricing in those markets relative to the Gulf Coast. In the past 18 months, the Salt Lake refining complex’s ability to process discounted crude oils like black wax and yellow wax has contributed to the premium at the Salt Lake refining complex.

Salt Lake Refined Products Market

The refined petroleum products market in Utah and southern Idaho comprises approximately 1.3% of the total U.S. market due to the low population in these states. The percentage population growth in Utah and in the Rocky Mountains has been about twice the percentage population growth level in the United States since 1990. Therefore, the Rocky Mountains and the Salt Lake refined products markets have grown at about twice the

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percentage rate of that for the United States, since 1990. The refinery capacities in these regions have increased by capacity creep and by adding several expansion projects to keep up with increasing demands over this period.

Petroleum products received into PADD IV from other PADD regions have been relatively small, averaging 15% to 20% of demand over the period from 1995-2006. Utah and southern Idaho are relatively isolated and are supplied by the five Salt Lake refineries, plus one petroleum products pipeline, the 70,000 bpd Pioneer pipeline operated by ConocoPhillips. The Pioneer pipeline receives products from the Sinclair refineries in Wyoming and the ConocoPhillips and ExxonMobil refineries in Billings, Montana. Utah also receives small volumes of petroleum products by truck from New Mexico and Nevada into sparsely populated Southern Utah. The five Salt Lake refineries supply most of Utah and southern Idaho and can supply eastern Oregon and southeastern Washington by the Chevron products pipeline from Salt Lake City.

The following map shows the crude oil supply to and the crude oil and refined product pipeline pipelines serving the Salt Lake refining complex:

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BUSINESS

Partnership Overview

We are an independent refiner of petroleum products operating in North Salt Lake, Utah. We were formed on December 3, 2007 by Big West Oil, LLC, or Big West, a subsidiary of Flying J Inc., or Flying J. Our assets consist of a 35.0% interest in OPCO, which will own the milli-second catalytic cracking unit and alkylation unit at the Salt Lake refining complex. We will control OPCO through our ownership of its general partner. Big West will own the remaining 65.0% interest in OPCO, our general partner and the other process units at the Salt Lake refining complex.

OPCO’s assets will consist of a milli-second catalytic cracking unit, or MSCC unit, and an alkylation unit. These two units enable the Salt Lake refining complex to process black wax and yellow wax crude oils, providing a cost advantage that has recently resulted in favorable refining margins for Big West. In connection with this offering, OPCO will enter into a 25-year refining agreement with Big West. Pursuant to the refining agreement, Big West will agree to throughput during each semi-annual period a minimum volume of gas oils from the distillation unit in the Big West facility to OPCO’s MSCC unit in return for a per barrel refining fee. Similarly, Big West will agree to offtake during each semi-annual period a minimum volume of alkylate processed at OPCO’s alkylation unit in return for a per barrel refining fee. Big West will be obligated to pay the minimum refining fees whether or not it utilizes OPCO’s units. Because OPCO will not own any of the gas oils or alkylate, and because the refining fees will not be tied to commodity prices of either feedstocks or refined products, we believe the refining agreement will substantially reduce our direct exposure to commodity price volatility. In addition, in the event that OPCO’s operating costs under its services agreements with Big West increase for any given year during the term of the refining agreement, the refining fees payable by Big West to OPCO for the following year will be increased permanently by the amount of the operating cost increase for the prior year, which will assist OPCO in maintaining its net operating profit.

OPCO will own and operate the following process units:

• Milli-second catalytic cracking unit. The MSCC unit catalytically breaks down complex, lower value gas oils fed to it by the Salt Lake refining complex’s distillation unit into lighter, higher value liquid products such as gasoline, diesel and other higher value hydrocarbon products. The MSCC unit was installed in 2002 and uses innovative technology that increases the efficiency of catalytic reactions. The MSCC unit has a throughput capacity of 11,500 barrels per day, or bpd. The MSCC unit underwent its most recent turnaround in April 2006, which lasted 27 days. We expect the next turnaround for this unit to occur in 2011.

• Alkylation unit. The alkylation unit combines lower value, low molecular weight olefins such as propylene, butylene or pentene with isobutane in the presence of a hydrofluoric acid catalyst to produce higher value, high octane gasoline blending stock called alkylate. Alkylate is a key blendstock in the production of high specification reformulated gasoline. The low molecular weight olefins and a portion of the isobutane used in the alkylation process are generated as a by-product of the MSCC unit. Additional isobutane is produced in the butamer unit at the Salt Lake refining complex or supplied by third parties. The alkylation unit has an alkylate offtake capacity of 2,800 bpd. The alkylation unit underwent its most recent turnaround in April 2006, which lasted 29 days. We expect the next turnaround for this unit to occur in 2011.

Immediately following the closing of the offering, Big West will be OPCO’s only customer and account for all of OPCO’s sales. We expect OPCO to continue to derive at least a substantial majority, if not all, of its revenues from Big West or its affiliates for the foreseeable future.

The Salt Lake refining complex was originally constructed in 1948 and, since acquiring the complex in 1985, Big West has significantly upgraded the refining complex’s processing capability and expanded its average

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daily crude oil throughput from approximately 18,000 bpd to approximately 31,000 bpd. The Salt Lake refining complex’s crude oil inputs consist of black wax crude oil and yellow wax crude oil from the nearby Uinta basin in northeastern Utah, light sweet crude oil (condensate) from Southwest Wyoming, or SWWS, and synthetic crude oil, or syncrude, from Canada. Black wax and yellow wax crude oils and SWWS have generally been less expensive than other benchmark light crude oils such as West Texas Intermediate (WTI), and produce a high percentage of light, high-value refined products.

Approximately 90% of the Salt Lake refining complex’s production during the fiscal year ended January 31, 2007 was higher-value products such as gasoline and diesel, and the remainder of production was marketable by-products. Big West sells the refined products from the Salt Lake refining complex in Utah, Idaho, Nevada, Wyoming, Colorado and Oregon. The Rocky Mountain market historically has had among the highest refining margins between prices of refined products and crude oil feedstocks in the United States.

Our Relationship with Flying J and Big West

We are currently an indirect, wholly owned subsidiary of Flying J, a privately held integrated petroleum firm engaged in the exploration and production, refining, transportation and wholesale and retail marketing of petroleum products, as well as the provision of financial, insurance and technology products and services. Flying J owns and operates travel plazas, convenience stores and truck service centers throughout the United States and Canada and provides financial, insurance, telecommunication, transaction data capture and systems integration services to its customer base. We believe that Flying J is the largest retail diesel fuel marketer by volume in North America, marketing in excess of 425,000 bpd of refined petroleum products and operating a fleet of approximately 900 tanker trucks. Flying J purchases more gasoline and diesel products in the Salt Lake market than the Salt Lake refining complex produces. We expect Flying J will continue to be one of the primary purchasers from Big West of the refined products at the Salt Lake refining complex, but Flying J will be under no contractual obligation to purchase any refined products from Big West. Approximately $253.1 million, $382.5 million, $405.7 million and $211.5 million of Big West’s total net sales of refined products from the Salt Lake refining complex were to Flying J and its affiliates for the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2007, respectively. We plan to leverage the expertise, relationships and reputation of Flying J to pursue growth opportunities in the refining industry and other energy industries.

Following the completion of this offering, Big West will own our general partner and all of our subordinated units and 65.0% of the limited partner interests in OPCO; and our general partner will own 1,218,750 common units, a 2.0% general partner interest in us and our incentive distribution rights.

We may have the opportunity to make acquisitions of assets from Big West and Flying J in the future, although Big West and Flying J will be under no contractual obligation to offer or sell any assets to us. At the closing of this offering, Big West will continue to own the remaining 65.0% limited partner interest in OPCO, the remaining portion of the Salt Lake refining complex and a refining complex in Bakersfield, California with a current crude oil throughput capacity of approximately 70,000 bpd. Big West has invested in the past and intends to continue to invest significant capital to upgrade the Bakersfield refining complex, with the completion of the upgrade project targeted for the fourth quarter of 2009. In addition, an affiliate of Flying J owns the 694-mile Longhorn refined products pipeline extending from a terminal near the Houston, Texas Ship Terminal to terminals in El Paso, Texas, where an affiliate of Flying J also owns a terminal with over one million barrels of storage. Additionally, the Flying J affiliate also owns 150,000 barrels of tank storage in Crane, Texas from which refined products can be dispensed through a third party terminal in Odessa, Texas. We believe these assets will be potentially suitable over time for possible purchase by our partnership. We also believe that our ability to consummate acquisitions of additional refining or other energy assets will be enhanced by our access to Big West’s and Flying J’s expertise and commercial relationships. Furthermore, we may pursue acquisitions jointly with Big West and Flying J.

While we believe Flying J and Big West will have an incentive to contribute or sell additional assets to us and to allow us to purchase additional refining or other energy assets suitable for us from third parties, neither

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has any legal or contractual obligation to do so. Flying J and Big West face few limitations on their ability to compete with us and may elect to acquire or dispose of assets that would be attractive to us in the future, including the assets they will retain at the closing of this offering, without offering us the opportunity to purchase those assets. Even if we are offered the opportunity to purchase assets in the future from Flying J, Big West or third parties, we may be unable to agree on acceptable terms of purchase or to obtain approvals or financing for the acquisition. Further, because Big West controls our general partner, we cannot pursue acquisitions unless Big West causes us to do so. If Flying J or Big West declines to present us with, or successfully competes against us for, attractive acquisition opportunities, we may not be able to acquire new assets, which would materially adversely affect our ability to grow.

Competitive Strengths

We believe the following competitive strengths will assist us in achieving our primary business objective of maintaining and increasing the amount of cash available for distribution per unit:

Stable Cash Flows from Refining Agreement

OPCO’s cash flow is relatively stable because it derives all of its revenues from per barrel refining fees under the 25-year refining agreement with Big West. The fee structure of the refining agreement helps reduce our direct exposure to commodity price volatility for feedstocks and refined products. In addition, the refining agreement specifies that Big West must pay for a minimum volume of throughput for the MSCC unit and minimum volume of offtake from the alkylation unit, whether or not such volumes are actually processed. We believe that this revenue stream, coupled with Big West’s obligation to permanently increase refining fees paid to OPCO in subsequent years for all operating expenses in prior years in excess of a baseline minimum amount and the length of the refining agreement, will provide us with a long-term, stable source of cash flows.

Unique Operational Relationship with Flying J

OPCO’s assets are integrated and optimized to function with the Big West facility, and we believe Big West will continue to rely on OPCO’s units for its catalytic cracking and alkylation needs. OPCO’s relationship with Big West and Flying J provides OPCO with a stable source of feedstock and a reliable outlet for the refined petroleum products OPCO produces. Flying J is the largest retail diesel fuel marketer by volume in North America and purchases more gasoline and diesel products in the Salt Lake market than the Salt Lake refining complex produces. We expect Flying J will continue to be one of the primary purchasers from Big West of the refined products from the Salt Lake refining complex.

Operations in Attractive Geographic Market

The Salt Lake refining complex is located in the Rocky Mountain region of the United States, which we believe is one of the most favorable areas in the United States in which to operate a refinery. This market features access to lower cost black wax and yellow wax crude oils, condensate from natural gas production in the Rocky Mountain region (also called SWWS) and Canadian crude oils, limited refining capacity, above-average growth in demand for refined products and a lack of pipeline capacity that limits the import of refined products to the Rocky Mountain region from the West Coast and Gulf Coast regions of the United States. As a result of these dynamics, the margin between refined product prices and the price of crude oil feedstocks, or the “crack spread,” in this region historically has generally been one of the highest in the United States. In order to capture the growth in this region, Big West expanded the capacity of the MSCC unit in April 2006 and the alkylation unit in November 2006.

Modern and Efficient Process Units

OPCO’s units are modern, efficient and well maintained. The MSCC unit was designed and installed in 2002 using technology tailored to process lower cost indigenous crude oils such as black wax and yellow wax.

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The MSCC unit can process these crude oils more efficiently than conventional fluid catalytic cracking units. The throughput capacity of the MSCC unit was expanded from approximately 10,000 bpd to approximately 11,500 bpd during its turnaround in April 2006. In November 2006, Big West increased the alkylate production capacity of the alkylation unit from approximately 2,000 bpd to approximately 2,800 bpd.

Experienced Management

Big West’s management has extensive experience operating refining assets and marketing refined products. Through our shared services and master services agreements with Big West, we will benefit from the knowledge, expertise and significant pool of management talent of Big West.

Business Strategies

Our primary business objective is to maintain and increase the amount of cash available for distribution per unit. Our principal strategies to achieve this objective are to:

Purchase Assets from Big West and Flying J

At the closing of this offering, Big West will own a 65.0% limited partner interest in OPCO, the remaining portion of the Salt Lake refining complex and a refining complex in Bakersfield, California. A Flying J affiliate will continue to own the Longhorn refined products pipeline, as well as related storage assets. We believe these assets will be potentially suitable over time for possible purchase by our partnership.

Purchase Assets from Third Parties

We will also seek to grow through accretive acquisitions of third party refining and other energy assets suitable for our partnership. Because we are not subject to federal income taxation at the entity level, we believe that we will have a lower cost of capital than our corporate competitors that will enhance our ability to make accretive acquisitions. We also believe that our ability to consummate these acquisitions will be enhanced by our access to Big West’s and Flying J’s expertise and commercial relationships. Furthermore, we may pursue acquisitions jointly with Big West and Flying J.

Salt Lake Refining Complex Overview

The Salt Lake refining complex is located on approximately 150 acres in North Salt Lake, Utah, in an industrial area approximately 8 miles north of downtown Salt Lake City. The Salt Lake refining complex was originally constructed in 1948 and was purchased by Flying J from Husky Oil in 1985. It has been expanded several times, most recently in April 2006 to its current crude oil throughput capacity of approximately 31,000 bpd. The refinery is designed to process light, low sulfur crude oils, including black wax and yellow wax crude oils, which cost less and yield better refining margins than other light crude oils.

The Salt Lake refining complex is a fully integrated refinery and utilizes the following major processes during production: fractional distillation (crude unit), catalytic cracking, catalytic reforming, HF alkylation, diesel hydrotreating, naphtha hydrotreating, C5/C6 isomerization, butamer and gas saturates processing, fuel gas scrubbing and sulfur recovery.

Other infrastructure supporting the Salt Lake refining complex operations includes truck unloading lanes for black and yellow wax crude oils, approximately 595,000 barrels of feedstock tankage, three truck loading lanes for offtake of refined products, railcar loading spots for blendstocks and intermediaries and approximately 454,000 barrels of refined products tankage. The Salt Lake refining complex has access to two common carrier crude oil pipelines and a common carrier refined products pipeline. The Salt Lake refining complex receives crude oil by pipeline and by truck; the wax crudes are delivered by truck, while the other crudes are pipelined.

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Most of the gasoline and diesel produced at the refining complex is trucked over its truck racks for distribution in the Rocky Mountain region. The remainder is shipped by pipeline to southern Idaho.

In April 2006, Big West completed a turnaround at the Salt Lake refining complex. We believe the turnaround will permit Big West and OPCO to operate the Salt Lake refining complex without significant planned maintenance shutdowns for the next five years. In connection with this turnaround, Big West completed maintenance on the MSCC unit and upgraded the alkylation unit. Following the turnaround, Big West increased the percentage of black wax crude oil that Big West is able to refine at the Salt Lake refining complex, thereby reducing its aggregate cost of crude oil feedstocks.

Refining Process

The flow diagram above displays the process flow of the Salt Lake refining complex. The diagram shows the crude inputs on the far left, refining units in the center, and products on the far right. The shaded refining units represent the process units that will be contributed to OPCO: the MSCC unit and the HF alkylation unit.

OPCO Process Units

The following are simplified descriptions of the process units included in OPCO’s units:

Milli-Second Catalytic Cracking (MSCC) Unit

The MSCC unit consists of two interconnected zones: the reaction zone and the regeneration zone. In the reaction zone, gas oils are cracked into lighter, more valuable petroleum products at high temperature and moderate pressure in the presence of a finely divided silica / alumina based catalyst. During the cracking process, an inert carbon by-product, or ‘coke’, is produced and deposited in the catalyst which reduces the effectiveness of the catalyst. This catalyst flows continuously through the regeneration zone where the coke is burned off the catalyst surface and the catalyst is returned to the reaction zone. The reactor and the regenerator operate together as an integrated unit.

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The MSCC unit typically processes gas oils from the Salt Lake refining complex’s crude unit. This unit could also be reconfigured to process crude oil directly. The products from the unit include gasoline, light cycle oil, olefins which serve as alkylation unit feedstock, and fuel oil.

The MSCC unit was constructed and placed in operation in 2002. This unit, with a throughput capacity of 11,500 bpd, uses innovative technology from UOP LLC, a wholly owned subsidiary of Honeywell International, Inc. The design of our MSCC unit was tailored to enhance the ability of the Salt Lake refining complex to process lower cost indigenous crudes such as black wax and yellow wax. The cracking reaction in an MSCC is carefully controlled to maximize the production of higher value, liquid products such as gasoline and diesel.

Hydrofluoric Acid (HF) Alkylation Unit

The hydrofluoric acid alkylation process combines low molecular weight olefins (such as propylene, butylene, or pentene) from the MSCC unit with isobutane in the presence of hydrofluoric acid catalyst to yield a product in the gasoline boiling range. This product is called alkylate. In this process, hydrocarbons which are too light and too volatile to use in gasoline are chemically combined or joined together to yield a gasoline-boiling-range material. Alkylate is used in motor fuel blending. Alkylate has ideal gasoline properties, such as high research and motor octane numbers, low vapor pressure, and no aromatics, olefins, or sulfur. Alkylation is a key process that allows refiners to produce the gasoline blending components for reformulated gasoline and other grades capable of meeting the increasingly stringent gasoline specifications across North America. The alkylation unit has alkylate production capacity of 2,800 bpd.

The olefin charge to the alkylation unit consists of propylene and butylenes produced by the MSCC unit. Part of the isobutane required for the process is contained in the olefin feed stream, and make-up isobutane supplies the remainder. Make-up isobutane is produced in the butamer unit or supplied from outside sources.

Hydrofluoric acid (HF) acts as a catalyst for the reaction, which combines olefins with isobutane. The hydrofluoric acid is continuously recycled / recirculated through the alkylation unit.

Big West Facility Units

The following are descriptions of the process units to be retained by Big West as part of the Big West facility. Neither we nor OPCO will own or operate any of the following units at the closing of this offering:

Crude Distillation Unit

Atmospheric distillation is the first step to processing crude oil. The throughput capacity of the Big West facility’s crude unit is 31,000 bpd. The crude oil is transferred from storage tanks via pipeline and is heated by passing it through heat exchangers, which use heat from product streams that would otherwise be wasted, and/or gas fired heaters. The crude oil then passes through the de-salters, where salt water and other undesirables are removed using water. In order to elevate the temperature of the crude necessary to initiate fractionation, the crude is passed once again through gas fired heaters. After being heated, the feedstock enters the atmospheric distillation column. A temperature gradient is maintained across the column, allowing the different compounds to separate. Collection trays are strategically placed within the column such that the individual liquids can be removed at their respective levels. All of the products from this process are sent to other units for additional refining. For example, gas oils exiting the lower portion of the crude distillation unit are sent to the MSCC unit for further cracking into higher value, lighter products such as gasoline, diesel, olefins which serve as alkylation unit feedstock, and fuel oil.

Amine Unit

The amine unit is an absorption device and is used to remove corrosive hydrogen sulfide, or H2S, from hydrocarbon streams (also known as sour fuel gas). A mixture of methyl diethanolamine (MDEA) and water are

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used to effect the H2S absorption in the amine contactor section of the amine unit. The treated hydrocarbon stream exiting the contactor section, also called sweet gas, is used as fuel in the refinery. The spent absorbent (H2S/MDEA) mixture is then sent to the regenerator section of the amine unit. The MDEA is recycled to the contactor section and H2S is sent to the sulfur recovery unit.

Sulfur Recovery Unit

The sulfur recovery unit converts hazardous gases into sulfur, an easily disposable and possibly saleable product. The unit receives acid gas from the amine absorber and regenerator. The gas consists mainly of H2S and some process water (otherwise known as sour water) that has absorbed H2S and/or ammonia, or NH3. Sour water strippers are used to remove the H2S and NH3. This is then fed into a thermal and then a catalytic reactor to convert the H2S into elemental sulfur. The gases produced in the catalytic reactor are sent to the tail gas incinerator.

Hydrodesulfurization (HDS) Unit

This unit purifies and reduces the sulfur content of diesel fuel to achieve compliance with transportation fuel quality specifications. It receives unfinished distillates from the crude unit and MSCC unit. The unfinished distillates are mixed, heated and charged to a reactor. After exiting the reactor, the stream enters a high pressure and then a low-pressure separator to remove sour fuel gas. The stream continues further into a distillation column to separate naphtha and the final product, a sweet or ultra low sulfur diesel fuel.

Reformer Unit (Including the Naphtha Hydrotreater and C5/C6 Isomerization Unit)

The throughput capacity of the reformer unit is 7,700 bpd. The reformer is used to convert low octane naphtha into a high octane reformate. Naphtha is heated and charged to a unifier reactor and then a unifier stripper to remove entrained H2S. The H2S is sent to the amine and sulfur recovery units, while the stripped naphtha is sent to a fractionator. The fractionator is used to separate straight run gas from the naphtha. The straight run gas is sent to the C5/C6 isomerization unit (reactor) to convert the gas into higher value and higher-octane isopentane and hexane. The naphtha is sent to three reactors operated in stacks. The product stream from the reactors is mixed with the product stream from the C5/C6 isomerization unit and then charged to a stabilizer. The stabilizer removes additional entrained H2S and controls the vapor pressure of the reformate product.

Butane Isomerization Unit and Saturates Gas Plant

The butane isomerization unit and the saturates gas plant convert normal butane into isobutane to be used in the alkylation unit. Isobutane is a primary feedstock for producing motor fuel alkylate. Refineries seldom have enough isobutane to maintain production in the alkylation unit, and therefore more isobutane needs to be either purchased or produced. Normal butane is purchased and converted to isobutane because it is mostly cheaper than isobutane as well as purchased field butane. The Salt Lake refining complex produces adequate isobutane to meet the needs of its alkylation unit and is a net seller of excess isobutane.

Historical Throughput and Production

Salt Lake Refining Complex

At the Salt Lake refining complex, approximately 90% of production during the fiscal year ended January 31, 2007 was higher-value products such as gasoline and low-sulfur diesel. From February 1, 2005 through July 31, 2007, Big West increased the average daily total throughput of the Salt Lake refining complex from 29,520 bpd during the fiscal year ended January 31, 2005 to 30,939 bpd during the six months ended July 31, 2007.

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The following table provides information concerning the historical throughput and production of the Salt Lake refining complex:

	Fiscal Year Ended January 31,						Six Months Ended July 31,
	2005		2006		2007(1)		2006(1)		2007
	Bpd	%	Bpd	%	Bpd	%	Bpd	%	Bpd	%
Refinery crude throughput:
Black wax	7,631	25.9	8,509	26.6	8,137	26.7	7,342	25.2	11,418	36.9
Other light crudes	16,309	55.2	19,780	61.8	18,592	61.1	18,758	64.3	16,407	53.0
Total crude oil	23,940	81.1	28,288	88.3	26,729	87.8	26,100	89.5	27,825	89.9
Intermediate and blendstocks	5,880	18.9	3,739	11.7	3,697	12.2	3,048	10.5	3,114	10.1
Total refinery throughput	29,520	100.0	32,027	100.0	30,426	100.0	29,148	100.0	30,939	100.0
Refinery products:
Light products:
Gasoline	15,560	52.7	16,848	52.6	17,514	57.6	15,695	53.8	19,375	62.6
Diesel	10,150	34.4	10,271	32.1	8,685	28.5	8,753	30.0	8,857	28.6
LPG	268	0.9	559	1.7	408	1.3	481	1.7	315	1.0
Total light products	25,978	88.0	27,679	86.4	26,607	87.4	24,929	85.5	28,546	92.2
Unfinished wax	2,228	7.5	2,480	7.7	1,522	5.0	1,918	6.6	212	0.7
Fuel oil residual	531	1.8	836	2.6	987	3.2	909	3.1	1,004	3.2
Total refined products	28,737	97.3	30,995	96.7	29,116	95.6	27,756	95.2	29,762	96.1

OPCO Process Units. The following table provides information concerning the historical throughput and production of the MSCC unit and the alkylation unit comprising OPCO’s units:

	Fiscal Year Ended January 31,			Six Months July 31,
	2005	2006	2007(1)	2006(1)	2007
MSCC unit throughput (bpd)	9,634	9,452	10,113	9,027	11,304
Alkylation unit alkylate offtake (bpd)	2,109	2,067	2,040	1,672	2,661

(1) Reflects a 27 day turnaround on the MSCC unit and a 29 day turnaround on the alkylation unit during this period.

Salt Lake Raw Material Supply

The crude oil supply for the Salt Lake refining complex consists of black wax and yellow wax crude oils, SWWS crude oil and syncrude. Big West purchases its crude oil feedstocks for its Salt Lake refining complex from approximately38 suppliers pursuant to contracts with terms of various duration.

Black and Yellow Wax Crude Oils. The Salt Lake refining complex obtains its supply of black and yellow wax crude oils from producers in the Uinta basin of Utah. These wax crude oils are shipped directly from the producers to our Salt Lake refining complex via insulated tanker trucks. Wax crude oils cannot be transported via pipeline without blending with other feedstocks because they will begin to solidify at temperatures less than approximately 100 degrees Fahrenheit. We believe that the Salt Lake refining complex’s access to Flying J insulated tanker trucks gives it a competitive advantage over other refineries in the Salt Lake City area that do not have a single, reliable transportation provider. Black wax and yellow wax crude oils accounted for approximately 30.4% and 14.7%, respectively, of the Salt Lake refining complex’s crude oil throughput during the year ended January 31, 2007.

Syncrude. The Salt Lake refining complex obtains its supply of synthetic crude oils, or syncrude, from producers in Canada via Kinder Morgan’s Express pipeline connecting to Plains All American Pipeline’s Salt

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Lake City Core System. Syncrude accounted for approximately 18.7% of the Salt Lake refining complex’s crude oil throughput during the fiscal year ended January 31, 2007.

Other Light Crude Oil. The Salt Lake refining complex obtains a majority of its supply of SWWS crude oils from a number of producers in Wyoming. SWWS crude oil, a byproduct (condensate) of the production of natural gas in the Rocky Mountain region, is transported from producers via pipelines or Flying J tanker trucks and then injected into common carrier pipelines for delivery to the Salt Lake refining complex. SWWS crude oils accounted for approximately 36.3% of the Salt Lake refining complex’s crude oil throughput during the fiscal year ended January 31, 2007.

Other. The Salt Lake refining complex also purchases butane and natural gasoline to supply the Salt Lake refining complex. These other feedstocks are purchased from other petroleum companies and delivered to the Salt Lake refining complex by truck or railcar. The Salt Lake refining complex is currently purchasing its MSCC catalyst supply pursuant to monthly contracts from BASF, one of three catalyst suppliers in the United States. The Salt Lake refining complex utilizes approximately two tons of catalyst per day.

Salt Lake Refining Complex Production

Transportation Fuels. Gasoline and diesel accounted for approximately 57.6% and 28.5%, respectively, of the Salt Lake refining complex’s production during the fiscal year ended January 31, 2007 and approximately 62.6% and 28.6%, respectively, for the six months ended July 31, 2007. The Salt Lake refining complex produces various grades of gasoline, ranging from 85 octane regular unleaded to 91 octane premium unleaded. All of the transportation fuels produced at the Salt Lake refining complex meet current EPA sulfur specifications.

The primary markets for the Salt Lake refining complex’s refined products are Utah and Southern Idaho. Big West also sells refined products from the Salt Lake refining complex in Wyoming, Colorado, Nevada and Oregon.

Big West sells a majority of the gasoline and diesel fuel produced at the Salt Lake refining complex from the truck rack located at the refining complex. The truck rack has three loading lanes, which are currently used for gasoline and diesel. All of the lanes are fully automated and electronically controlled. Remaining volumes of gasoline and diesel fuel are distributed through the Chevron pipeline system to markets in Southern Idaho or transported by truck to the other markets Big West serves.

Big West’s primary customer for diesel fuel produced at the Salt Lake refining complex is Flying J.For the fiscal year ended January 31, 2007 and the six months ended July 31, 2007, Flying J and its affiliates accounted for approximately 78% and 75%, respectively, of the Salt Lake refining complex’s diesel sales. Big West’s primary customers for gasoline produced at the Salt Lake refining complex include a variety of retail, commercial and industrial customers. For the fiscal year ended January 31, 2007 and the six months ended July 31, 2007, Flying J and its affiliates accounted for approximately 30.0% and 27.0%, respectively, of the Salt Lake refining complex’s gasoline sales. Big West typically sells Salt Lake refined products pursuant to contracts with initial terms of six-months or one year and monthly terms thereafter. Product pricing is based on the OPIS rack price or Big West rack price. Contracts are terminable by either party after the initial term upon 60 days’ written notice. As of July 31, 2007, Big West had six contracts for sales of refined products with six customers.

Big West and Flying J also purchase additional refined products from other refineries to supplement supply to the Salt Lake refining complex customers. These products are the same grade as the products that are currently produced at the Salt Lake refining complex.

Unfinished Wax. Unfinished wax accounted for approximately 0.7% of the Salt Lake refining complex’s production during the six months ended July 31, 2007. Big West sold its unfinished wax primarily to International Group Inc., a wax product manufacturer. In March 2007, Big West ceased producing unfinished wax.

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Competition

Petroleum refining is highly competitive. The Salt Lake refining complex is one of five refineries located in Utah. We estimate that the four refineries that compete with the Salt Lake refining complex have a combined capacity to process approximately 143,500 bpd of crude oil. These five refineries collectively supply a substantial majority of the gasoline and distillate products consumed in Utah and southern Idaho, with the balance provided by refineries in surrounding states. The Salt Lake refining complex primarily competes with the Salt Lake refineries owned by Tesoro Corporation, Chevron Corporation, Holly Corporation and Silver Eagle. The Salt Lake refining complex also competes with Sinclair Oil Corporation’s refineries in Wyoming and the ExxonMobil and Conoco Phillips’ refineries in Billings, Montana.

Set forth below is certain information relating to the refineries in the Salt Lake City area.

Salt Lake City Area Refineries

Company	Crude Capacity (bpd)	Catalytic Cracking Capacity (bpd)	Alkylate Production Capacity (bpd)	Catalytic Reforming Capacity (bpd)	Nelson Complexity
Tesoro	60,000	23,000	6,000	12,000	6.3
Chevron	45,000	13,000	4,500	7,000	8.3
Big West	31,000	11,500	2,800	7,700	9.0
Holly	26,000	7,680	2,400	7,200	8.7
Silver Eagle Refining	12,500	N/A	N/A	2,200	4.2
Total	174,500	55,180	15,600	36,100

The principal competitive factors affecting the Salt Lake refining complex are costs of crude oil and other feedstocks, refinery efficiency, refinery product mix and costs of product distribution and transportation. The Salt Lake refining complex has a higher than average percentage of catalytic cracking and reforming capacity to crude capacity which allows it to process a higher percentage of black wax crude oil and condensate (SWWS) compared to other refineries in the region. In addition, it is the only one of the Salt Lake area refineries with a distillate dewaxing unit, which allows it to process a higher percentage of black wax crude oil than its competitors.

Agreements with Affiliates

In conjunction with this offering, we and OPCO have entered into a number of agreements with Big West and its affiliates, which will become effective upon the completion of this offering. The following discussion of the agreements with Big West is qualified in its entirety by reference to the forms of such agreements, which have been filed as exhibits to the registration statement of which this prospectus forms a part. The terms of these agreements present conflicts between our interests and the interests of Big West, and the terms may be less favorable to us than terms we could have obtained from an unaffiliated third party. We and OPCO may not, without the approval of the conflicts committee of the board of directors of our general partner, agree to any amendment of these agreements that, in the reasonable judgment of our general partner, will adversely affect any holder of common units.

Refining Agreement

General. In connection with this offering, OPCO will enter into a 25-year refining agreement with Big West. The refining agreement has a “take or pay” feature requiring Big West to pay a minimum amount of refining fees to OPCO over each semi-annual period whether or not Big West actually throughputs volumes that would accrue such fees.

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Gas oil throughput commitment. Big West will agree to throughput in OPCO’s MSCC unit an average of at least 10,000 bpd of gas oil during each semi-annual period (the “MSCC Commitment”) or pay the related refining fee as if it had throughput these volumes. Subject to Big West’s right of first refusal with respect to any excess capacity, OPCO will have the right to use any excess capacity in the MSCC unit to process for itself or third parties on a spot market basis. OPCO may enter into contracts of up to six months duration with third parties with respect to such excess capacity without Big West’s consent if Big West has failed to pay for the MSCC Commitment for six consecutive months. During the six months ended July 31, 2007, Big West throughput an average of 11,304 bpd of gas oil through the MSCC unit.

The fee for refining barrels of gas oil delivered by Big West to OPCO in any semi-annual period up to the MSCC Commitment will be (i) $29.00 multiplied by (ii) 10,000 multiplied by (iii) the number of days in such semi-annual period (such fee, the “MSCC Refining Fee”). For barrels of gas oil delivered by Big West to OPCO in excess of the MSCC Commitment, if any, the refining fee will be $5.00 per barrel (the “Excess Barrels Refining Fee”). Big West will pay the MSCC Refining Fee in estimated installments on a monthly basis, adjusted monthly and at the end of each semi-annual period. Big West will pay the Excess Barrels Refining Fee, if any, monthly in accordance with the refining agreement. If estimated monthly payments for MSCC Refining Fees by Big West in any semi-annual period fail to meet the minimum MSCC Refining Fee due for such semi-annual period, Big West will be required to pay OPCO cash in the amount of any shortfall. If estimated monthly payments for MSCC Refining Fees paid by Big West in any semi-annual period exceed the actual amount due for such semi-annual period, OPCO will be required to pay Big West cash in the amount of any excess.

Alkylation offtake commitment. Big West will be obligated to offtake an average of at least 2,000 bpd of alkylation product during each semi-annual period (the “Required Offtake Commitment”) or pay the related fee as if it had received these volumes. Subject to Big West’s right of first refusal with respect to any excess capacity, OPCO shall have the right to use the excess capacity of the alkylation unit to process alkylation feedstock for itself or third parties on a spot market basis. OPCO may enter into contracts of up to six months duration with third parties with respect to such excess capacity without Big West’s consent if Big West has failed to pay for its Required Offtake Commitment for six consecutive months. During the six months ended July 31, 2007, Big West received an average of 2,661 bpd of alkylate from the alkylation unit.

The fee for processing Big West’s alkylation feedstock in any semi-annual period up to the Required Offtake Commitment will be (i) $19.00 multiplied by (ii) 2,000 multiplied by (iii) the number of days in such semi-annual period (such fee, the “Alkylation Refining Fee”). For barrels of alkylation product received by Big West above the Required Offtake Commitment, if any, the refining fee will be $3.00 per barrel (the “Excess Alkylation Refining Fee”). Big West will pay the refining fee in estimated installments on a monthly basis, adjusted monthly and at the end of each semi-annual period. Big West will pay the Excess Alkylation Offtake Fee, if any, monthly in accordance with the refining agreement. If estimated monthly payments for Alkylation Refining Fees by Big West in any semi-annual period fail to meet the minimum Alkylation Refining Fee due for such semi-annual period, Big West will be required to pay OPCO cash in the amount of any shortfall. If estimated monthly payments for the Alkylation Refining Fees paid by Big West in any semi-annual period exceed the actual amount due for such semi-annual period, OPCO will be required to pay Big West cash in the amount of any excess.

Shortfall payment. A shortfall payment by Big West for unused capacity in any semi-annual period will be applied as credit entitling Big West to have feedstock refined for it by OPCO during the following twelve-month period, subject to certain conditions.

Refining fee increase. In the event that OPCO’s aggregate operating expenses under its services agreements with Big West increase for any given year during the term of the refining agreement, the refining fees payable by Big West to OPCO for the following year will be increased by the amount of the operating expenses increase for the prior year. This refining fee increase will be permanent and is intended to offset increases in OPCO’s operating costs during the term of the refining agreement that would otherwise decrease OPCO’s net operating profit.

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Force majeure. A force majeure event under the refining agreement includes, but is not limited to, acts of God; calamities; fire; war; terrorism; unusually bad weather; interruption or delay in transportation and any inadequacy, shortage or failure or breakdown of supply of raw materials; certain labor difficulties (whether or not the demands of the employee are within the power of the claiming party to concede); and compliance with governmental orders or laws not brought about by an act or omission of the party claiming force majeure. Changes in costs of goods or services or changes in costs of regulatory or other compliance with law or lack of finances are not force majeure events. During any force majeure event with respect to Big West’s facility, OPCO will be relieved of its obligations to refine feedstock to the extent such obligations are affected by the force majeure event. If the force majeure event is solely with respect to Big West’s facility, Big West will be obligated to continue to pay refining fees, including with respect to feedstock that Big West is unable to deliver due to the force majeure event. During any force majeure event with respect to OPCO’s units, Big West will be relieved of its obligation to deliver feedstock and pay refining fees, to the extent such obligations are affected by the force majeure event.

Events of default. An event of default with respect to a party shall mean any of the following:

• the failure of the defaulting party to pay when due any undisputed payment under the agreement and such failure is not remedied within 15 business days after written notice thereof;

• the failure of the defaulting party to comply with its other respective obligations under the agreement and such failure is not remedied for 30 days after written notice thereof; or

• the defaulting party is subject to a bankruptcy proceeding.

Upon the occurrence and during the continuation of an event of default with respect to bankruptcy of the defaulting party, the non-defaulting party may, in its sole discretion:

• accelerate and liquidate the parties’ respective obligations under the agreement by establishing and notifying the defaulting party of an early termination date (which shall be no earlier than the date of such notice and no later than 90 days after the date of such notice) on which the agreement shall terminate;

• withhold any payments due to the defaulting party until such event of default is cured; and/or

• set off against any amounts due to the defaulting party any or all amounts that the defaulting party owes to the non-defaulting party.

With respect to all other events of default under the refining agreement, the non-defaulting party must engage in mediation and a determination by Utah courts that an event of default has occurred before exercising the remedies described above. In addition to the remedies described above, if Big West terminates the refining agreement in violation of the agreement, Big West must pay to OPCO as liquidated damages the present value of the anticipated refining fees (less anticipated payments to Big West under the services agreements and site lease) that would have been received by OPCO over the remainder of the term.

Term. The refining agreement has an initial term of 25 years and may be renewed thereafter if agreed by both parties. Beginning at least one year prior to the expiration of the term, the parties will negotiate in good faith to renew the agreement, and if they are unable to reach an agreement, senior management of the parties will discuss a renewal, but neither party shall be obligated to renew the refining agreement.

If Big West does not extend or renew the refining agreement on terms favorable to OPCO, OPCO’s and our financial condition and results of operations may be materially adversely affected. OPCO’s assets are integrated with the Big West facility and have been optimized to service Big West’s refining and marketing supply chain. As a result, if Big West does not renew the refining agreement, OPCO is unlikely to be able to generate replacement revenues from third parties. For a description of the risks related to the refining agreement and other agreements relating to the operation of OPCO’s units, please read “Risk Factors—Risks Inherent in Our Business.”

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Shared Services Agreement

OPCO will enter into a shared services agreement with Big West. Pursuant to the shared services agreement, Big West has agreed to provide to OPCO various services including services relating to the maintenance and operation of those common facilities located in the Salt Lake refining complex that are necessary for the operation of OPCO’s units including but not limited to railroad, control room and process safety, emergency response and security, warehouse and laboratory, and maintenance of buildings and grounds. Big West will also make available to OPCO electricity, natural gas, fuel gas, boiler feed water, cooling water, potable water and other utility services that are necessary for OPCO to operate its units. The shared services agreement also provides that Big West will use commercially reasonable efforts to furnish additional services as OPCO may request on terms mutually agreed upon. The provision of services to OPCO is subject to the control of OPCO, and Big West is required at all times to act in accordance with prudent operating and maintenance practices of the U.S. petroleum refining industry, all applicable laws, and good faith and reasonable commercial standards. In addition, the services are to be performed in a good faith effort to be cost effective, and with the same general degree of care and at the same general degree of accuracy and responsiveness as when Big West performs services for itself at the Big West facility.

OPCO has agreed to pay the direct costs of these services plus an administrative fee of $100,000 per year. To the extent that such direct costs cannot be separately measured, OPCO has agreed to pay a portion of the total cost determined in accordance with GAAP. The shared services agreement has an initial 25-year term. The shared services agreement may be renewed thereafter upon agreement of the parties. Big West may terminate the agreement if the refining agreement terminates under certain circumstances. With respect to events of default under the shared services agreement other than bankruptcy, the non-defaulting party must engage in mediation and a determination by the Utah courts that an event of default has occurred before terminating the agreement.

Master Services Agreement

OPCO will enter into a master services agreement with Big West pursuant to which Big West has agreed to provide to OPCO comprehensive operating services for OPCO’s units including but not limited to those relating to operation of OPCO’s units, maintenance, technical and engineering services, inventory controls and metering, and environmental permitting and compliance. The master services agreement also provides that Big West will use commercially reasonable efforts to furnish additional services as OPCO may request on terms mutually agreed upon. The provision of services to OPCO is subject to the control of OPCO, and Big West will be required to act at all times in accordance with prudent operating and maintenance practices of the U.S. petroleum refining industry, all applicable laws, and good faith and reasonable commercial standards. In addition, the services are to be performed in a good faith effort to be cost effective, and with the same general degree of care and at the same general degree of accuracy and responsiveness as when Big West performs services for itself at the Big West facility. These services are to be provided in a manner that permits OPCO’s units to be operated to the maximum extent possible on a coordinated basis with the Salt Lake refining complex.

OPCO has agreed to pay the direct costs of these services plus an administrative fee of $300,000 per year. To the extent that such direct costs cannot be separately measured, OPCO has agreed to pay a portion of the total cost determined in accordance with GAAP. The master services agreement has an initial 25-year term. The master services agreement may be renewed thereafter upon agreement of the parties. Big West may terminate the agreement if the refining agreement terminates under certain circumstances. With respect to events of default under the master services agreement other than bankruptcy, the non-defaulting party must engage in mediation and a determination by the Utah courts that an event of default has occurred before terminating the agreement.

Site Lease Agreement

OPCO will enter into a site lease agreement with Big West pursuant to which Big West has agreed to lease to OPCO the real property underlying the process units comprising OPCO’s units and to grant OPCO easements and rights of way necessary to operate OPCO’s units at the Salt Lake refining complex. OPCO has agreed to pay to Big West lease payments of $50,000 per annum. While under the site lease OPCO will have access to the

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facilities necessary to perform its obligations under the refining agreement, the access and support services Big West will provide to OPCO’s units under the services agreements and the site lease have been optimized to service Big West’s refining and marketing supply chain and for the operating requirements of the Big West facility. OPCO does not own or lease storage tanks and other equipment necessary in order for OPCO to throughput product on behalf of a third party. If OPCO were to refine products on behalf of a third party, it would need to lease tanks and related facilities from Big West at a commercially reasonable fee based on then current market rates for the storage and throughput of third party feedstocks.

The site lease agreement has an initial term that is coterminous with the term of the shared services agreement. The site lease agreement may be renewed if agreed by the parties. With respect to events of default under the site lease agreement other than bankruptcy, the non-defaulting party must engage in mediation and a determination by the Utah courts that an event of default has occurred before terminating the agreement.

Environmental, Health and Safety Matters

OPCO operates petroleum refining operations, which are subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations can impair OPCO’s operations that affect the environment in many ways, such as requiring the acquisition of permits to conduct regulated activities; restricting the manner in which we can release materials into the environment; requiring remedial activities or capital expenditures to mitigate pollution from former or current operations; and imposing substantial liabilities on us for pollution resulting from our operations. Certain environmental laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes, or other materials have been released or disposed. Moreover, because the permits and authorizations for OPCO’s air emissions, water discharges and waste handling activities are held by Big West, compliance by the Salt Lake refining complex with those permits or other applicable requirements of federal, state or local environmental laws may affect our ability to obtain and maintain the permits and authorizations that are necessary for our business as well as operate under our current permits.

Failure to comply with environmental laws and regulations may result in administrative, civil and criminal sanctions, including monetary penalties, remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of our operations. On occasion, Big West receives notices of violation, enforcement and other complaints from regulatory agencies alleging non-compliance with applicable environmental laws and regulations. For example, Big West received a proposed consent decree dated November 23, 2005 with respect to the Salt Lake refining complex relating to Prevention of Significant Deterioration, or PSD, New Source Performance Standards, or NSPS, Leak Detection and Repair, or LDAR, and National Emission Standards for Hazardous Pollutants, or NESHAP, from the EPA. The proposed consent order stems from the EPA’s Natural Petroleum Refinery Initiative which targeted petroleum refineries that allegedly increased production capacity, allegedly without adequately complying with such requirements relating to flares, sulfur recovery units, heaters and boilers. The EPA has not proposed a fine at this time and we do not know the cost of compliance measures if any, needed to meet the terms of the decree. Big West is working with the EPA to finalize the consent decree but negotiations are preliminary and the outcome is uncertain. Any definitive consent decree that is entered into between Big West and EPA/DOJ could impose civil penalties as well as costly compliance measures on Big West.

Big West has in the past and may in the future experience releases of petroleum products, unauthorized air emissions, fires, explosions and accidents involving workers or contractors. As a result, Big West has been, and we and Big West may in the future be, subject to claims for damages or penalties from government authorities or private parties. While OPCO is not responsible for any such releases that may occur in the future from Big West’s operations it is possible that similar release will occur from our operations.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more

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stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. Moreover, in connection with accidental spills or releases associated with OPCO’s operations, we cannot assure our unitholders that we will not incur substantial costs and liabilities as a result of such spills or releases, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may be unable to pass on those increases to our customers. While we believe that OPCO and Big West are in substantial compliance with existing environmental laws and regulations and that continued compliance with these requirements will not have a material adverse effect on us, there can be no assurance that our environmental compliance expenditures will not become material in the future.

Air

OPCO’s operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws. The Clean Air Act Amendments of 1990 require most industrial operations in the U.S. to incur capital expenditures to meet the air emission control standards that are developed and implemented by the EPA and state environmental agencies. Under the Clean Air Act, facilities that emit volatile organic compounds or nitrogen oxides face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. In addition, the petroleum refining sector has come under stringent new EPA regulations, imposing maximum achievable control technology (“MACT”) on refinery equipment, including catalytic cracking units, emitting certain listed hazardous air pollutants. Some of OPCO’s facilities have been included within the categories of sources regulated by MACT rules. When finalized, EPA’s proposed new source performance standards (“NSPS”) for petroleum refineries that were published in the Federal Register on May 14, 2007, may also apply to certain new or modified sources of air emissions at OPCO’s units. In addition, air permits are required for OPCO’s refining and terminal operations that result in the emission of regulated air pollutants. These permits incorporate stringent control technology requirements and are subject to extensive review and periodic renewal. Aside from the current discussions with the EPA concerning a proposed consent decree, as described above, we and Big West believe that we are in substantial compliance with the Clean Air Act and similar state and local laws.

The Clean Air Act authorizes the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with the fuel product’s final use. For example, in December 1999, the EPA promulgated regulations limiting the sulfur content allowed in gasoline. These regulations required the phase-in of gasoline sulfur standards beginning in 2004, with special provisions for small refiners and for refiners serving those Western states exhibiting lesser air quality problems. Similarly, the EPA promulgated regulations that limit the sulfur content of 80% of highway diesel produced at the refinery beginning on June 1, 2006 from its former level of 500 parts per million (“ppm”) to 15 ppm (the “ultra low sulfur standard”). The Salt Lake refining complex implemented the sulfur standard with respect to diesel meeting the ultra low sulfur standard by the deadline. Big West estimates that approximately 90% or more of the diesel produced in the Salt Lake refining complex for the fiscal year ended January 31, 2007 was in compliance with the diesel standards. Any diesel product not meeting the standards may be sold for use in certain non-road vehicle markets until 2010. Additional sulfur reductions will become effective on June 1, 2010, by which time the sulfur limit will be 15 ppm for all diesel sold for highway, off-highway, locomotive and marine use. Big West eventually may need to install additional equipment at the Big West facility for its entire diesel product to meet the new sulfur standard.

Climate Change

In response to recent studies suggesting that emissions of certain gases may be contributing to warming of the Earth’s atmosphere, many foreign nations have agreed to limit emissions of these gases, generally referred to as “greenhouse gases,” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of fossil fuels, are examples of greenhouse gases. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills having already been introduced in both the House and the Senate that propose to restrict greenhouse gas emissions. By comparison, several states have already adopted legislation, regulations and/or regulatory

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initiatives to reduce emissions of greenhouse gases. For example, in December 2005, a group of northeastern states agreed to implement a regional cap-and-trade program, referred to as the Regional Greenhouse Gas Initiative (“RGGI”) to stabilize carbon dioxide emissions from regional power plants beginning in 2009. Under RGGI, the 10 participating Northeastern states have set the goal of capping carbon dioxide emissions from power plants at current levels through 2015 and must cut carbon dioxide emissions by ten percent below the initial cap by 2020. Six Western states, including Utah and two Canadian provinces, have also formed a regional greenhouse gas reduction initiative, the Western Climate Initiative, with the stated goal of reducing the region’s greenhouse gas emissions through a market-based mechanism by 15 percent below 2005 levels by the year 2020. The scope of the Western Climate Initiative, including the industries to be targeted, has yet to be established.

Also, on April 2, 2007, the U.S. Supreme Court held, inMassachusetts, et al. v. EPA that the U.S. Environmental Protection Agency has the authority under the federal Clean Air Act to regulate carbon dioxide emissions from new motor vehicles. This litigation did not directly concern EPA’s authority to regulate greenhouse gas emissions from stationary sources, such as oil refineries. The Court’s decision has, however, influenced another lawsuit currently pending in the U.S. Court of Appeals for the District of Columbia Circuit,New York State, et al. v. EPA, involving a challenge to EPA’s decision not to regulate carbon dioxide from power plants and other stationary sources under its February 27, 2006 new source performance standard (“NSPS”) for new electric utility steam generating units. Pending the resolution of any petitions for rehearing, the D.C. Circuit remandedNew York State, et al. v. EPA back to EPA on September 24, 2007 for further proceedings in light of the Supreme Court’s decision inMassachusetts, et al. v. EPA.

In the future, the promulgation of rules governing GHG emissions by EPA or the passage of climate change legislation by Congress could result in federal regulation of carbon dioxide emissions and other greenhouse gases. Also, any federal or state restrictions on emissions of greenhouse gases that may be imposed in areas of the United States in which OPCO conducts business could adversely affect OPCO’s operations and demand for its products.

Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict 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. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of its operations, OPCO generates wastes or handle substances that may be regulated as hazardous substances, and we and OPCO could become subject to liability under CERCLA and comparable state laws. We and OPCO may incur liability, including possibly joint and several liability, for releases of hazardous substances from the Salt Lake refining complex or OPCO’s units.

We and OPCO also may incur liability under the Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose requirements related to the handling, storage, treatment, and disposal of solid and hazardous wastes. In the course of its operations, OPCO generates petroleum product wastes and ordinary industrial wastes, such as paint wastes, waste solvents, and waste oils, that may be regulated as hazardous wastes. In addition, OPCO’s operations also generate solid wastes, which are regulated under RCRA and state law. We believe that OPCO is in substantial compliance with the existing requirements of RCRA and similar state and local laws, and the cost involved in complying with these requirements is not material.

OPCO currently owns or operates, and in the past Big West owned or operated, properties that for many years have been used for refining and terminal activities. These properties have in the past been operated by third

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parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. Although Big West used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes have been released on or under the properties owned or operated by OPCO. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we and OPCO could be required to remove or remediate previously disposed wastes or releases of hazardous substances on our property, or to perform remedial activities to prevent future releases.

Voluntary soil remediation has been undertaken and active groundwater monitoring is in process at the Salt Lake refining complex. The groundwater monitoring activities are being overseen by the appropriate state agencies. Based on current investigative and remedial activities, we believe that the groundwater issues at these refineries can be controlled or remedied without having a material adverse effect on our financial condition. However, such costs are often unpredictable and, therefore, there can be no assurance that the future costs will not become material.

Water

The federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. Such discharges are prohibited, except in accordance with the terms of a permit issued by the EPA or the appropriate state agencies. Any unpermitted release of pollutants, including crude or hydrocarbon specialty oils as well as refined products, could result in penalties, as well as significant remedial obligations. Spill prevention, control, and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the releases of hazardous substances to navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. We believe that we and OPCO are in substantial compliance with the requirements of the Clean Water Act.

The primary federal law for oil spill liability is the Oil Pollution Act of 1990, as amended (“OPA”), which addresses three principal areas of oil pollution—prevention, containment, and cleanup. OPA applies to vessels, offshore facilities, and onshore facilities, including refineries, terminals, and associated facilities that may affect waters of the U.S. 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 from oil spills. We believe that we and OPCO are in substantial compliance with OPA and similar state laws.

Remediation Matters

Many environmental cleanup requirements are imposed regardless of fault under liability schemes that call for strict, joint and several liability. At the Salt Lake refining complex, Big West has cleaned up several areas where releases of hazardous substances from historical activities were occurring and is currently monitoring a plume of hydrocarbons in the groundwater under a tank farm area. Over a period of several years, the plume has not increased in size or concentration. The downgradient edge of the plume is over one thousand feet from the property boundary. OPCO and Big West continue to monitor the plume on a regular basis.

In addition, Big West may have additional responsibilities for portions of the site that Big West has remediated pursuant to a Closure/Post-Closure plan Big West entered into with the state. To date, the state has not agreed to terminate post-closure care of the remediated areas. The negotiations to date have been preliminary and we do not know the cost of additional remedial measures that may be imposed by the state, if any. However, any Stipulation and Consent Order, or Post-Closure Permit, could impose substantial and costly remediation obligations on OPCO and Big West.

Environmental Insurance

Big West has purchased an environmental insurance policy covering certain environmental liabilities at the Salt Lake refining complex, the premiums for which have been prepaid in full. Under an environmental response, compensation and liability insurance policy, Big West is covered for bodily injury, property damage, clean-up

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costs, legal defense expenses and civil fines and penalties relating to unknown conditions and incidents. The policy is subject to a self-insured retention of $1.0 million per loss. The policy has a term of three years from September 2005 to September 2008 and provides maximum coverage of $4.0 million for each loss and maximum aggregate coverage of $8.0 million over the policy period. The insurer under these policies is Greenwich Insurance Company.

Environmental Indemnification

Pursuant to the omnibus agreement, Big West will indemnify us for 25 years after the closing of the offering for certain environmental and toxic tort liabilities associated with the operation of the assets contributed to us and occurring prior the closing of the offering. However, Big West will not have any indemnification obligation under the omnibus agreement for environmental losses until our aggregate losses exceed $500,000, and then only to the extent such aggregate losses exceed $500,000.

Big West has agreed to indemnify us for environmental liabilities associated with the assets retained by Big West and associated with the operation of those assets after the closing of this offering. In addition, we have agreed to indemnify Big West against environmental liabilities related to our assets and associated with the operation of the assets occurring after the closing date of this offering to the extent Flying J is not required to indemnify us.

Health and Safety

We and OPCO are subject to various laws and regulations relating to occupational health and safety including OSHA, and comparable state laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We maintain safety, training, and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. Our compliance with applicable health and safety laws and regulations has required and continues to require substantial expenditures. We believe that our and OPCO’s operations are in substantial compliance with OSHA and similar state laws.

Employees

As of July 31, 2007, Big West had approximately 410 employees, of which approximately 140 were employed at the Salt Lake refining complex. Of these 140 employees at the Salt Lake refining complex, approximately 90 are covered by collective bargaining agreements that expire on April 15, 2009. Approximately 35 employees worked at Big West’s corporate offices in Ogden, Utah. None of the employees in the corporate offices are represented by a union. Big West considers its relations with its employees to be satisfactory.

Legal Proceedings

In the ordinary conduct of our business, we, OPCO and Big West are subject to periodic lawsuits, investigations and claims, including, environmental claims and employee related matters. See “—Environmental, Health and Safety Matters.” Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations and claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we or Big West are a party will have a material adverse effect on our business, results of operations, cash flows or financial condition.

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MANAGEMENT

Management of Big West Oil Partners, LP

Our general partner, Big West GP, LLC, will manage our operations and activities. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are nonrecourse to it.

The directors of our general partner will oversee our operations. Upon the closing of this offering, our general partner will have at least six directors, and intends to increase the size of its board of directors to eight following the closing of this offering. Our general partner will elect all members to its board of directors. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/governance committee. Our general partner’s board of directors does not have a nominating and corporate governance committee or a committee performing the functions of this committee.

At least three members of the board of directors of our general partner, or the Board, will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934, as amended (“Exchange Act”), to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

In addition, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the New York Stock Exchange. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee.

All of the executive officers of our general partner listed below will allocate their time between managing our business and affairs and the business and affairs of Flying J and Big West. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of Flying J and Big West. Flying J and Big West intend to cause the executive officers to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs although it is anticipated that the executive officers of our general partner will devote significantly less than a majority of their time to our business for the foreseeable future. We will reimburse Big West for allocated expenses of personnel who perform services for our benefit, allocated general and administrative expenses and certain direct expenses. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Administrative Services.”

Big West Operating GP, LLC, the general partner of OPCO, will manage OPCO’s operations and activities. The board of directors of Big West GP, LLC, will appoint the officers of Big West Operating GP, LLC. Some of the directors and officers of our general partner will also serve as executive officers of OPCO’s general partner.

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Any amendment to OPCO’s partnership agreement or to the limited liability company agreement of OPCO’s general partner must be approved by the conflicts committee of the board of directors of our general partner, Big West GP, LLC. Other actions affecting OPCO, including, among other things, the amount of its cash reserves, must be approved by our general partner’s board of directors on our behalf. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—OPCO Partnership Agreement and Big West Operating GP, LLC Limited Liability Company Agreement.”

Whenever our general partner makes a determination or takes or declines to take an action in its individual capacity rather than in its capacity as our general partner, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us or any limited partner, and our general partner is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law. Examples include the exercise of its call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership. Actions of our general partner, which are made in its individual capacity, will be made by Big West.

Directors and Executive Officers of Big West GP, LLC

The following table shows information regarding the current directors and executive officers of Big West GP, LLC. Directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors.

Name	Age	Position
J Phillip Adams	52	Chairman of the Board, President and Chief Executive Officer
Fred L. Greener	52	Chief Operating Officer and Director
Scott G. McMillan	32	Chief Financial Officer and Director
Robert L. Inkley	44	Director
Jeffery O. Foote	46	Director

Set forth below is a brief description of the business experience of each of our directors, executive officers and key employees listed above. Prior to this offering, our executive officers and key employees held positions with Flying J or Big West Oil, LLC or their affiliates. In December 2007, in contemplation of this offering, each of the executive officers was elected to an office or appointed to a position with Big West GP, LLC.

J Phillip Adams. J Phillip Adams serves as President and Chief Financial Officer of our general partner and Chairman of the Board of Directors of our general partner. He has served as President and Chief Executive Officer of Flying J since 1992. Mr. Adams joined Flying J in 1980 and served as its Executive Vice President from 1986 to 1992. Prior to joining Flying J, Mr. Adams was a certified public accountant with Brown & Davis in Brigham City, Utah. Mr. Adams has a BS degree in accounting and finance from Utah State University.

Fred L. Greener. Fred L. Greener serves as Chief Operating Officer and a director of our general partner. Mr. Greener joined Flying J in 1980 and has been the Executive Vice President of Big West Oil, LLC since October 2003. From 1998 until October 2003, Mr. Greener served as the Chief Financial Officer of Big West Oil, LLC. Mr. Greener served as Mayor of Corinne, Utah from 1987 to 1993 and has a BS degree in accounting from Brigham Young University.

Scott G. McMillan. Scott G. McMillan serves as Chief Financial Officer and a director of our general partner. Mr. McMillan has served as Flying J’s administrative divisional controller since August 2007. From April 2004 to August 2007, Mr. McMillan served as Flying J’s Senior Vice President of Highway Hospitality. Mr. McMillan served as Flying J’s Director of Interstate Operations from January 2003 to April 2004. From March 1998 to January 2003, he was employed with Flying J as a corporate accounting manager. Mr. McMillan is a graduate of Utah State University, with a BS degree in Accounting and later received an MBA.

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Robert L. Inkley. Robert L. Inkley serves as a director of our general partner. Mr. Inkley joined Flying J in 1999 and has served as Flying J’s Corporate Controller since August 2003. From August 2001 to August 2003, Mr. Inkley served as Flying J’s Administrative Divisional Controller. From 1999 to August 2001, Mr. Inkley served as Flying J’s Assistant Corporate Controller. Prior to joining Flying J, Mr. Inkley worked for Geneva Steel from 1988 to 1999 where he served as the Manager of General Ledger and Planning and as a Senior Financial Analyst. Mr. Inkley has a MBA and a BS degree in finance from the University of Utah and a BS degree in accounting from Utah State University. Additionally, Mr. Inkley is a certified public accountant and certified treasury professional.

Jeffrey O. Foote. Jeffrey O. Foote serves as a director of our general partner. Mr. Foote has been President of Longhorn Partners Pipeline, a Flying J subsidiary unit, since November 2006. He joined Flying J in March 2005 as Vice President responsible for its communications business unit Prior to joining Flying J, Mr. Foote held several leadership positions over a 20 year career with Alliant Techsystems (ATK). He was President of ATK Aerospace Group from February 2002 until April 2004. He was both Executive VP and President of ATK Propulsion Company from March 2000 to February 2002. Mr. Foote held the positions of Vice President of Programs from March 1999 to February 2000; Vice President of Operations from January 1998 to March 1999 and Vice President of Titan Projects from April 1995 to January 1998. He has served as Director of the FAA Commercial Space Transportation Committee (2000 to 2004), Director and Chairman of Utah Manufacturer’s Association (1998 to 2004) and is currently a member of the Association of Oil Pipelines Executive Leadership committee. Mr. Foote earned a bachelor of engineering degree in civil engineering from the University of Delaware and a MBA degree from University of Utah.

Reimbursement of Expenses of Our General Partner

Our partnership agreement requires us to reimburse our general partner for all actual direct and indirect expenses it incurs or actual payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business including overhead allocated to our general partner by its affiliates, including Big West. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf, and expenses allocated to our general partner by its affiliates. We do not expect to incur any additional fees or to make other payments to these entities in connection with operating our business. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Executive Compensation

We, OPCO, our general partner and OPCO’s general partner were formed in December 2007. Neither our general partner nor OPCO’s general partner has paid or accrued any amounts for management or director compensation for the fiscal year ended January 31, 2007 or for any prior periods. Because the executive officers of our general partner are employees of Flying J and/or Big West or their affiliates, their compensation will be set and paid by Flying J. Our partnership agreement requires us to reimburse our general partner for the expenses it determines, in good faith, are allocable to us, including a portion of the compensation and benefits paid to the executive officers of our general partner. Officers and employees of Big West or its affiliates, who perform services for the partnership, may participate in employee benefit plans and arrangements sponsored by Big West or its affiliates, including plans that they may establish in the future. While we do not expect to make awards to them in the foreseeable future under the Big West GP, LLC Long-Term Incentive Plan, we reserve the option to do so in the future.

Compensation Discussion and Analysis

The following Compensation Discussion and Analysis of Flying J is relevant to the extent that the compensatory policies of Flying J affect the overall general and administrative costs of Big West and its affiliates, a portion of which we will be required to reimburse.

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We are a master limited partnership and do not directly employ any of the persons responsible for managing our business, and we do not have any directors. Big West GP, LLC, our general partner, will manage our operations and activities, and its board of directors and officers will make decisions on our behalf. All of the executive officers of our general partner and OPCO’s general partner also serve as executive officers of Big West, Flying J and/or their affiliates. Our reimbursement for the compensation of executive officers will be governed by our partnership agreement and will be based on Big West’s methodology used for allocating general and administrative expenses to us.

As discussed above, neither our general partner nor OPCO’s general partner has accrued any obligations with respect to management or director compensation. Accordingly, we are not presenting any compensation information for historical periods.

The compensation policies and philosophy of Flying J govern the types and amount of compensation granted to each of the executive officers of our general partner. Flying J will have the ultimate decision-making authority with respect to the total compensation of our executive officers and will determine the portion of such compensation that is allocated to us. Flying J does not have a compensation committee. The levels of such compensation will not be subject to approval by our general partner’s board of directors, including the audit and conflicts committees thereof, except with respect to awards under our general partner’s long-term incentive plan, which will be made by the Board of our general partner and must be unanimously approved by all of the non-independent directors of the Board of our general partner.

Purpose of Flying J’s Executive Compensation Program

Flying J’s executive compensation program has been designed to accomplish the following long-term objectives:

• create a proper balance between building stockholder wealth and executive wealth while maintaining good corporate governance;

• produce long-term, positive results for Flying J’s stockholders;

• align executive compensation with Flying J’s performance and appropriate peer group comparisons;

• provide market-competitive compensation and benefits that will enable Flying J to attract, motivate and retain a talented workforce; and

• prevent short-term inappropriate behavior to manipulate results for the purpose of increasing compensation.

Elements of Flying J’s Executive Compensation Program

Flying J’s executive compensation program consists of the following elements:

• base salary;

• annual incentive compensation, which includes (1) an annual cash bonus, (2) special cash bonus and (3) long-term incentive compensation (stock option awards and stock appreciation right awards); and

• perquisites and other benefits.

Base Salary

Flying J provides executive officers with a base salary that is commensurate with an industry peer group consisting of companies that compete with Flying J both for business opportunities and for executive talent. The base salary for each executive officer reflects the officer’s position, responsibilities and contributions relative to other executives. Salaries are typically reviewed by Flying J on a periodic basis as part of its performance and

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compensation review process, as well as at other times to recognize a promotion or change in job responsibilities or market positioning. As discussed above, a portion of the base salaries of the executive officers will be allocated to us pursuant to the services agreements.

Incentive Compensation

In general, an executive officer’s annual incentive compensation consists primarily of cash, stock appreciation rights and stock options. Flying J believes that making a portion of an executive’s annual incentive compensation contingent on long-term stock performance more closely aligns the executive’s interests with those of Flying J’s stockholders. Stock options and stock appreciation rights are granted periodically to executives and other key employees, as recommended by Flying J management and approved by Flying J’s board of directors.

Cash Bonuses

Employees of Big West have been granted awards under Flying J’s cash bonus plans. After the closing of this offering, employees of Flying J and Big West, who act as executive officers of our general partner, will continue to be eligible to receive future awards under the Flying J bonus plans.

Cash Bonus Plan. Certain employees of Big West and its affiliates are eligible to participate in a discretionary cash bonus plan. Based on the performance of specific affiliates and operating divisions, employees assigned to the affiliates and operating divisions may be paid a cash bonus as determined by the Flying J board of directors. Bonus amounts are calculated upon performance for the twelve months ended October 31 and are generally paid during the following December. However, both the amounts and recipients of all cash bonuses are determined at the discretion of Flying J’s management and board of directors.

Special Bonus Program. Certain employees of Big West and its affiliates are eligible to participate in the special bonus plan. This non-qualified plan pursuant to I.R.S. regulations is designed to reward participants for their efforts in continuing the growth and success of Flying J. Discretionary contributions are made by Flying J each year. Earnings on these contributions are based each year on Flying J’s increase in accumulated earnings. Each year’s contributions vest and are paid out separately one third each in years five, six and seven. Participants become 100.0% vested in their entire account upon their death, becoming totally disabled and no longer able to work, or upon reaching the age of 60.

Equity Compensation

Flying J 2007 Incentive Compensation Plan. The purpose of the Flying J 2007 Incentive Compensation Plan is to provide incentive to the directors, officer, other employees and consultants of Flying J and any present or future subsidiaries of Flying J. The Flying J 2007 Incentive Compensation Plan permits the granting of awards in the form of options to purchase Flying J common stock. Options to purchase Flying J common stock generally vest in equal annual installments over a four-year period and are exercisable for up to 10 years so long as the participant is continuously employed by Flying J or its subsidiaries. Flying J stock appreciation rights have vesting and expiration terms that are similar to Flying J stock options. Appreciation rights generally give the recipient the right to receive the spread between the fair market value of the underlying Flying J common stock on the date of exercise minus the fair market value at the date of grant (less applicable taxes).

Employees of Big West have been granted awards under the Flying J 2007 Incentive Compensation Plan and under prior Flying J stock option plans. After the closing of this offering, employees of Big West and its affiliates providing services to OPCO or the Partnership will continue to be eligible to receive future awards under the Flying J 2007 Incentive Compensation Plan and will retain any awards previously granted thereunder and under prior option plans.

Flying J Employee Stock Ownership Plan. Flying J maintains an Employee Stock Ownership Plan for the purpose of providing retirement benefits for eligible employees, including certain employees of Big West. The

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Employee Stock Ownership Plan was frozen to new participants and contributions on January 31, 2001. Prior to January 31, 2001, participants in the Employee Stock Ownership Plan were eligible to receive an annual stock bonus contribution and money purchase contribution to such employee’s ownership account, which Flying J was permitted to make in the form of Flying J common stock instead of cash. Participants are eligible to receive the vested amount in their ownership account balances when the participant (1) no longer has an employment relationship with Flying J or any of its subsidiaries or (2) exercises a withdrawal as permitted by the Flying J Employee Stock Ownership Plan. As of January 31, 2001, all participants were fully vested in their ownership accounts. Flying J has the option to give participants exercising their put right either (1) a lump sum cash payment equal to the fair market value of the Flying J common stock or (2) installment payments pursuant to a promissory note equal to the fair market value of the Flying J common stock, over a period not exceeding five years, at a reasonable interest rate and upon posting of adequate security. Participants who receive Flying J common stock as part of a plan distribution have been granted a put option to require Flying J to repurchase such common stock at the current fair market value of such common stock. The put option may be exercised only during two 60-day option periods. The first option period begins on the date of distribution of the Flying J common stock to the participant and the second option period begins in the next plan year on the date the fair market value of the Flying J common stock is determined.

After the closing of this offering, eligible employees of Flying J and its affiliates, including those providing services to OPCO or the Partnership, will maintain their ownership account in the Flying J Employee Stock Ownership Plan.

Perquisites and Other Benefits

Flying J generally does not pay for perquisites for any of the named executive officers that are not available to all employees generally. Flying J seeks to provide benefit plans, such as medical, life and disability insurance, in line with market conditions. Flying J’s executive officers are eligible for the same benefit plans provided to other exempt employees, including insurance plans and supplemental plans chosen and paid for by employees who wish additional coverage. Flying J does not have any special insurance plans for executive officers.

Flying J has a voluntary 401(k) savings plan for employees of Flying J and its affiliates. Eligible employees may contribute up to 12.0% of their salary. Flying J matches 50.0% of each employee’s contribution, up to a maximum annual company contribution of $1,200 per employee.

Compensation of Directors

Officers or employees of our general partner, OPCO’s general partner or their affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner or OPCO’s general partner. Our general partner anticipates that each director who is not an officer or employee of our general partner, OPCO’s general partner or its affiliates will receive compensation for attending meetings of the board of directors, as well as committee meetings. The amount of compensation to be paid to our general partner’s non-employee directors has not yet been determined. Each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

In addition, directors or officers are eligible to receive awards under the Big West GP, LLC Long-Term Incentive Plan described below.

Big West GP, LLC Long-Term Incentive Plan

Our general partner intends to adopt the Big West GP, LLC Long-Term Incentive Plan for employees, officers and directors ofBig West, our general partner, and any of their affiliates who perform services for us.

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The long-term incentive plan will consist of the following components: options, restricted units, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The purpose of awards under the long-term incentive plan is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such employees with the interests of our unitholders. The long-term incentive plan will limit the number of units that may be delivered pursuant to awards to 812,500 common units. Common units cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The plan will be administered by the board of directors of our general partner, which we refer to as the plan administrator, and must be unanimously approved by the non-independent directors of the Board of our general partner.

The plan administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. The plan administrator also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire on the earliest of (1) the date units are no longer available under the plan for grants, (2) termination of the plan by the plan administrator or (3) the date 10 years following its date of adoption.

We do not expect to make any awards under the long-term incentive plan in the foreseeable future, but reserve the option to do so if our general partner deems such awards to be in the best interest of the partnership and provided such rewards are unanimously approved by the non-independent directors of the Board of our general partner.

Restricted Units

A restricted unit is a common unit that vests over a specified period of time and during that time is subject to forfeiture. The plan administrator may make grants of restricted units containing such terms as it shall determine, including the period over which restricted units will vest. The plan administrator, in its discretion, may base its determination upon the achievement of specified financial or other performance objectives. Restricted units will be entitled to receive quarterly distributions during the vesting period.

Unit Options

The long-term incentive plan will permit the grant of options covering common units. The plan administrator may make grants containing such terms as the plan administrator shall determine. Unit options must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit options granted will become exercisable over a period determined by the plan administrator.

Unit Appreciation Rights

The long-term incentive plan will permit the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a common unit on the exercise date over the exercise price established for the unit appreciation right. Such excess will be paid in cash or common units. The plan administrator may make grants of unit appreciation rights containing such terms as the plan administrator shall determine. Unit appreciation rights must have an exercise price that is not less than the fair market value of the common units on the date of grant. In general, unit appreciation rights granted will become exercisable over a period determined by the plan administrator.

Distribution Equivalent Rights

The plan administrator may, in its discretion, grant distribution equivalent rights, or DERs, as a stand-alone award or in tandem with other awards under the long-term incentive plan. DERs entitle the participant to receive

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cash or additional awards equal to the amount of any cash distributions made by us during the period the right is outstanding. Payment of a DER issued in connection with another award may be subject to the same vesting terms as the award to which it relates or different vesting terms, in the discretion of the plan administrator.

Other Unit-Based Awards

The long-term incentive plan will permit the grant of other unit-based awards, which are awards that are based, in whole or in part, on the value or performance of a common unit. Upon vesting, the award may be paid in common units, cash or a combination thereof, as provided in the grant agreement.

Unit Awards

The long-term incentive plan will permit the grant of common units that are not subject to vesting restrictions. Unit awards may be in lieu of or in addition to other compensation payable to the individual.

Change in Control; Termination of Service

Awards under the long-term incentive plan will vest and/or become exercisable, as applicable, upon a “change in control” of us or our general partner, unless provided otherwise by the plan administrator. The consequences of the termination of a grantee’s employment, consulting arrangement or membership on the board of directors will be determined by the plan administrator in the terms of the relevant award agreement.

Source of Units

Common units to be delivered pursuant to awards under the long-term incentive plan may be common units acquired by us in the open market, common units acquired by us from any other person or any combination of the foregoing. If we issue new common units upon the grant, vesting or payment of awards under the long-term incentive plan, the total number of common units outstanding will increase.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:

• each person who then will beneficially own of 5% or more of the outstanding units;

• each member of the board of directors of our general partner;

• each named executive officer of our general partner; and

• all directors and executive officers of our general partner as a group.

The amounts and percentages of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the person named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable. The address for the beneficial owners listed below is 1104 County Hills Drive, Ogden, Utah 84403, unless otherwise indicated.

	Common Units to be Beneficially Owned	Percentage of Common Units to be Beneficially Owned		Subordinated Units to be Beneficially Owned	Percentage of Subordinated Units to be Beneficially Owned		Percentage of Total Common and Subordinated Units to be Beneficially Owned
Big West Holdings, LLC(1)	—	—		6,906,250	100	%	42.50	%
Big West GP, LLC(1)	1,218,750	13.04	%	—	—		7.5	%
Directors and Executive Officers:
J Phillip Adams(2)	—	—		—	—		—
Scott G. McMillan(2)	—	—		—	—		—
Fred L. Greener(2)	—	—		—	—		—
Robert L. Inkley(2)	—	—		—	—		—
Jeffrey O. Foote(2)	—	—		—	—		—
All directors and officers as a group (5 persons)	—	—		—	—		—

(1) Big West Holdings, LLC and Big West GP, LLC are indirect wholly owned subsidiaries of Flying J Inc.

(2) Does not include common units that may be purchased in the directed unit program.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions

Prior to the offering, our predecessor was an indirect wholly owned subsidiary of Flying J and operated as a component of the integrated operations of Flying J and its affiliates. Consequently, we have historically engaged in significant transactions and have had material relationships with Flying J and its affiliates on a continuous basis.

Big West sold refined petroleum products to Flying J and its affiliates, and purchased from Flying J and its affiliates, both crude oil forthe Salt Lake refining complex and finished petroleum products. For the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2007, Big West’s total net sales of refined products to Flying J and its affiliates were approximately $253.1 million, $427.4 million, $450.3 million and $243.3 million, respectively. Approximately $253.1 million, $382.5 million, $405.7 million and $211.5 million of such sales related to net sales of refined products from the Salt Lake refining complex for the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2007, respectively. For the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2007, Big West purchased crude oil from Flying J Oil & Gas, a subsidiary of Flying J, in amounts of approximately $11.1 million, $16.1 million, $14.4 million and $6.0 million, respectively (all of which related to the Salt Lake refining complex). For the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2007, Big West purchased finished petroleum products from Flying J in amounts of approximately $14.3 million, $10.9 million, $2.9 million and $0.2 million, respectively (all of which related to the Salt Lake refining complex).

For the fiscal years ended January 31, 2005, 2006 and 2007 and the six months ended July 31, 2007, Flying J charged Big West approximately $1.3 million, $4.0 million, $6.7 million and $3.4 million, respectively, for management services. These charges are reflected in Big West’s financial statements as general and administrative expenses.

Ownership of General Partner and Limited Partner Interests

Following the completion of this offering, Big West will own 65.0% of the limited partner interests in OPCO. In addition, Big West will beneficially own approximately 50.0% of our limited partner interests, or 43.7% if the underwriters exercise their option to purchase additional units in full. In addition, following completion of this offering, Big West will own the entire equity interest in our general partner. As a result, Big West will continue to be able to control the election of the directors of our general partner, otherwise exercise control or significant influence over our partnership and management policies and generally determine the outcome of any partnership or OPCO transaction or other matter submitted to our unitholders for approval, including potential mergers or acquisitions, asset sales and other significant partnership transactions. So long as Big West owns a majority equity interest in our general partner or a significant amount of our limited partner interest, Big West will continue to be able to effectively control or significantly influence the outcome of such matters.

Contractual Arrangements

In connection with this offering, we and/or OPCO will enter into the following agreements with Big West:

• refining agreement;

• master services agreement;

• shared services agreement;

• site lease agreement; and

• omnibus agreement.

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These agreements are described under “Business—Agreements with Affiliates.” As a result of Big West’s ownership interest in us, the terms of such agreements were not, and the terms of any future amendments to those agreements may not be, the result of arm’s-length negotiations.

Registration Rights

For a description of the registration rights granted to our general partner and its affiliates, including Big West Oil, LLC, see “Units Eligible for Future Sale.”

Future Transactions with Related Parties

We have not adopted any formal policy governing related party transactions. Consequently, our general partner’s board of directors will utilize such procedures in evaluating the terms of any future material transactions between us and Big West, Flying J or other related parties as our general partner’s board of directors may deem appropriate in light of its fiduciary duties under state law.

After this offering, Big West will beneficially own 6,906,250 subordinated units representing an aggregate 41.7% limited partner interest in us. In addition, our general partner will own a 2.0% general partner interest in us, 1,218,750 common units representing a 7.3% limited partner interest in us, and the incentive distribution rights. Big West will also own 65.0% of the limited partner interests in OPCO.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Big West Oil Partners, LP These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general partner and its affiliates for the contribution to us of a 35.0% interest in OPCO (consisting of the 0.001% general partner interest and a 34.999% limited partner interest), such contribution to occur at or prior to the closing of this offering	•   1,218,750 common units;
	•   6,906,250 subordinated units;
	•   2.0% general partner interest;
	•   the incentive distribution rights;
	•   $298.0 million distribution from the net proceeds of this offering and borrowings under the new credit facility.

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Operational Stage

Distributions of available cash to our general partner and its affiliates We will generally make cash distributions of 98.0% to the unitholders pro rata, including our general partner and its owner, as the holders of an aggregate of 1,218,750 common units and 6,906,250 subordinated units, and 2.0% to our general partner.

In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target level.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $0.50 million on its 2.0% general partner interest and our general partner and its owner would receive $12.2 million on their common and subordinated units.

Payments to our general partner and its affiliates We will reimburse our general partner and its affiliates for all expenses incurred on our behalf.

Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of the General Partner.”

Liquidation Stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including our acquisition of interests in OPCO, the vesting of assets in, and the assumption of liabilities by, us and OPCO, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement

Upon the closing of this offering, we and OPCO will enter into an omnibus agreement with Flying J, Big West, our general partner and others. The obligations of Flying J and its affiliates under the omnibus agreement will terminate in the event of a change of control of our general partner and assignment of the omnibus agreement to the transferee, assumption by the transferee of Big West’s obligations under the related agreements and the transferee’s meeting a minimum credit rating.

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Indemnification. Under the omnibus agreement, Big West will indemnify us for 25 years after the closing of this offering against certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets and occurring before the closing date of this offering. Big West will not have any obligation under this indemnification until our aggregate losses exceed $500,000, and only to the extent such aggregate losses exceed $500,000. Big West has agreed to indemnify us for environmental liabilities associated with the assets retained by Big West and associated with the operation of those assets after the closing of this offering. In addition, we have agreed to indemnify Big West against environmental liabilities related to our assets and associated with the operation of the assets occurring after the closing date of this offering to the extent Flying J is not required to indemnify us.

Additionally, Big West will indemnify us for losses attributable to title defects, failures to obtain consents or permits necessary for the transfer of the contributed assets, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify Flying J for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to Big West’s indemnification obligations. In addition, Big West will indemnify the Partnership for liabilities relating to events and conditions associated with the operation of the assets contributed to the Partnership (other than with respect to environmental and toxic tort liabilities) that occur prior to the closing of the offering, to the extent that Big West is notified in writing within one year after the closing of the offering, events and conditions associated with any assets retained by Big West or its affiliates and all currently pending legal actions against Big West or its affiliates.

Right of First Refusal. The partnership and its controlled affiliates will grant Big West a right of first refusal on any proposed transfer of the assets that serve Big West’s refineries.

If any partnership entity proposes to transfer any of the assets subject to the right of first refusal pursuant to a bona fide third-party offer, it shall promptly give written disposition notice to the applicable Big West entity, providing certain required information about the acquisition proposal. The applicable Big West entity will provide written notice of its decision regarding the exercise of its right of first refusal to purchase the sale assets within 30 days of its receipt of the disposition notice. If the applicable Big West entity fails to exercise a right during the applicable period, it shall be deemed to have waived its rights with respect to such proposed disposition of the sale assets, but not with respect to any future offer of assets.

If the transfer to the proposed transferee is not consummated in accordance with the terms of the acquisition proposal within the later of (a) 180 days after the later of the applicable acceptance deadline and (b) 10 days after the satisfaction of all governmental approval or filing requirements, if any, the acquisition proposal shall be deemed to lapse, and the partnership entity may not transfer any of the sale assets described in the disposition notice without complying again with the provisions described above if and to the extent then applicable.

Competition. Flying J and its affiliates, for a period of 5 years following the closing date, are prohibited from creating any new publicly traded limited partnership that (1) conducts the business of refining crude oil or other hydrocarbon products in the continental United States or (2) owns or operates the Longhorn refined products pipeline which is currently owned by another Flying J affiliate.

Except as provided above, neither Flying J nor any of its affiliates will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. Flying J and any of its affiliates may acquire, construct or dispose of additional refining or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

Insurance. Big West is required to obtain and maintain certain minimum insurance coverage and types during any period in which one or more of the refining agreement or other related agreements is in effect. Big West shall procure and maintain such insurance under individual or blanket policies and (unless an insurer does not permit) include OPCO and the partnership as insureds under all liability policies except for workers compensation insurance.

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The insurance to be obtained and maintained by Big West includes statutory workers compensation insurance, employer’s liability insurance, comprehensive general liability insurance, automobile liability insurance, excess/umbrella liability insurance and property insurance, in each case meeting specified coverage amounts or other requirements. In addition, Big West is required to maintain environmental insurance having limits of liability of at least $4,000,000 each loss and at least $8,000,000 total all losses which covers all loss or damage to the partnership’s and Big West’s property or to third parties, relating to pollution or environmental matters, including without limitation, environmental laws, environmental permits, releases, hazardous materials or remediations; such coverage shall name the partnership as a named insured.

OPCO and the partnership also are required under certain circumstances to obtain and maintain at their expense certain minimum insurance policies and coverages under individual or blanket policies.

Change of Control of General Partner. The Big West entities shall not engage in any transaction or series of transactions that results in a Change in Control (as defined) of the general partner unless the person who will control the general partner following such transaction or transactions (i) will be the owner, directly or indirectly, of the Big West facility and the interest in OPCO other than the interest that we own, (ii) has a credit rating (as determined by a nationally recognized rating agency) of at leastB1 by Moody’s or B+ by Standard & Poor’s or a credit profile that is otherwise reasonably acceptable to the Conflicts Committee, and (iii) agrees in writing to assume all of the obligations of the Big West entities under the omnibus agreement, the refining agreement, the shared services agreement, the master services agreement and the site lease. Following written assumption by such transferee of all of the Big West entities’ obligations under those agreements, thereafter the Big West entities shall be released from all obligations arising under the omnibus agreement after the date of such assignment; provided that such assumption shall not relieve any Big West entity from any obligations arising under the omnibus agreement prior to date of such assignment.

Reimbursement for Certain General and Administrative Expenses. Pursuant to the omnibus agreement, Big West will reimburse us to the extent the incremental costs we incur as a result of being a public entity exceed $1.5 million per year. These include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, director compensation and incremental insurance costs, including director and officer liability insurance.

OPCO Partnership Agreement and Big West Operating GP, LLC Limited Liability Company Agreement

We, on behalf of Big West Operating GP, LLC as its sole owner, and Big West have entered into an agreement of limited partnership for OPCO. This agreement governs the ownership and management of OPCO, designates Big West Operating GP, LLC as the general partner of OPCO, and provides for quarterly distributions of available cash to the limited and general partner, as determined by us as sole member of the general partner of OPCO.

OPCO’s partnership agreement provides that the amount of cash reserves for future maintenance capital expenditures, turnaround reserves, working capital and other matters and the amount of quarterly cash distributions to OPCO’s partners will be determined by us as the sole member of Big West Operating GP, LLC. Thus, this decision will be made by the board of directors of our general partner. This approval is also required for the following actions relating to OPCO:

• effecting any merger or consolidation involving OPCO;

• effecting any sale or exchange of all or substantially all of OPCO’s assets;

• dissolving or liquidating OPCO;

• creating or causing to exist any consensual restriction on the ability of OPCO or its subsidiaries to make distributions, pay any indebtedness, make loans or advances or transfer assets to us or our subsidiaries;

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• settling or compromising any claim, dispute or litigation directly against, or otherwise relating to indemnification by OPCO of, any of the officers of Big West Operating GP, LLC; or

• issuing additional partnership interests in OPCO.

Approval of the conflicts committee of our general partner’s board of directors will be required to amend OPCO’s partnership agreement or its general partner’s limited liability company agreement.

Administrative Services

Flying J has historically provided Big West Oil, LLC with management, administrative and accounting services for which it receives an annual fee. Flying J also provided Big West Oil, LLC with strategic and financial advisory services from time to time. Payments for these management, administrative and accounting services for the years ended January 31, 2005, 2006, 2007 and the six months ended July 31, 2007 were $1.3 million, $4.0 million, $6.7 million and $3.4 million, respectively. It is anticipated that Big West will continue to provide similar services to us and OPCO following completion of the offering.

Indemnification of Directors and Officers

Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Flying J, Big West and their affiliates) on the one hand, and our partnership and our unaffiliated limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to our unitholders and us.

The officers of OPCO’s general partner have fiduciary duties to manage OPCO in a manner beneficial to us, as such general partner’s owner. At the same time, OPCO’s general partner has a fiduciary duty to manage OPCO in a manner beneficial to OPCO’s limited partners, including Big West. The board of directors of our general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in the best interest of us or our unitholders. Our general partner’s board of directors will appoint the officers of OPCO’s general partner. The Chief Executive Officer, Chief Operating Officer and Chief Financial Officer of our general partner and all of our general partner’s non-independent directors also serve as executive officers of OPCO’s general partner and/or executive officers or directors of Flying J, Big West or their affiliates.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

• approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner or from the common unitholders, except that OPCO’s partnership agreement requires conflicts committee approval to amend either OPCO’s partnership agreement or the limited liability company agreement of OPCO’s general partner. If our general partner does not seek approval from the conflicts committee (other than for, and only with respect to, amendments to OPCO’s and OPCO’s general partner’s agreements), and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors, including the board members affected by the conflict, acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.

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Conflicts of interest could arise in the situations described below, among others.

Flying J and its affiliates are not limited in their ability to compete with us, which could limit our commercial activities or our ability to acquire additional assets or businesses.

Neither our partnership agreement nor the omnibus agreement will prohibit Flying J or its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, provided that they do not compete through the vehicle of a new publicly traded partnership that (1) conducts the business of refining crude oil or other hydrocarbon products in the continental United States or (2) owns and operates the Longhorn refined products pipeline which is currently owned by another Flying J affiliate. In addition, Flying J and its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Flying J is a large, established participant in the downstream energy business, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with it with respect to commercial activities as well as for acquisition candidates. As a result, competition from Flying J could adversely impact our results of operations and cash available for distribution.

Our general partner is allowed to take into account the interests of parties other than us, such as Flying J or its affiliates, in resolving conflicts of interest.

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. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to our partnership agreement.

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

We will not have any officers or employees and will rely solely on officers of our general partner and employees of our general partner and its affiliates. Affiliates of our general partner will conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and its affiliates.

Our partnership agreement limits our general partner’s fiduciary duties to our 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. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of our partnership or amendment to our partnership agreement;

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

• generally provides that affiliated 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 being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by the general partner in good faith. 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; 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 our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash available for distribution to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

• amount and timing of asset purchases and sales;

• cash expenditures;

• borrowings;

• the issuance of additional units; and

• the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by the general partner to our unitholders, including borrowings that have the purpose or effect of:

• enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

• hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “How We Make Cash Distributions—Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company, or its operating subsidiaries.

In addition, our general partner may use an amount, initially equal to $15.0 million, which would not otherwise constitute operating surplus, in order to permit the payment of cash distributions on the subordinated units or incentive distribution rights.

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Our general partner determines which costs incurred by our general partner are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. Please read “Certain Relationships and Related Party Transactions.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length transactions.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts, and arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, are or will be the result of arm’s-length negotiations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Our general partner’s affiliates may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. Except as provided in our partnership agreement and the omnibus agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Common units are subject to our general partner’s limited call right.

Our general partner may exercise its right to call and purchase common units as provided in our partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

The attorneys, independent accountants and others who have performed services for us regarding the offering have been retained by our general partner. Attorneys, independent accountants and others who will perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to our unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

State law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable

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law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

If our general partner does not seek approval from the conflicts committee of its board of directors and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

Rights and remedies of unitholders The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further 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 errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud, willful misconduct.

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Each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or transferee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act of 1933, as amended (“Securities Act”), in the opinion of the SEC such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “How We Make Cash Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

                 will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:

• surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

• special charges for services requested by a common unitholder; and

• other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

• represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

• automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

• gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

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Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of this agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

• with regard to distributions of available cash, please read “How We Make Cash Distributions;”

• with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”

• with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units;” and

• with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization and Duration

We were organized on December 3, 2007 and have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activities that are approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us, OPCO or its subsidiaries to engage in activities other than the refining and marketing of fuel products and specialty hydrocarbon products, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers, under our partnership agreement.

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Various matters requiring the approval of a “unit majority” require:

• during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

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• after the subordination period, the approval of a majority of the common units.

In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us and our limited partners.

Action Unitholder Approval Required

Issuance of additional units No approval right.

Amendment of our partnership agreement Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

Amendment of the partnership agreement of OPCO or the limited liability company agreement of OPCO’s general partner, or other action taken by us as an equity holder of OPCO’s general partner No approval right. However, approval by the conflicts committee of the board of directors of our general partner is required for these amendments and by our general partner’s board of directors for certain actions affecting OPCO. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—OPCO Partnership Agreement and Big West Operating GP, LLC Limited Liability Company Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances. Please read “—Merger, Sale or Other Disposition of Assets.”

Dissolution of our partnership Unit majority. Please read “—Termination and Dissolution.”

Reconstitution of our partnership upon dissolution Unit majority. Please read “—Termination and Dissolution.”

Withdrawal of our general partner Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to January 31, 2018 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of the General Partner”.

Removal of our general partner Not less than 66 ²/3% of the outstanding units, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of the General Partner.”

Transfer of the general partner interest Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its

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assets to, such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to January 31, 2018. Please read “—Transfer of General Partner Interest.”

Transfer of incentive distribution rights Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to January 31, 2018. Please read “—Transfer of Incentive Distribution Rights.”

Transfer of ownership interests in our general partner No approval required at any time. Please read “—Transfer of Ownership Interests in Our General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group to:

• remove or replace our general partner;

• approve some amendments to our partnership agreement; or

• take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

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OPCO and its subsidiaries conduct business in the state of Utah. Maintenance of our limited liability as a member of OPCO may require compliance with legal requirements in the jurisdictions in which OPCO conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our ownership or control of operating subsidiaries or OPCO or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of common units upon exercise of the underwriters’ over-allotment option or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. The general partner’s 2.0% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. In addition, upon issuance of additional partnership securities, Big West or its affiliates will have preemptive rights to purchase additional partnership securities to the extent necessary to maintain their respective percentage partnership interests in us. Otherwise, under our partnership agreement, the holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in

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the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

• enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected;

• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option;

• change the term of our partnership;

• provide that our partnership is not dissolved upon an election to dissolve our partnership by our general partner that is approved by the holders of a unit majority; or

• give any person the right to dissolve our partnership other than our general partner’s right to dissolve our partnership with the approval of the holders of a unit majority.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately 50% of the outstanding units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:

• a change in our name, the location of our principal place of our business, our registered agent or our registered office;

• the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

• a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating company nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

• an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

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• any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

• a change in our fiscal year or taxable year and related changes;

• mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger or conveyance other than those it receives by way of the merger or conveyance; or

• any other amendments substantially similar to any of the matters described in the bullet points above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee in connection with a merger or consolidation approved in connection with our partnership agreement, or if our general partner determines that those amendments:

• do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

• are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

• are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described above under “—No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

A merger or consolidation of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of

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merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, the transaction would not result in a material amendment to our partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the units to be issued do not exceed 20% of our outstanding units immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

• the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

• there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

• the entry of a decree of judicial dissolution of our partnership; or

• the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to reconstitute us and continue our business on the same terms and conditions described in our partnership agreement by forming a new limited partnership on terms identical to those in our partnership agreement and having as general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability of any limited partner; and

• neither our partnership, the reconstituted limited partnership, our operating company nor any of our other subsidiaries, would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as provided in “How We Make Cash Distributions—Cash Distributions—Distributions of Cash upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

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Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to January 31, 2018 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after January 31, 2018, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50.0% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest” and “—Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 ²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as a separate class. The ownership of more than 33 ¹/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, the owner of our general partner will own 50% of the outstanding units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:

• the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the

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departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest in our partnership to:

• an affiliate of our general partner (other than an individual); or

• another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest in our partnership to another person prior to January 31, 2018 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may, at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest of the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to January 31, 2018, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after January 31, 2018, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Big West GP, LLC as our general partner or otherwise change our management. If

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any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

• the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, but not the obligation, which right may be assigned in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:

• the highest cash price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and

• the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences—Disposition of Common Units.”

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, will be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which

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a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions. By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records.

Non-Citizen Transferees

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen transferee. A non-citizen transferee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen transferee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

• our general partner;

• any departing general partner;

• any person who is or was an affiliate of a general partner or any departing general partner;

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• any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

• any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner or any of their affiliates; and

• any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is January 31.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing our audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each taxable year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand stating the purpose of such demand and at his own expense, have furnished to him:

• a current list of the name and last known address of each partner;

• a copy of our tax returns;

• information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

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• copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

• information regarding the status of our business and financial condition; and

• any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their transferees if an exemption from the registration requirements is not available. These registration rights continue for two years following any withdrawal or removal of Big West GP, LLC as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, our general partner and its owner will hold 1,218,750 common units and 6,906,250 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an affiliate of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

• 1% of the total number of the securities outstanding; or

• the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates and their transferees have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Big West GP, LLC and its affiliates will continue to have these registration rights for two years following the withdrawal or removal of Big West GP, LLC as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

We, Big West, OPCO, our general partner and the directors and executive officers of our general partner, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Big West Oil Partners, LP.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (“IRAs”), real estate investment trusts (“REITs”) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are, to the extent noted herein, based on the accuracy of the representations made by us.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with

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respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the refining, processing, transportation, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our partnership status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, both we and OPCO will be classified as a partnership for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

(a) Neither we nor the operating company will elect to be treated as a corporation; and

(b) For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Big West Oil Partners, LP will be treated as partners of Big West Oil Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in

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street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Big West Oil Partners, LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Big West Oil Partners, LP.

The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Big West Oil Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on January 31.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending January 31, 2011, will be

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allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed with respect to that period. This difference is attributable to depreciation allocable to such unitholder. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, if gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all units, or we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than     % with respect to the period described above.

Basis of Common Units

A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses

The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50.0% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder’s tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other

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than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

• interest on indebtedness properly allocable to property held for investment;

• our interest expense attributed to portfolio income; and

• the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections

If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that

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distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

We will be treated as the successor ofBig West Oil, LLC for federal income tax purposes. Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our property at the time of the offering, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to holders of partnership interests immediately prior to such other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

• his relative contributions to us;

• the interests of all the partners in profits and losses;

• the interest of all the partners in cash flow; and

• the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election,” “—Uniformity of Units,” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

• any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

• any cash distributions received by the unitholder as to those units would be fully taxable; and

• all of these distributions would appear to be ordinary income.

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Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

Alternative Minimum Tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates

In general, the highest U.S. federal income tax rate for individuals is currently 35%, and the maximum U.S. federal income tax rate for net capital gains of an individual where the asset disposed of was held for more than twelve months at the time of disposition, is scheduled to remain at 15% for years 2008 through 2010 and then increase to 20% beginning January 1, 2011.

Section 754 Election

We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury Regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we will generally adopt as to our properties), a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150.0% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives generally used to depreciate the inside basis in such properties. Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our

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assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for his units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the unitholder’s basis in his units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units. If such a challenge were sustained, the gain from the sale of common units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A tax basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally, a built-in loss or a tax basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally unamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending January 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than January 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

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Initial Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by the general partner and its affiliates, and (ii) any other offering will be borne by our common unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. We are not entitled to any amortization deductions with respect to any goodwill held by us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss

Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as long-term capital gain or loss. Capital

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gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15% through December 31, 2010. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

• a short sale;

• an offsetting notional principal contract; or

• a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation

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Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements

A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have been terminated for 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. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending January 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than January 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of

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depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable methods and lives as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult you tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to it.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

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A foreign unitholder who sells or otherwise disposes of a unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder of a publicly traded partnership would be subject to U.S. federal income tax or withholding tax upon the sale or disposition of a unit to the extent of the unitholder’s share of the partnership’s U.S. real property holdings if he owns 5% or more of the units at any point during the five-year period ending on the date of such disposition. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names Big West GP, LLC as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

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Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

(i) a person that is not a United States person;

(ii) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(iii) a tax-exempt entity;

(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related and Assessable Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(i) for which there is, or was, “substantial authority”; or

(ii) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

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Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please see “—Administrative Matters—Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

• accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related and Assessable Penalties;”

• for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

• in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Utah, and that state imposes a personal income tax on individuals as well as an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from those jurisdictions falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN BIG WEST OIL PARTNERS, LP

BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

• whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

• whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

• whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” meaning it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25.0% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Citigroup Global Markets Inc., Lehman Brothers Inc. and UBS Securities LLC are acting as joint book-running managers of the offering and as the representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase from us, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.

Underwriter	Number of Common Units
Citigroup Global Markets Inc.
Lehman Brothers Inc.
UBS Securities LLC
Total	8,125,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the option to purchase additional units described below) if they purchase any of the common units.

The underwriters propose to offer some of the common units directly to the public at the public offering price set forth on the cover page of this prospectus and some of the common units to dealers at the public offering price less a concession not to exceed $             per common unit. The underwriters may allow, and dealers may reallow, a concession on sales to other dealers. If all of the common units are not sold at the initial offering price, the representative may change the public offering price and the other selling terms. The representatives have advised us that the underwriters do not intend sales to discretionary accounts to exceed five percent of the total number of our common units offered by them.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 1,218,750 additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering any over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment.

We, Big West Oil, LLC, our general partner and their respective subsidiaries, and the officers and directors of our general partner and Big West Oil, LLC, have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup Global Markets Inc., Lehman Brothers Inc. and UBS Securities LLC, dispose of or hedge any common units or any securities convertible into or exchangeable for our common units. Citigroup Global Markets Inc., Lehman Brothers Inc. and UBS Securities LLC in their sole discretion may release any of the securities subject to these lock-up agreements at any time without notice. Citigroup Global Markets Inc., Lehman Brothers Inc. and UBS Securities LLC have no present intent or arrangement to release any of the securities subject to these lock-up agreements. The release of any lock-up is considered on a case by case basis. Factors in deciding whether to release common units may include the length of time before the lock-up expires, the number of units involved, the reason for the requested release, market conditions, the trading price of our common units, historical trading volumes of our common units and whether the person seeking the release is an officer, director or affiliate of us.

The 180-day restricted period described in the preceding paragraph will be extended if:

• during the last 17 days of the 180-day restricted period we issue an earnings release or announce material news or a material event; or

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• prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or event.

At our request, the underwriters have reserved up to 10% of the common units for sale at the initial public offering price to persons who are directors, officers or employees, or who are otherwise associated with us, through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed units purchased by participants in the program. The common units reserved for sale under the directed unit program will be subject to 90-day lock-up agreements (or 180 days if they are sold to officers, directors or employees of our general partner), subject to extension as described above in the event of earnings releases or material announcements. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act of 1933, in connection with the sales of the directed units.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units will be determined by negotiations between our general partner and the representatives. Among the factors considered in determining the initial public offering price will be our record of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to us. We cannot assure you, however, that the prices at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

We intend to apply to list our common units on the New York Stock Exchange under the symbol “BWO.”

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

	Paid by Big West Oil Partners, LP
	No Exercise	Full Exercise
Per common unit	$	$
Total	$	$

We estimate that our portion of the total expenses of this offering, excluding underwriting discounts and commissions, will be approximately $3.1 million. In connection with financial advisory services performed for us related to the evaluation, analysis and structuring of our partnership and this offering, we will pay advisory fees to Citigroup Global Markets Inc., Lehman Brothers Inc. and UBS Securities LLC equal to an aggregate of         % of the gross proceeds of this offering (including any exercise of the underwriters’ option to purchase additional common units).

In connection with this offering, the underwriters may purchase and sell common units in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of common units in excess of the number of common units to be purchased by the underwriters in this offering, which creates a syndicate short position. “Covered” short sales are sales of common units made in an amount up to the number of common units represented by the underwriters’ option to purchase additional units. In determining the source of common units to close out the covered syndicate short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the option to purchase

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additional units. Transactions to close out the covered syndicate short involve either purchases of the common units in the open market after the distribution has been completed or the exercise of the option to purchase additional units. The underwriters may also make “naked” short sales of common units in excess of the option to purchase additional units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering. Stabilizing transactions consist of bids for or purchases of common units in the open market while this offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the representatives repurchase common units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

Any of these activities may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time without notice. Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions.

Certain of the underwriters and their affiliates have performed investment banking, commercial banking and advisory services for us, Big West, Flying J and their affiliates from time to time for which they have received customary fees and expenses. The underwriters and their affiliates may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business, for which they may in the future receive customary fees and expenses. Affiliates of Citigroup Global Markets Inc. and UBS Securities LLC serve as lenders under Big West’s revolving credit facility, for which they have received customary fees and expenses.

Because the Financial Industry Regulatory Authority views the common units offered under this prospectus as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed on a national securities exchange.

The underwriters do not expect sales to discretionary accounts to exceed five percent of the total number of common units offered.

In no event will the maximum amount of compensation to be paid to FINRA members in connection with this offering exceed 10% plus 0.5% for bona fide due diligence.

A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters. Other than the prospectus in electronic format, the information on any such website is not part of the prospectus. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. The representatives will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders. Other than the prospectus in electronic format, the information on any of the underwriters’ or selling group member’s websites and any other information contained in any other websites maintained by an underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved or endorsed by any underwriter or selling group member and should not be relied upon by investors.

We, our general partner andBig West Oil, LLC have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., New York, New York. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The financial statements of Big West Oil Predecessor as of January 31, 2007 and 2006 and for each of the years in the three-year period ended January 31, 2007 having been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of such firm as experts in accounting and auditing.

The balance sheet of Big West Oil Partners, LP as of December 3, 2007, having been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of such firm as experts in accounting and auditing.

The balance sheet of Big West GP, LLC as of December 3, 2007, having been included herein and in the registration statement in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

189

FORWARD-LOOKING STATEMENTS

This prospectus includes forward-looking statements in addition to historical information. These forward-looking statements are included throughout this prospectus, including in the sections entitled “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Refining Industry Overview” and “Business” and relate to matters such as our industry, business strategy, goals and expectations concerning our market position, future operations, margins, profitability, capital expenditures, liquidity and capital resources and other financial and operating information. We have used the words “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “will,” “future” and similar terms and phrases to identify forward-looking statements in this prospectus.

Forward-looking statements reflect our current expectations regarding future events, results or outcomes. These expectations may or may not be realized. Some of these expectations may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized or otherwise materially affect our financial condition, results of operations and cash flows.

Actual events, results and outcomes may differ materially from our expectations due to a variety of factors. Although it is not possible to identify all of these factors, they include, among others, the following:

• changes in general economic conditions and capital markets;

• changes in demand and prices for Big West’s products;

• actions of Big West’s customers and competitors;

• Big West’s ability to meet its payment obligations under the refining agreement;

• changes in our estimated maintenance capital expenditures and turnaround reserves;

• disruptions at OPCO’s or Big West’s facilities due to natural disasters, fires, explosions, pipeline ruptures and spills, third-party interference, mechanical failures or other causes;

• the execution of planned capital projects and the ability to obtain required governmental approvals and operating permits;

• the effects of and cost of compliance with current and future state and federal environmental, economic, safety and other laws, policies and regulations;

• operating hazards, natural disasters, casualty losses and other matters beyond our control; and

• the other factors discussed in more detail under “Risk Factors.”

Potential investors are urged to consider these factors and the other factors described under “Risk Factors” carefully in evaluating any forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included herein are made only as of the date of this prospectus, and we undertake no obligation to update any information contained in this prospectus or to publicly release the results of any revisions to any forward-looking statements that may be made to reflect events or circumstances that occur, or that we become aware of, after the date of this prospectus.

190

INDEX TO FINANCIAL STATEMENTS

	Page
Audited Financial Statements of Big West Oil Predecessor:
Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets as of January 31, 2006 and 2007	F-3
Statements of Income for the Years Ended January 31, 2005, 2006 and 2007	F-4
Statements of Member’s Equity and Comprehensive Income for the Years Ended January 31, 2005, 2006 and 2007	F-5
Statements of Cash Flows for the Years Ended January 31, 2005, 2006 and 2007	F-6
Notes to Financial Statements	F-7
Interim Financial Statements of Big West Oil Predecessor (unaudited):
Balance Sheets as of January 31, 2007 and July 31, 2007	F-25
Statements of Income for the Six Months Ended July 31, 2006 and 2007	F-26
Statements of Cash Flows for the Six Months Ended July 31, 2006 and 2007	F-27
Notes to Interim Financial Statements of Big West Oil Predecessor	F-28
Audited Financial Statement of Big West Oil Partners, LP:
Report of Independent Registered Public Accounting Firm	F-34
Balance Sheet as of December 3, 2007	F-35
Notes to Balance Sheet	F-36
Audited Financial Statement of Big West GP, LLC:
Report of Independent Registered Public Accounting Firm	F-37
Balance Sheet as of December 3, 2007	F-38
Notes to Balance Sheet	F-39

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors

Big West Oil, LLC:

We have audited the accompanying balance sheets of Big West Oil Predecessor (the “Company”) as of January 31, 2007 and 2006 and the related statements of income and member’s equity and comprehensive income, and cash flows for each of the years in the three-year period ended January 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in note 1 to the financial statements, the accompanying financials statements were prepared solely to present a new entity to be formed in connection with the carve-out of certain assets under the common control of Big West Oil, LLC and is not intended to be a complete presentation of the assets and liabilities of Flying J Inc. or Big West Oil, LLC.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Big West Oil Predecessor as of January 31, 2007 and 2006 and the results of its operations and its cash flows for each of the years in the three-year period ended January 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 9 to the financial statements, the Company adopted the recognition and disclosure provisions of the Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, as of January 31, 2007.

/s/    KPMG LLP

December 7, 2007

Salt Lake City, Utah

F-2

BIG WEST OIL PREDECESSOR

Balance Sheets

(Dollars in thousands)

	As of January 31,
	2006			2007
Assets
Current assets:
Cash	$	1,704		$	374
Trade receivables, net of allowance for doubtful accounts of $458 in 2006 and $612 in 2007		67,577			56,373
Trade receivables from affiliated companies		11,310			18,930
Receivable from affiliated companies		6,710			1,251
Inventories		140,370			149,920
Prepaid expenses		4,280			2,871
Total current assets		231,951			229,719
Land, buildings, and equipment:
Land and improvements		7,280			7,280
Buildings		3,711			3,711
Equipment		235,722			247,372
Construction in progress		29,969			194,180
		276,682			452,543
Less accumulated depreciation and amortization		53,873			69,856
Net land, buildings, and equipment		222,809			382,687
Other assets		20,956			46,962
Total assets	$	475,716		$	659,368
Liabilities and Member’s Equity
Current liabilities:
Current installments of long-term debt	$	6,121		$	3,271
Accounts payable		168,041			182,090
Accounts payable to affiliated companies		2,514			1,603
Accrued fuel, property, and state taxes		23,269			18,423
Other accrued liabilities		6,224			7,307
Total current liabilities		206,169			212,694
Long-term debt, excluding current installments		29,271			143,300
Other liabilities		2,695			4,345
Total liabilities		238,135			360,339
Member’s equity:
Member’s equity		238,972			301,276
Accumulated other comprehensive loss		(1,391	)		(2,247	)
Total member’s equity		237,581			299,029
Total liabilities and member’s equity	$	475,716		$	659,368

See accompanying notes to financial statements.

F-3

BIG WEST OIL PREDECESSOR

Statements of Income

(Dollars in thousands)

	Year ended January 31,
	2005			2006			2007
Sales	$	715,700		$	2,016,973		$	2,410,078
Operating costs and expenses:
Cost of products		619,726			1,729,022			2,149,090
Cost of refining		24,945			133,200			140,257
Selling, general, and administrative		4,785			10,216			12,208
Depreciation and amortization		6,130			19,220			18,748
Gain on sale of other assets		—			—			(838	)
		655,586			1,891,658			2,319,465
Income from operations		60,114			125,315			90,613
Other income (expenses):
Interest expense, net		(958	)		(2,150	)		219
Losses on derivative activities		(7,084	)		(18,106	)		(2,528	)
Total other expenses		(8,042	)		(20,256	)		(2,309	)
Net income	$	52,072		$	105,059		$	88,304

See accompanying notes to financial statements.

F-4

BIG WEST OIL PREDECESSOR

Statements of Member’s Equity and Comprehensive Income

(Dollars in thousands)

	Member’s Equity			Accumulated other comprehensive income (loss)			Total member’s equity
Balances at January 31, 2004	$	50,672		$	(1,581	)	$	49,091
Comprehensive income:
Net income		52,072			—			52,072
Other comprehensive loss—pension liability adjustment					(203	)		(203	)
Total comprehensive income								51,869
Compensation expense on stock options		269			—			269
Contribution from member		20,000			—			20,000
Distribution to member		(35,700	)		—			(35,700	)
Balances at January 31, 2005	$	87,313		$	(1,784	)	$	85,529
Comprehensive income:
Net income	$	105,059		$	—		$	105,059
Other comprehensive loss—pension liability adjustment					393			393
Total comprehensive income								105,452
Contribution from member		90,000			—			90,000
Distribution to member		(43,400	)		—			(43,400	)
Balances at January 31, 2006	$	238,972		$	(1,391	)	$	237,581
Comprehensive income:
Net income	$	88,304		$	—		$	88,304
Other comprehensive loss—pension liability adjustment					261			261
Total comprehensive income								88,565
Adjustment to initially apply FASB Statement No. 158					(1,117	)		(1,117	)
Distribution to member		(26,000	)		—			(26,000	)
Balances at January 31, 2007	$	301,276		$	(2,247	)	$	299,029

See accompanying notes to financial statements.

F-5

BIG WEST OIL PREDECESSOR

Statements of Cash Flows

(Dollars in thousands)

	Year ended January 31,
	2005			2006			2007
Cash flows from operating activities:
Net income	$	52,072		$	105,059		$	88,304
Adjustments to reconcile net income to net
Depreciation and amortization		6,130			19,220			18,748
Amortization of loan fees		165			809			827
Provision for losses on trade receivables		120			300			153
Gain on sale of fixed assets		—			(5	)		(219	)
Gain on sale of other assets		—			—			(838	)
Compensation expense on stock options		269			—			—
Changes in operating assets and liabilities:
Trade receivables		(3,634	)		(50,373	)		11,051
Trade receivables from affiliated companies		500			(2,167	)		(7,620	)
Inventories		(15,718	)		(34,681	)		(9,550	)
Prepaid expenses and other assets		(1,970	)		(12,836	)		(27,948	)
Accounts payable and accrued liabilities		11,004			138,115			(14,273	)
Accounts payable to affiliated companies		576			102			(911	)
Other liabilities		(195	)		1,826			794
Net cash provided by operating activities		49,319			165,369			58,518
Cash flows from investing activities:
Proceeds from sale of fixed assets		—			767			219
Proceeds on sale of other assets		—			—			871
Cash paid for acquisition		(10,000	)		(176,714	)		—
Capital expenditures		(21,726	)		(35,330	)		(151,418	)
Net cash used in investing activities		(31,726	)		(211,277	)		(150,328	)
Cash flows from financing activities:
Payments of debt issuance costs		(813	)		(1,065	)		(158	)
Net proceeds on revolving line of credit agreement		—			26,000			117,300
Principal payments on long-term debt obligations		(7,592	)		(12,819	)		(6,121	)
Contributions from member		20,000			90,000			—
Distributions to member		(35,700	)		(43,400	)		(26,000	)
Net proceeds from (disbursements to) affiliated companies		4,249			(11,466	)		5,459
Net cash provided by (used in) financing activities		(19,856	)		47,250			90,480
Increase (decrease) in cash		(2,263	)		1,342			(1,330	)
Cash beginning of year		2,625			362			1,704
Cash end of year	$	362		$	1,704		$	374
Supplemental disclosure of cash flows information:
Cash paid for interest, net of capitalized amounts	$	1,391		$	1,968		$	—
Supplemental schedule of non-cash operating and investing activities:
Increases (decreases) of pension obligations through other comprehensive income		203			(393	)		856
Accrued acquisition of equipment and construction in progress		19			945			24,560

See accompanying notes to financial statements.

F-6

BIG WEST OIL PREDECESSOR

Notes to Financial Statements

January 31, 2005, 2006 and 2007

(Dollars in thousands)

(1) Basis of Presentation and Description of Business

(a) Basis of Presentation

Big West Oil Predecessor (the “Company”) is comprised of operations that were formerly part of Big West Oil, LLC. Big West Oil, LLC is a wholly owned subsidiary of Flying J Inc. (Flying J). The accompanying financial statements include the accounts relating to the refining assets of Big West Oil, LLC. These financial statements assume that the Company existed as a separate legal entity for the years ended January 31, 2005, 2006, and 2007.

Historically, the Big West Oil, LLC and subsidiaries financial statements consisted of the accounts of Big West Oil, LLC, and its wholly owned subsidiaries, Big West Transportation LLC, and Big West Oil of California, LLC (“BWOC”). In addition to its refinery assets, Big West Oil, LLC also operated nine retail convenience stores offering motor fuels and merchandise throughout Utah and Idaho. Big West Oil, LLC carved out the net assets and operations of the convenience stores and Big West Transportation. In January 2005, Big West Oil, LLC formed a wholly owned subsidiary, Big West of California, LLC, to purchase a refinery located in Bakersfield, California, from Equilon Enterprises LLC, dba Shell Products US. The Bakersfield refinery was acquired March 15, 2005, and its operations have been included in the financial statements from that date.

Accounts and balances related to the included operations were based on a combination of specific identification and allocations. Overhead allocations were carved out based on historical allocations. Historically, Flying J has allocated various corporate overhead expenses based on a percentage of labor hours devoted by functional department. These allocations are not necessarily indicative of the cost that the Company would have incurred had it operated as an independent stand-alone entity for all years presented. Accounts payable was allocated by applying existing accounts payable terms to actual cost of sales for the respective portions. The Company carved out other accounts based on specific identification.

The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All transactions and balances between the combined entities and segments have been eliminated.

(b) Description and Nature of Business

The Company engages in the business of refining petroleum products operating in the Western region of the United States. The Company’s business consists of refining operations in North Salt Lake City, Utah, (the “Salt Lake refinery”) and in Bakersfield, California (the “Bakersfield refinery”). The Company acquired the Bakersfield refinery on March 15, 2005.

Products from the Company’s Salt Lake refinery, including gasoline and diesel, are sold primarily in Utah and Idaho, as well as in Nevada, Wyoming, Colorado and Oregon. Unfinished wax products produced at the Salt Lake City refinery are marketed and exported across North America. The Bakersfield refinery typically processes heavy and light crude oil from the San Joaquin Valley. Products from the Bakersfield refinery, including gasoline, diesel, gas oil, fuel oil cutter, liquid petroleum gases, petroleum coke, and other petroleum products, are sold primarily in California. During its normal course of business, the Company sells to Flying J and its affiliates certain petroleum products.

F-7

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

(2) Summary of Significant Accounting Polices

(a) Cash

The Company has historically participated in the overall cash management system of Flying J whereby periodically excess cash has been distributed to Flying J. The Company considers all investments with original maturities to the Company of three months or less to be cash equivalents. The Company did not have any cash equivalents as of January 31, 2006 or 2007.

(b) Trade Receivables

Trade receivables are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing trade receivables. The Company determines the allowance based on historical write-off experience and the composition and aging of the trade receivable balances. The Company reviews its allowance for doubtful accounts monthly. Account balances are charged off against the allowance when the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.

(c) Inventories

Inventories of crude oil and refined and purchased petroleum products are stated at the lower of cost or market value and are accounted for using the first-in, first-out (FIFO) method of accounting.

(d) Revenue Recognition

Revenues for products sold are recorded upon delivery of the products to their customers, which is the point at which title to the products is transferred, customer has assumed risk of loss, and when payment has either been received or collection is reasonably assured. The Company records these revenues net of sales and excise tax.

The Company enters into certain product exchange arrangements, which involve the receipt and delivery of products, the purposes of which are to address location, quality or grade requirements and economics. These transactions are made in contemplation of one another and are viewed as a single transaction. As a result, revenues and cost of sales are netted against each other and are not reflected in the statements of income in accordance with EITF 04-13 Accounting for purchases and sales of inventory with the same counterparty.

The Company enters into refined product exchange transactions to fulfill sales contracts with its customers by accessing refined products in markets where it does not operate its own refinery. These product exchanges are accounted for as exchanges of non-monetary assets, and no revenues are recorded on these transactions in accordance with EITF 04-13Accounting for purchases and sales of inventory with the same counterparty.

(e) Hedging Activities

The Company follows Statement of Financial Accountings Standards (SFAS) No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended, effective January 1, 2001. The Company considers all forwards, futures, and option contracts to be part of its risk management strategy. The Company has elected not to designate derivative contracts as cash flow hedges for financial accounting purposes. Accordingly, net unrealized losses for changes in the fair value on open derivative contracts are recognized in loss from derivative activities.

F-8

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

(f) Land, Buildings, and Equipment

Land, buildings, and equipment are stated at cost. Land, buildings, and equipment are depreciated using the straight-line method at rates based on the following estimated useful lives:

Land improvements	10-30 years
Refinery buildings	18-30 years
Refinery equipment	2-19 years

The Company capitalizes interest costs associated with major construction projects based on the effective interest rate on aggregate borrowings. Major construction in progress as of January 31, 2006 and 2007 related primarily to an ongoing upgrade at the Bakersfield refinery.

Expenditures for major replacements and additions are capitalized. Expenditures for routine repairs and maintenance costs are expensed as incurred. The applicable costs and accumulated depreciation of assets that are sold, retired, or otherwise disposed of are removed from the accounts and the resulting gain or loss is recognized in the statements of income.

(g) Impairment of Long-Lived Assets and Assets to be Disposed of

In accordance with Statement of Financial Accounting Standard (SFAS) No. 144,Accounting for the Impairment or Disposal of Long-lived Assets, long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of an asset exceeds its estimated undiscounted future cash flows, an impairment loss is recognized based on the excess of the carrying value of the impaired asset over its fair value. Assets to be disposed of would be separately presented in the balance sheet at the lower of the carrying amount or fair value less costs to sell. These future cash flows and fair values are estimates based on the Company’s judgment and assumptions.

(h) Pension and Other Postretirement Plans

The Company has two defined benefit pension plans covering its hourly employees upon their retirement. The benefits are based on age, years of service and the level of compensation. The Company also sponsors a defined benefit health care plan for hourly employees at its Bakersfield refinery.

The Company records annual amounts relating to its pension and postretirement plans based on calculations that incorporate various actuarial and other assumptions including, discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The Company reviews its assumptions on an annual basis and makes modifications to the assumptions based on current rates and trends when it is appropriate to do so. The effect of modifications to those assumptions is recorded in accumulated other comprehensive income beginning in 2006 and amortized to net periodic cost over future periods using the corridor method. The Company believes that the assumptions utilized in recording its obligations under its plans are reasonable based on its experience and market conditions.

F-9

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

The net periodic costs are recognized as employees render the services necessary to earn the postretirement benefits. Actuarial gains and losses are generally amortized subject to the corridor over the average remaining service life of the Company’s active employees.

(i) Asset Retirement Obligations

The Company records asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations. The Company has determined that an asset retirement obligation exists relating to its refinery assets. However, the fair value of the asset retirement obligation associated with these refinery assets cannot be reasonably estimated since the settlement dates are indefinite lived; therefore, no obligation was recorded for the refinery assets. The Company will continue to assess whether or not it would be required to record an asset retirement obligation based upon changes in facts or circumstances.

(j) Turnarounds

The Company records the cost of planned major refinery maintenance, referred to as turnarounds, in other assets in the balance sheet. Turnaround costs are currently deferred and amortized on a straight-line basis beginning upon the completion of the turnaround and ending immediately prior to the next scheduled turnaround. Amortization of turnaround costs is presented in depreciation and amortization in our statements of income.

(k) Income Taxes

Historically, the Company has not incurred income taxes because its operations were conducted as a Limited Liability Company (LLC) that was not subject to income taxes. Capital distributions are periodically made to Flying J, sole member of the LLC, to fund the tax obligations resulting from Flying J being taxed on the Company’s taxable income.

(l) Environmental Expenditures

The Company accrues for costs associated with environmental remediation obligations when such costs are probable and can be reasonably estimated. Environmental liabilities represent the estimated costs to investigate and remediate contamination at the Company’s properties. This estimate is based on internal and third-party assessments of the extent of the contaminations, the selected remediation technology and review of applicable environmental regulations. The Company does have environmental obligations for which it is required to accrue. The Company will continue to assess whether or not it would be required to change its environmental obligation based upon changes in facts or circumstances.

(m) Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

F-10

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

(n) Accounting Standards Issued and Not Yet Adopted

In September 2006, the FASB published SFAS No. 157,Fair Value Measurements (SFAS No. 157), to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS No. 157 retains the exchange price notion in earlier definition of fair value, but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or liability in the principal or most advantageous market for the asset or liability. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price), as opposed to the price that would be paid to acquire the asset or received to assume the liability at the measurement date (an entry price). SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in this Statement applies for derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, although earlier application is encouraged. The FASB has deferred until fiscal years beginning after November 15, 2008 the statement’s measurement requirements for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. The Company is evaluating the impact, if any, that SFAS No. 157 will have on the Company’s financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159), which permits entities to measure many financial instruments and certain other items at fair value at specified election dates that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected should be reported in earnings at each subsequent reporting date. The provisions of SFAS No. 159 are effective for Big West as of January 1, 2008. The Company is currently evaluating the impact this standard will have on its financial position and results of operations.

(o) Reclassifications

Certain amounts in 2006 have been reclassified to conform to the 2007 presentation.

(3) Bakersfield Refinery Acquisition

On March 15, 2005, BWOC purchased a refinery located in Bakersfield, California, from Equilon Enterprises LLC, dba Shell Products (“Bakersfield Acquisition”) for a total purchase price of approximately $186.7 million. The operations of the Bakersfield refinery have been included in the accompanying statements of income since that date. The purpose of the acquisition was to increase the Company’s overall refining capacity and expand its geographic production diversification. The Bakersfield Acquisition was funded with a $100 million equity contribution from Flying J and the Company’s operating cash and borrowings under its bank credit facility.

F-11

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

The purchase price has been allocated among the assets acquired and liabilities assumed as the date of acquisition, based on the fair values. The purchase price allocation was as follows:

	Allocation amount
Current assets:
Prepaid expenses	$	86
Inventory		55,669
Noncurrent assets:
Emissions reduction credits		4,195
Favorable terminal lease		5,378
Land and structures		5,754
Oil & gas wells		1,953
Property, plant and equipment		116,373
		189,408
Liabilities:
Accrued liabilities		(1,364	)
Oil & gas wells ARO		(1,330	)
		(2,694	)
Total purchase price	$	186,714

Concurrent with the Bakersfield Acquisition, the oil and gas wells and associated asset retirement obligation were transferred, at the allocated value listed above, to Flying J Oil & Gas, a wholly owned subsidiary of the Flying J.

The following unaudited pro forma information presents the results of operations for the year ended January 31, 2006, as if the acquisition occurred as of February 1, 2005, after giving effect to certain adjustments, including, but not limited to, depreciation and amortization of acquired assets, and interest income. These pro forma results have been prepared for comparative purposes only and do not purport to be indicative of what would have occurred had the acquisition of the Bakersfield refinery been made at the beginning of the period, nor are they indicative of future results.

	January 31, 2005			January 31, 2006
Sales	$	1,633,080		$	2,095,066
Operating cost and expenses		1,454,716			1,952,694
Other income (expense), net		(7,280	)		(20,162	)
Net income	$	171,084		$	122,210

(4) Segment Information

The Company is involved in the downstream operating segment of the petroleum industry. Activities of the downstream operations include refining crude oil and other feedstocks into petroleum products and buying and selling crude oil and refined products. As such, the Company has one reportable operating segment as defined by Financial Accounting Standards Board Statement No. 131,Disclosures About Segments of an Enterprise and Related Information.

F-12

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

(5) Financial Instruments

(a) Fair Value of Financial Instruments

The carrying value for certain short-term financial instruments that mature or re-price frequently at market rates, approximates fair value because of the immediate or short-term maturities of these financial instruments. Such financial instruments include: cash, trade and other receivables, other assets, revolving lines of credit, accounts payable, and other accrued liabilities. Because the interest rate of long-term debt approximates the current interest rates available, the carrying value of debt instruments also approximates fair market value. Derivative financial instruments are carried at fair value, which is based on quoted market prices.

(b) Derivative Financial Instruments

The Company occasionally uses crude oil and refined product commodity future contracts to reduce the financial exposure related to price changes on anticipated transactions. Crude oil and refined product forward contracts are used to facilitate the supply of crude oil to the refinery and the sale of refined products while managing price exposure. The contract fair values are recorded on the balance sheets as accounts payable or trade receivables and related loss is recorded as loss from derivative activities. Various third-party sources are used to determine fair value for the purpose of marking to market the derivative instruments at each period-end.

The fair value of the outstanding contracts was a gain/(loss) of $1,251, $0, and ($2,997) at January 31, 2005, 2006, and 2007, respectively. The Company recognized net losses of $7,084, $18,106, and $2,528 for the periods ending January 31, 2005, 2006 and 2007, respectively.

(c) Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of cash and trade receivables. The Company places its cash investments with high quality financial institutions and limits the amount of credit exposure to any one financial institution. Concentrations of credit risk with respect to trade receivables result from sales of liquid product to affiliated companies. The remaining trade receivables are due from a large number of customers comprising the Company’s customer base which are dispersed throughout the Rocky Mountain and West Coast regions of the United States. The Company routinely performs credit evaluations of its customers and maintains allowances for potential credit losses.

The Company does not believe that there is a significant credit risk associated with the Company’s derivative instruments, which are transacted through counterparties meeting established collateral and credit criteria.

(6) Significant Customers

The Company sells a variety of refined products to a diverse customer base. The Company’s affiliated companies and one non-affiliated customer each accounted for more than 10% of total revenue. In the years ending January 31, 2005, 2006, and 2007, sales to these customers accounted for 47.0%, 35.0%, and 31.0% of total sales, respectively (See note 11).

F-13

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

(7) Inventories

Carrying value of inventories consisted of the following:

	January 31,
	2006		2007
Crude oil, refined products, and blendstocks	$	131,680	$	140,756
Chemicals and additives		8,690		9,164
Total inventories	$	140,370	$	149,920

(8) Other Assets

Other assets consisted of the following:

	January 31,
	2006		2007
Refinery turnaround	$	5,176	$	31,801
Precious metals		4,533		5,276
Terminal lease		4,818		4,191
Emissions reduction credits		4,195		4,161
Financing costs, net		1,130		787
Prepaid insurance		1,104		746
Total other assets	$	20,956	$	46,962

(a) Refinery Turnaround

Turnaround costs are currently deferred and amortized on a straight-line basis beginning upon the completion of the turnaround and ending immediately prior to the next scheduled turnaround. Amortization of turnaround costs is presented in depreciation and amortization in our statements of income.

(b) Precious Metals

The Company uses precious metals that consist of reactor platinum and rhenium in the ordinary course of its refinery operations. The precious metals are recorded at cost.

(c) Terminal Lease and Emissions Reduction Credits

In connection with the Bakersfield Acquisition, a portion of the purchase price was allocated to a favorable terminal lease agreement and multiple emissions reductions credits (See note 3). The portion of the purchase price allocated to the terminal lease of $5,378 is being amortized over a 10-year life. The portion of the purchase price allocated to the emissions reductions credits of $4,195 is being amortized as they are used or sold.

(d) Financing Costs

Debt issuance costs are amortized over the term of the related debt using the effective interest method. Amortization of deferred debt issuance costs is recorded as interest expense in the accompanying statements of

F-14

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

operations. Accumulated amortization of debt issuance costs was $529, $1,026, and $1,584 for the years ended January 31, 2005, 2006, and 2007, respectively.

(9) Employee Benefit Plans

(a) Salt Lake Refinery

The Company has a voluntary 401(k) savings plan. Eligible employees may contribute up to 12.0% of their salary. The Company matches 50.0% of each employee’s contribution, up to a maximum company contribution of $1.2 per employee. Company contributions to the savings plan amounted to $119, $455, and $663 for the years ended January 31, 2005, 2006, and 2007, respectively.

In January 2007, the Company adopted SFAS No. 158, which requires companies to fully recognize the obligations associated with single-employer defined benefit pension, retiree healthcare, and other postretirement plans in their financial statements. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements. Under SFAS No. 158, a defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as components of net periodic benefit cost pursuant to SFAS No. 87, Employers’ Accounting for Pensions, or SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions. The incremental effect of applying Statement 158 on the Company’s financial position as of January 31, 2007 was as follows:

	Before application of Statement 158			Adjustments			After application of Statement 158
Liability for pension benefits—long-term or noncurrent portion	$	2,489		$	1,117		$	3,606
Total liabilities		359,222			1,117			360,339
Accumulated other comprehensive loss		(1,130	)		(1,117	)		(2,247	)
Total member’s equity		300,146			(1,117	)		299,029

The recognition provisions of Statement 158 had no effect on the statements of income for the periods presented.

F-15

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

The Company has a defined benefit pension plan that covers substantially all of its hourly employees at the Salt Lake refinery. The Company uses January 31 as the measurement date for its pension plan. Financial information related to the Company’s pension plan is presented below.

	January 31,
	2006			2007
Changes in projected benefit obligation:
Projected Benefit obligation at beginning of year	$	8,853		$	9,514
Service cost		329			327
Interest cost		506			544
Plan participants’ contributions		9			16
Actuarial (gain) loss		75			(258	)
Benefits paid		(258	)		(301	)
Projected Benefit obligation at end of year	$	9,514		$	9,842
Change in plan assets:
Fair value of plan assets at beginning of period	$	5,525		$	6,792
Actual return on plan assets		674			537
Employer contributions		842			913
Plan participants’ contributions		9			16
Benefits paid		(258	)		(301	)
Fair value of plan assets at end of period	$	6,792		$	7,957
Reconciliation of funded status:
Funded status	$	(2,722	)	$	(1,885	)
Unrecognized net loss		2,885			2,496
Additional liability		(1,391	)		—
Net amount recognized	$	(1,228	)	$	611
Amounts recognized in the balance sheet consist of:
Noncurrent assets	$	—		$	—
Current liabilities		—			—
Noncurrent liabilities		(1,228	)		(1,885	)
Accumulated other comprehensive income		1,391			2,496
Net amount recognized	$	163		$	611

See accompanying notes to financial statements.

F-16

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

Amounts recognized in accumulated other comprehensive income consist of:

	January 31,
	2006		2007
Minimum pension liability	$	1,391	$	—
Net actuarial gain (loss)		—		2,496

The accumulated benefit obligation for the pension plan was $8,019 and $8,443 at January 31, 2006 and 2007, respectively. Components of net periodic pension cost were:

	January 31,
	2005			2006			2007
Service cost	$	297		$	329		$	327
Interest cost		471			506			544
Expected return on assets		(435	)		(519	)		(636	)
Net amortization and deferral		237			273			229
Net periodic pension cost	$	570		$	589		$	464

Other changes in plan assets and benefit obligations recognized in accumulated other comprehensive income were as follows:

	January 31,
	2005		2006			2007
Adjustment to minimum liability	$	203	$	(393	)	$	(295	)
Elimination of minimum liability		—		—			1,117
Total recognized in accumulated other comprehensive income		203		(393	)		822
Total recognized in net periodic benefit cost and accumulated other comprehensive income		773	$	196		$	1,286

The estimated net actuarial loss that will be amortized from accumulated other comprehensive loss into net periodic pension cost over the next fiscal year is $230.

The weighted averages assumptions used to determine the benefit obligations as of January 31, 2006 and 2007, were as follows:

	January 31,
	2006		2007
Weighted average assumptions:
Discount rate	5.75	%	6.00	%
Expected return on plan assets	9.00		9.00
Rate of compensation increase	4.50		4.50

F-17

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

The weighted average assumptions used to determine net periodic benefit costs for the years ended January 31, 2005, 2006 and 2007 were as follows:

	January 31,
	2005		2006		2007
Discount rate	6.00	%	5.75	%	6.00	%
Expected return on plan assets	9.00		9.00		9.00
Rate of compensation increase	4.50		4.50		4.50

The Company’s expected long-term rate of return assumption on assets is 9.00%. The expected long-term rate of return is based on the portfolio as a whole and not on the sum of the returns on individual asset categories. The return is based exclusively on historical returns, without adjustments.

The Company’s weighted average asset allocations for its defined pension plan at January 31, 2006 and 2007 by asset category were as follows:

	January 31,
	2006		2007		Target
Equity securities	72	%	72	%	65-72	%
Debt securities	28		27		28-35
Other	—		1		0-1
Total	100	%	100	%	100	%

The Other category is comprised of cash equivalents and is used to fund the subsequent month’s benefit payment obligation.

The asset allocation and expected return on plan assets is set to meet the plan’s liabilities within legal investment constraints.

The investment strategy is to manage the assets of the plan to meet the long-term liabilities while maintaining sufficient liquidity to pay current benefits. This goal is primarily achieved by holding equity-like investments while investing a portion of the assets in long duration bonds in order to partially match the long-term nature of the liabilities. The company will periodically review the asset mix based upon changes in the capital markets.

The following pension benefit payments, which reflect expected future service, are expected to be paid in the indicated years:

Year ending January 31:
2008	$	319
2009		338
2010		362
2011		416
2012		494
2013-2017		3,182
Total	$	5,111

The Company expects to contribute approximately $880 for the fiscal year ending January 31, 2008, for the defined benefit pension plan.

F-18

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

As of January 31, 2006 and 2007, the accumulated benefit obligation for the Company’s pension plans was in excess of plan assets. The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for the pension plans were as follows:

	January 31,
	2006		2007
Projected benefit obligation	$	9,514	$	9,842
Accumulated benefit obligation		8,019		8,443
Fair value of plan assets		6,792		7,957

(b) Bakersfield Refinery

The Company has a defined benefit pension plan and a retiree medical plan that covers substantially all of its contract hourly employees at the Bakersfield refinery. The effective date of the plans was March 16, 2005. The Company made contributions of $0 and $148 to the plans for the years ended January 31, 2006 and 2007, respectively. As of January 31, 2007, the Company has accrued an additional $188 which it has not yet funded to the plan. The Company uses January 31 as the measurement date for its pension and retiree medical plans. Financial information related to the Company’s plans is presented below.

	Pension January 31,						Retiree Medical January 31,
	2006			2007			2006			2007
Changes in projected benefit obligation:
Projected benefit obligation at beginning of year	$	—		$	231		$	1,131		$	1,280
Service cost		231			329			94			207
Interest cost		—			13			55			65
Actuarial loss (gain)		—			(27	)		—			(222	)
Projected benefit obligation at end of year	$	231		$	546		$	1,280		$	1,330
Change in plan assets:
Fair value of plan assets at beginning of period	$	—		$	—		$	—		$	—
Actual return on plan assets		—			7			—			—
Employer contributions		—			148			—			—
Fair value of plan assets at end of period	$	—		$	155		$	—		$	—
Reconciliation of funded status:
Funded status	$	(231	)	$	(391	)	$	(1,280	)	$	(1,330	)
Unrecognized actuarial net loss (gain)					(27	)		—			(222	)
Net amount recognized	$	(231	)	$	(418	)	$	(1,280	)	$	(1,552	)
Amounts recognized in the balance sheet consist of:
Noncurrent assets	$	—		$	—		$	—		$	—
Current liabilities		—			—			—			—
Noncurrent liabilities		(231	)		(391	)		(1,280	)		(1,330	)
Accumulated other comprehensive income		—			(27	)		—			(222	)
Net amount recognized	$	(231	)	$	(418	)	$	(1,280	)	$	(1,552	)

F-19

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

Amounts recognized in accumulated other comprehensive income consisted of:

	Pension, January 31,					Retiree Medical January 31,
	2006		2007			2006		2007
Net actuarial (gain) loss	$	—	$	(27	)	$	—	$	(222	)
Total	$	—	$	(27	)	$	—	$	(222	)

The accumulated benefit obligation for the pension plan was $201 and $485 at January 31, 2006 and 2007, respectively. The components of net periodic cost were:

	January 31,					Retiree Medical January 31,
	2006		2007			2006		2007
Service cost	$	231	$	329		$	94	$	207
Interest cost		—		13			55		65
Expected return on plan assets		—		(6	)		—		—
Net periodic pension costs	$	231	$	336		$	149	$	272

The total recognized in net periodic benefit cost and other comprehensive income at January 31, 2006 and 2007 for the pension plan was $231 and $309, respectively and for the retiree medical plan was $149 and $50, respectively. The estimated net actuarial gain that will be amortized from accumulated other comprehensive loss into net periodic benefit cost over the next fiscal year is $0 for both plans.

The weighted average assumptions used to determine the benefit obligations as of January 31, 2006 and 2007 were as follows:

	January 31,				Retiree Medical January 31,
	2006		2007		2006		2007
Weighted average assumptions:
Discount rate	6.00	%	6.00	%	6.00	%	6.00	%
Expected return on plan assets	8.00		8.00		N/A		N/A
Rate of compensation increase	3.50		3.50		N/A		N/A
Health care cost trend rate—Pre-Medicare	N/A		N/A		14.50		14.50
Health care cost trend rate—Medicare	N/A		N/A		23.00		23.00

The weighted averages assumptions used to determine net periodic benefit cost as of January 31, 2006 and 2007 were as follows:

	Pension, January 31,				Retiree Medical January 31,
	2006		2007		2006		2007
Discount rate	5.60	%	5.60	%	5.60	%	5.60	%
Expected long-term return on plan assets	8.00		8.00		N/A		N/A
Rate of compensation increase	3.50		3.50		N/A		N/A
Health care cost trend rate—Pre-Medicare	N/A		N/A		14.50		14.50
Health care cost trend rate—Medicare	N/A		N/A		23.00		23.00

F-20

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

The Company’s expected long-term rate of return assumption on assets is 8.00%. The expected long-term rate of return is based on the portfolio as a whole and not on the sum of the returns on individual asset categories. The return is based exclusively on historical returns, without adjustments.

The asset allocation of the Company’s pension benefits at January 31, 2007 were as follows:

	Pension January 31, 2007
Asset Category:
Equity securities	81.00	%
Debt securities	16.00	%
Real estate	0.00	%
Other	3.00	%
Total	100.00	%

There were no plan assets at January 31, 2006. The Company maintains target allocation percentages among various asset classes based on an investment policy established for the pension plan which is designed to achieve long-term objectives of return, while mitigation against downside risk and considering expected cash flows. The current target asset allocation is 65% equity securities and 35% debt securities. The portfolio utilizes two asset allocation overlays. First, it utilizes tactical asset allocation overlay that shifts 15% of the assets to or from stocks. The portfolio also utilizes tactical equity allocation overlay that shifts equity money to the more favored asset classes.

The Company expects to contribute approximately $546 for the fiscal year ending January 31, 2008 to the defined benefit pension plan.

The expected future benefit payments are:

	Pension		Retiree Medical
Year ending January 31:
2008	$	5	$	—
2009		10		—
2010		14		—
2011		19		—
2012		23		—
2013-2017		284		347
Total	$	355	$	347

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

	1-Percentage Point Increase		1-Percentage Point Decrease
Effect on total of service and interest cost components	$	75	$	(57	)
Effect on postretirement benefit obligation	$	274	$	(216	)

F-21

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

As part of the Bakersfield Acquisition, the seller will retain the liability to provide post-retirement medical and life insurance coverage to all its qualified employees as of March 15, 2005. The Company is required to extend post-retirement medical and life insurance benefits to all qualified employees participating in the seller’s post-retirement benefits program as of March 16, 2005. The Company has recorded an obligation of $1,331, which represents the total amount of the accumulated post-retirement medical obligation as of January 31, 2007, and an offsetting receivable of the amount due from the seller of $1,255, which represents the accumulated obligation as of March 15, 2005.

(10) Long-Term Debt

A summary of the Company’s long-term debt follows:

	January 31,
	2006		2007
Revolving credit facility	$	26,000	$	143,300
Notes payable		9,392		3,271
Less current installments		6,121		3,271
Total long-term debt, excluding current installments	$	29,271	$	143,300

(a) Notes Payable

Borrowings under the term credit facility, or term loan, bear interest at the rate of 8.98% per annum. The borrowings outstanding under the term loan mature on May 31, 2007. The borrowings under the term loan are secured by a millisecond catalytic cracking unit located at the Salt Lake refinery. The term loan contains representations and warranties, affirmative, negative and financial covenants and events of default that are customary for this type of financing.

(b) Revolving Line of Credit Agreement

On March 15, 2005, the Company entered into a $130,000 revolving credit facility with a non-affiliated lender. The company has exercised their ability to increase the facility up to $200,000 by receiving additional commitments from the nonaffiliated lenders. Borrowing availability under the revolving credit facility is limited at any time to an amount equal to the lower of $200,000 and the amount of the borrowing base (as defined in the revolving credit agreement). As of January 31, 2007, the borrowing base under the revolving credit facility was limited to $167,412. The Company can borrow under the revolving credit facility using Base Rate loans, Eurodollar Rate loans, or a combination of both. The borrowings under the Base Rate loans bear interest at the Federal Funds rate plus 0.5%, and the borrowing under the Eurodollar Rate loans bear interest at the Eurodollar rate plus an amount that varies from 1.00% to 2.00% per annum based on a leverage ratio. The average borrowing rate for the reporting period has been approximately 7.32%. The borrowings under the revolving credit facility are secured by the Company’s accounts receivable and inventory. The revolving credit facility contains representations and warranties, affirmative, negative and financial covenants and events of default that the Company believes are customary for financings of this kind. The revolving credit facility matures on March 15, 2010. As of January 31, 2006 and 2007, the outstanding balance on revolving credit facility was $26,000 and $143,300, respectively, and there were no outstanding letters of credit.

F-22

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

(c) Maturity of Long-Term Debt

Aggregate maturities of long-term debt are summarized as follows:

Year ending January 31:
2008	$	3,271
2009		—
2010		—
2011		143,300
Total	$	146,571

(d) Interest Expense

Interest expense included in the accompanying statements of operations consisted of the following:

	January 31,
	2005			2006			2007
Net interest expense	$	1,837		$	1,938		$	4,451
Amortization of debt issuance costs		165			810			827
Capitalized interest		(1,044	)		(598	)		(5,497	)
Total interest expense	$	958		$	2,150		$	(219	)

(11) Related-Party Transactions

During its normal course of business, the Company sells to Flying J and its affiliates certain petroleum products. Sales of products amounted to $253,131, $427,386, and $450,300 for the years ended January 31, 2005, 2006, and 2007, respectively.

Flying J charged the Company $1,310, $3,971, and $6,730 for years ended January 31, 2005, 2006, and 2007, respectively, for management services which are included in general and administrative expenses. Management services consist of allocations from Flying J’s corporate support groups based on the percentage of time spent on each subsidiary.

During its normal course of business, the Company purchased crude oil as a raw material for its refinery from an affiliate of Flying J, in the amounts of $11,131, $16,097, and $14,441 for the years ended January 31, 2005, 2006, and 2007, respectively. The Company purchased finished petroleum products from Flying J amounting to $14,354, $10,915, and $2,893 for the years ending January 31, 2005, 2006, and 2007, respectively.

Trade receivables from affiliated companies are due from Flying J and its affiliates resulting from petroleum product sales from the refinery.

Accounts payable to affiliated companies results from crude oil and finished petroleum product purchases from Flying J and its affiliates.

Receivables from affiliated companies are the result of financing activity between the Company and Flying J.

F-23

BIG WEST OIL PREDECESSOR

Notes to Financial Statements—(Continued)

January 31, 2005, 2006 and 2007

(Dollars in thousands)

Certain employees of the Company participate in the Flying J Stock Option Plan. The Company recorded $269 of compensation expense from stock options for the year ended January 31, 2005. No compensation expense from stock options was recorded for the years ended January 31, 2006, and 2007.

(12) Commitments and Contingencies

(a) Other Commitments

In the normal course of business, the Company has long-term commitments to purchase services, such as natural gas, electricity and water for use by its refinery. The Company is also party to various refined product and crude oil supply and exchange agreements. These agreements are short-term in nature or provide terms for cancellation.

The Company is involved in legal actions resulting from the ordinary course of business. Management believes that the Company has adequate legal defenses or insurance coverage and reserves, and that the ultimate outcome of such actions will not have a material adverse effect on the Company’s financial position or results of operations.

(b) Environmental

The Company is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require the Company to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and for remediation and restoration costs. These possible obligations relate to sites owned by the Company and associated with past or present operations. The Company may in the future be involved in environmental investigations, assessments, and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the unknown timing, extent and method of the remedial actions, which may be required, and the determination of the Company’s liability in proportion to other responsible parties.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

The Company has a $30 million indemnification from the seller of the Bakersfield Refinery for any pre-existing environmental obligations. As of January 31, 2006 and 2007, the Company has estimated and accrued an environmental obligation of $630, and $0, respectively. The Company will continue to assess its estimate based upon changes in facts or circumstances.

F-24

BIG WEST OIL PREDECESSOR

Balance Sheets

(Dollars in thousands)

(unaudited)

	As of January 31, 2007			As of July 31, 2007
Assets
Current assets:
Cash	$	374		$	57,606
Trade receivables, net of allowance for doubtful accounts of $612 as of January 31, 2007 and $750 as of July 31, 2007		56,373			79,174
Trade receivables from affiliated companies		18,930			17,999
Receivable from affiliated companies		1,251			5,796
Inventories		149,920			161,306
Prepaid expenses		2,871			5,380
Total current assets		229,719			327,261
Land, buildings, and equipment:
Land and improvements		7,280			7,280
Buildings		3,711			3,988
Equipment		247,372			303,282
Construction in progress		194,180			243,758
		452,543			558,308
Less accumulated depreciation and amortization		69,856			79,343
Net land, buildings, and equipment		382,687			478,965
Other assets		46,962			45,710
Total assets	$	659,368		$	851,936
Liabilities and Member’s Equity
Current liabilities:
Current installments of long-term debt	$	3,271		$	4,000
Accounts payable		182,090			225,303
Accounts payable to affiliated companies		1,603			4,979
Accrued fuel, property, and state taxes		18,423			25,767
Other accrued liabilities		7,307			12,758
Total current liabilities		212,694			272,807
Long-term debt, excluding current installments		143,300			176,000
Other liabilities		4,345			3,708
Total liabilities		360,339			452,515
Member’s equity:
Member’s equity		301,276			401,668
Accumulated other comprehensive loss		(2,247	)		(2,247	)
Total member’s equity		299,029			399,421
Total liabilities and member’s equity	$	659,368		$	851,936

See accompanying notes to financial statements.

F-25

BIG WEST OIL PREDECESSOR

Statements of Income

(Dollars in thousands)

(unaudited)

	Six Months Ended July 31,
	2006			2007
Sales	$	1,286,035		$	1,412,664
Operating costs and expenses:
Cost of products		1,121,375			1,143,500
Cost of refining		70,516			84,578
Selling, general, and administrative		6,181			11,738
Depreciation and amortization		8,882			13,612
Gain on sale of other assets		—			(2,208	)
		1,206,954			1,251,220
Income from operations		79,081			161,444
Other income (expenses):
Interest expense, net		(581	)		451
Losses on derivative activities		(2,727	)		(4,003	)
		(3,308	)		(3,552	)
Net income	$	75,773		$	157,892

See accompanying notes to financial statements.

F-26

BIG WEST OIL PREDECESSOR

Statements of Cash Flows

(Dollars in thousands)

(unaudited)

	Six Months ended July 31,
	2006			2007
Cash flows from operating activities:
Net income	$	75,773		$	157,892
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		8,882			13,612
Amortization of loan fees		449			1,068
Provision for losses on trade receivables		170			180
Gain on sale of fixed assets		(205	)		(112	)
Gain on sale of other assets		—			(2,208	)
Changes in operating assets and liabilities:
Trade receivables		(15,564	)		(22,981	)
Trade receivables from affiliated companies		(3,321	)		931
Inventories		(25,357	)		(11,386	)
Prepaid expenses and other assets		(1,856	)		(9,545	)
Accounts payable and accrued liabilities		28,268			44,387
Accounts payable to affiliated companies		(68	)		3,376
Other liabilities		5			(637	)
Net cash provided by operating activities		67,176			174,577
Cash flows from investing activities:
Proceeds from sale of fixed assets		205			112
Proceeds from sale of other assets		—			2,208
Capital expenditures		(39,201	)		(94,203	)
Net cash used in investing activities		(38,996	)		(91,883	)
Cash flows from financing activities:
Payments of debt issuance costs		—			3,154
Proceeds under notes payable and mortgages		—			180,000
Net payments on revolving line of credit agreement		(26,000	)		(143,300	)
Principal payments on long-term debt obligations		(2,993	)		(3,271	)
Distributions to member		—			(57,500	)
Net proceeds from (distributions to) affiliated companies		494			(4,545	)
Net cash used in financing activities		(28,499	)		(25,462	)
Increase (decrease) in cash		(319	)		57,232
Cash, beginning of year		1,704			374
Cash, end of year	$	1,385		$	57,606
Supplemental disclosure of cash flows information
Cash paid for interest, net of capitalized amounts	$	124		$	—
Supplemental schedule of noncash operating and investing activities:
Accrued acquisition of equipment and construction in progress	$	1,511		$	11,621

See accompanying notes to financial statements.

F-27

BIG WEST OIL PREDECESSOR

Notes to Unaudited Interim Financial Statements

January 31, 2007 and July 31, 2007

(Dollars in thousands)

(1) Basis of Presentation and Description of Business

(a) Basis of Presentation

Big West Oil Predecessor (the “Company”) is comprised of operations that were formerly part of Big West Oil, LLC. Big West Oil, LLC is a wholly owned subsidiary of Flying J, Inc. (Flying J). The accompanying financial statements include the accounts relating to the refining assets of Big West Oil, LLC. These financial statements assume that the Company existed as a separate legal entity for the year ended January 31, 2007 and the six months ended July 31, 2007.

Historically, the Big West Oil, LLC and subsidiaries financial statements consisted of the accounts of Big West Oil LLC, and its wholly owned subsidiaries, Big West Transportation LLC, and Big West Oil of California, LLC. In addition to its refinery assets, Big West Oil, LLC also operated nine retail convenience stores offering motor fuels and merchandise throughout Utah and Idaho. Big West Oil, LLC carved out the net assets and operations of the convenience stores and Big West Transportation.

Accounts and balances related to the included operations were based on a combination of specific identification and allocations. Overhead allocations were carved out based on historical allocations. Historically, Flying J has allocated various corporate overhead expenses based on a percentage of labor hours devoted by functional department. These allocations are not necessarily indicative of the cost that the Company would have incurred had it operated as an independent stand-alone entity for all years presented. Accounts payable was allocated by applying existing accounts payable terms to actual cost of sales for the respective portions. The Company carved out other accounts based on specific identification.

The accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. All transactions and balances between the combined entities and segments have been eliminated.

In the opinion of management, the accompanying unaudited financial statements contain all adjustments, which are of a normal recurring nature, necessary to present fairly the Company’s financial position as of July 31, 2007 and results of operations and cash flows for the periods indicated. The results of operations for the six months ended July 31, 2006 and 2007 are not necessarily indicative of the results for any other period or for the year as a whole. Additionally, pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures that are normally included in annual financial statements in accordance with GAAP have been omitted. Therefore, these financial statements should be read in conjunction with the Company’s audited financial statements for the year ended January 31, 2006.

The Company is required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. The Company based its estimates on historical experience, available information and various other assumptions it believes to be reasonable under the circumstances. The Company evaluates its estimates on an ongoing basis; however, actual results may differ from these estimates under different assumptions or conditions.

(b) Description and Nature of Business

The Company engages in the business of refining petroleum products operating in the Western region of the United States. The Company’s business consists of refining operations in North Salt Lake City,

F-28

BIG WEST OIL PREDECESSOR

Notes to Unaudited Interim Financial Statements—(Continued)

January 31, 2007 and July 31, 2007

(Dollars in thousands)

Utah, (the “Salt Lake refinery”) and in Bakersfield, California (the “Bakersfield refinery”). The Company acquired the Bakersfield refinery on March 15, 2005.

Products from the Company’s Salt Lake refinery, including gasoline and diesel, are sold primarily in Utah and Idaho, as well as in Nevada, Wyoming, Colorado and Oregon. Unfinished wax products produced at the Salt Lake City refinery are marketed and exported across North America. The Bakersfield refinery typically processes heavy and light crude oil from the San Joaquin Valley. Products from the Bakersfield refinery, including gasoline, diesel, gas oil, fuel oil cutter, liquid petroleum gases, petroleum coke, and other petroleum products, are sold primarily in California. During its normal course of business, the Company sells to Flying J and its affiliates certain petroleum products.

(2) Summary of Significant Accounting Polices

(a) Accounting Standards Issued and Not Yet Adopted

In September 2006, the FASB published SFAS No. 157,Fair Value Measurements (SFAS No. 157), to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS No. 157 retains the exchange price notion in earlier definition of fair value, but clarifies that the exchange price is the price in an orderly transaction between market participants to sell an asset or liability in the principal or most advantageous market for the asset or liability. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price), as opposed to the price that would be paid to acquire the asset or received to assume the liability at the measurement date (an entry price). SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in this Statement applies for derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, although earlier application is encouraged. The FASB has deferred until fiscal years beginning after November 15, 2008 the statement’s measurement requirements for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis. The Company is evaluating the impact, if any, that SFAS No. 157 will have on the Company’s financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159), which permits entities to measure many financial instruments and certain other items at fair value at specified election dates that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been elected should be reported in earnings at each subsequent reporting date. The provisions of SFAS No. 159 are effective for Big West as of January 1, 2008. The Company is currently evaluating the impact this standard will have on its financial position and results of operations.

(3) Financial Instruments

(a) Derivative Financial Instruments

The Company occasionally uses crude oil and refined product commodity future contracts to reduce the financial exposure related to price changes on anticipated transactions. Crude oil and refined product forward

F-29

BIG WEST OIL PREDECESSOR

Notes to Unaudited Interim Financial Statements—(Continued)

January 31, 2007 and July 31, 2007

(Dollars in thousands)

contracts are used to facilitate the supply of crude oil to the refinery and the sale of refined products while managing price exposure. The contract fair values are recorded on the balance sheets as accounts payable or trade receivables and related loss is recorded as loss from derivative activities. Various third-party sources are used to determine fair value for the purpose of marking to market the derivative instruments at each period-end.

The fair value of the outstanding contracts was a loss of $3,132 and $4,003 at July 31, 2006 and 2007, respectively. The Company recognized net losses of $2,727 and $4,003 for the periods ending July 31, 2006 and 2007, respectively.

(b) Concentration of Credit Risk

Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of cash and trade receivables. The Company places its cash investments with high quality financial institutions and limits the amount of credit exposure to any one financial institution. Concentrations of credit risk with respect to trade receivables result from sales of liquid product to affiliated companies. The remaining trade receivables are due from a large number of customers comprising the Company’s customer base which are dispersed throughout the Rocky Mountain and West Coast regions of the United States. The Company routinely performs credit evaluations of its customers and maintains allowances for potential credit losses.

The Company does not believe that there is a significant credit risk associated with the Company’s derivative instruments, which are transacted through counterparties meeting established collateral and credit criteria.

(4) Inventories

Carrying value of inventories consisted of the following:

	January 31 2007		July 31 2007
Crude oil, refined products, and blendstocks	$	140,756	$	151,065
Chemicals and additives		9,164		10,241
Total inventories	$	149,920	$	161,306

(5) Employee Benefit Plans

(a) Salt Lake Refinery

The Company has a defined benefit pension plan and a retiree medical plan that covers substantially all of its contract hourly employees at the Salt Lake Refinery. The Company made contributions of $531 and $377 to the plans for the six months ended July 31, 2006 and 2007, respectively.

	July 31
	2006			2007
Service cost	$	165		$	157
Interest cost		253			293
Expected return on assets		(260	)		(365	)
Net amortization and deferral		137			92
Net periodic pension cost	$	295		$	177

F-30

BIG WEST OIL PREDECESSOR

Notes to Unaudited Interim Financial Statements—(Continued)

January 31, 2007 and July 31, 2007

(Dollars in thousands)

The Company expects to contribute approximately $880 for the fiscal year ending January 31, 2008, for the defined benefit pension plan.

(b) Bakersfield Refinery

The Company has a defined benefit pension plan and a retiree medical plan that covers substantially all of its contract hourly employees at the Salt Lake Refinery. The Company made contributions of $0 and $117 to the plans for the six months ended July 31, 2006 and 2007, respectively.

	Pension July 31					Retiree Medical July 31
	2006		2007			2006		2007
Service cost	$	116	$	186		$	47	$	116
Interest cost		—		18			28		41
Expected return on assets		—		(15	)		—		—
Net amortization and deferral		—		—			—		(1	)
Net periodic pension cost	$	116	$	189		$	75	$	156

The Company expects to contribute approximately $546 and $0 for the fiscal year ending January 31, 2008 to the defined benefit pension plan and retiree medical plan, respectively.

(6) Long-Term Debt

A summary of the Company’s long-term debt follows:

	January 31, 2007		July 31, 2007
Revolving credit facility	$	143,300	$	—
Notes payable		3,271		—
Term loan		—		180,000
Less current installments		3,271		4,000
Total long-term debt, excluding current installments	$	143,300	$	176,000

(a) Term Loan

On May 15, 2007 the Company entered into a $400,000 term loan credit agreement with a syndicated group of lenders. The Company initially drew $180,000 on the facility and can make two additional draws up to the $220,000 no later than August 31, 2008. The Company can borrow under the revolving credit facility using base rate loans, eurodollar rate loans, or a combination of both. The borrowings under the base rate loans bear interest at the Federal Funds rate plus an amount that varies from 1.00% to 1.25% based on a leverage ratio, and the borrowing under the Eurodollar Rate loans bear interest at the Eurodollar rate plus an amount that varies from 1.00% to 2.00% per annum based on a leverage ratio. The borrowings under the credit facility are secured by all the Company’s assets. The credit facility contains representations and warranties, affirmative, negative and financial covenants and events of default that the Company believes are customary for financings of this kind. The term loan matures May 15, 2014.

F-31

BIG WEST OIL PREDECESSOR

Notes to Unaudited Interim Financial Statements—(Continued)

January 31, 2007 and July 31, 2007

(Dollars in thousands)

(7) Member’s Equity

The Company paid dividends of $0 and $57,500 for the six months ended July 31, 2006 and 2007, respectively.

(8) Related-Party Transactions

During its normal course of business, the Company sells to Flying J and its affiliates certain petroleum products. Sales of products amounted to $238,506 and $243,348 for the six months ended July 31, 2006 and 2007, respectively.

Flying J charged the Company $3,365 for each of the six months ended July 31, 2006 and 2007, respectively, for management services which are included in general and administrative expenses. Management services consist of allocations from Flying J’s corporate support groups based on the percentage of time spent on each subsidiary.

During its normal course of business the Company purchases crude oil as a raw material for its refinery from an affiliate of Flying J, in the amounts of $7,995 and $6,031 for the six months ended July 31, 2006 and 2007, respectively. The Company purchased finished petroleum products from Flying J amounting to $1,572 and $155 for the six months ending July 31, 2006 and 2007, respectively.

Trade receivables from affiliated companies are due from Flying J and its affiliates resulting from petroleum product sales from the refinery.

Accounts payable to affiliated companies results from crude oil and finished petroleum product purchases from Flying J and its affiliates.

Receivables from affiliated companies are the result of financing activity between the Company and Flying J.

(9) Commitments and Contingencies

(a) Other Commitments

In the normal course of business, the Company has long-term commitments to purchase services, such as natural gas, electricity and water for use by its refinery. The Company is also party to various refined product and crude oil supply and exchange agreements. These agreements are short-term in nature or provide terms for cancellation.

The company is involved in legal actions resulting from the ordinary course of business. Management believes that the Company has adequate legal defenses or insurance coverage and reserves, and that the ultimate outcome of such actions will not have a material adverse effect on the Company’s financial position or results of operations.

(b) Environmental

The Company is subject to loss contingencies pursuant to federal, state, and local environmental laws and regulations. These rules regulate the discharge of materials into the environment and may require the Company

F-32

BIG WEST OIL PREDECESSOR

Notes to Unaudited Interim Financial Statements—(Continued)

January 31, 2007 and July 31, 2007

(Dollars in thousands)

to incur future obligations to investigate the effects of the release or disposal of certain petroleum, chemical, and mineral substances at various sites; to remediate or restore these sites; to compensate others for damage to property and natural resources and for remediation and restoration costs. These possible obligations relate to sites owned by the Company and associated with past or present operations. The Company may in the future be involved in environmental investigations, assessments, and cleanups. The magnitude of future costs will depend on factors such as the unknown nature and contamination at many sites, the unknown timing, extent and method of the remedial actions, which may be required, and the determination of the Company’s liability in proportion to other responsible parties.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. The level of future expenditures for environmental remediation obligations is impossible to determine with any degree of reliability.

F-33

Report of Independent Registered Public Accounting Firm

Management and Partners of

Big West Oil Partners, LP:

We have audited the accompanying balance sheet of Big West Oil Partners, LP (the “Partnership”) as of December 3, 2007. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material aspects, the financial position of Big West Oil Partners, LP as of December 3, 2007, in conformity with U.S. generally accepted accounting principles.

/s/    KPMG LLP

Salt Lake City, Utah

December 7 , 2007

F-34

BIG WEST OIL PARTNERS, LP

AUDITED BALANCE SHEET

	As of December 3, 2007
Assets
Current:
Cash and cash equivalents	$	1,000
Total assets	$	1,000
Partners’ Equity
Limited partner	$	980
General partner		20
Total partners’ equity	$	1,000

F-35

BIG WEST OIL PARTNERS, LP

Notes to Audited Balance Sheet

(1) Nature of Operations

Big West Oil Partners, LP, a Delaware limited partnership (or thePartnership), was formed on December 3, 2007 to ultimately own a 35.0% interest in Big West Oil Operating, LP (orOPCO), including a 34.999% limited partner interest held directly by the Partnership and a 0.001% general partner interest held through its ownership of Big West Operating GP, LLC, OPCO’s sole general partner. The Partnership’s general partner (or theGeneral Partner), is wholly owned by Big West Holdings, LLC. Big West Holdings, LLC is wholly owned by Big West Oil, LLC (orBig West), which is a wholly owned subsidiary of Flying J Inc. The Partnership intends to obtain its interests in OPCO in connection with the initial public offering of the Partnership’s common units (theOffering).

(2) Subsequent Events (Unaudited)

At the closing of the Offering, the following are among the transactions that are expected to occur:

• the contribution to OPCO of the Salt Lake refinery’s milli-second catalytic cracking and alkylation units and related assets of Big West Oil, LLC;

• the transfer by Big West to the Partnership of a 34.999% limited partner interest in OPCO and a 100.0% interest in Big West Operating GP, LLC, which holds a 0.001% general partner interest in OPCO;

• the issuance by the Partnership to subsidiaries of Big West Oil, LLC of 1,218,750 common units, 6,906,250 subordinated units, the 2.0% general partner interest represented by 331,633 general partner units and all of the Partnership’s incentive distribution rights;

• the sale by the Partnership of 8,125,000 common units to the public in the Offering and the use of the net proceeds to purchase approximately $130.0 million of certificates of deposit, which will be used to secure the secured term loan pursuant to the Partnership’s new credit facility and to make an $18.0 million distribution to Big West;

• the entry by the Partnership into a new $130.0 million senior secured term loan and a $151.0 million unsecured term loan and distribution of the net proceeds of $280.0 million to Big West;

• the entry by OPCO into a refining agreement with Big West pursuant to which OPCO will process feedstocks provided by Big West for per barrel refining fees;

• the entry by the Partnership and OPCO into various other agreements with Big West relating to the operation of OPCO’s units, the sharing of various site services, a site lease and related easements and other matters; and

• the entry by the Partnership and OPCO into an omnibus agreement with Big West, Flying J, the General Partner and other affiliates governing, among other things, indemnification obligations, the Partnership’s grant to Big West of a right of first refusal on any proposed transfer of certain assets, restrictions on Flying J’s right to compete with the Partnership and Big West’s agreement to reimburse the Partnership for certain general and administrative expenses.

F-36

Report of Independent Registered Public Accounting Firm

The Board of Directors

Big West GP, LLC:

We have audited the accompanying balance sheet of Big West GP, LLC (the “General Partner”) as of December 3, 2007. This financial statement is the responsibility of the General Partner’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material aspects, the financial position of Big West GP, LLC as of December 3, 2007, in conformity with U.S. generally accepted accounting principles.

/s/     KPMG LLP

Salt Lake City, Utah

December 7, 2007

F-37

BIG WEST GP, LLC

AUDITED BALANCE SHEET

	As of December 3, 2007
Assets
Current:
Cash and cash equivalents	$	980
Investment in Big West Oil Partners, LP		20
Total assets	$	1,000
Member’s Equity
Member’s equity	$	1,000
Total member’s equity	$	1,000

F-38

BIG WEST GP, LLC

Note to Audited Balance Sheet

(1) Nature of Operations

Big West GP, LLC (or theCompany), a Delaware limited liability company, was formed on December     , 2007 to become the general partner of Big West Oil Partners, LP (or thePartnership). The Company is a wholly owned subsidiary of Big West Holdings, LLC, a Delaware limited liability company, which is a wholly owned subsidiary of Big West Oil, LLC, a Delaware limited liability company. On December 3, 2007, Big West Holdings, LLC contributed $1,000 to the Company in exchange for a 100.0% ownership interest. The Company has invested $20 in the Partnership for its 2.0% general partner interest. There have been no other transactions involving the Company as of December 3, 2007.

(2) Subsequent Events (Unaudited)

The Partnership anticipates filing a registration statement for an initial public offering of its units.

F-39

APPENDIX A

FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF

BIG WEST OIL PARTNERS, LP

[to come]

A-1

APPENDIX B

GLOSSARY OF SELECTED TERMS

The following are definitions of certain industry terms used in this prospectus.

Alkylation A process in which low-value, intermediate refining by-products are combined in the presence of a catalyst to produce alkylate.

Alkylate A high-value, high octane blending agent for gasoline.

Barrel A common unit of measure which equates to 42 U.S. gallons.

Black wax A relatively inexpensive high paraffin crude oil that is low in sulfur content but is difficult for many refineries to process.

Blendstocks Various liquid compounds such as natural gasoline, butanes, alkylate, iso-octane, and ethanol which require no further processing before being blended with other refining compounds to produce gasoline.

bpd Barrels per day.

By-products Lower-value products that result when high value products such as gasoline and diesel fuel are produced from crude oil through the refining process; examples of by-products include black oil, sulfur, propane, and petroleum coke.

Catalyst A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.

Catalytic cracking The refining process of using a catalyst to break larger, heavier, and more complex hydrocarbon molecules into simpler, lighter molecules such as gasoline, also “cat cracking.”

Crack spread The theoretical gross margin that would be realized by refining one barrel of crude oil into high-value refined products such as gasoline and diesel. For example, a 3/2/1 crack spread typically approximates the gross margin that would result if one barrel of crude oil were refined, or cracked, into two-thirds of a barrel of gasoline and one-third of a barrel of diesel.

Crude oil A mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities.

Crude oil throughput capacity The amount of crude oil that can be processed by a unit or a refinery.

Crude unit A distillation unit at the front end of a refinery that separates the hydrocarbon components in crude oil based on their relative boiling points at atmospheric pressure.

Distillates A general classification of refined petroleum products that includes diesel fuel, distillate fuel oil, jet fuel and kerosene.

Feedstocks Inputs to a refining unit or process—can include crude oil, natural gas liquids, etc.

B-1

Fluid catalytic cracking unit A refining unit that uses fluidized bed technology to perform catalytic cracking.

Fuel oil A low-grade fuel primarily used in industrial boilers and in marine applications.

Gas oil Primary feed to a catalytic cracking unit which has a viscosity between that of distillates and vacuum tower bottoms.

Heavy crude oil A crude oil characterized by high relative density and viscosity. Because heavy crude oil requires more processing than light crude oil to produce the same percentage of high value products, heavy crude oil typically costs less than light crude oil.

Hydrotreater A refinery process unit that uses hydrogen to remove undesirable compounds such as sulfur and nitrogen from gasoline, kerosene, diesel, and intermediates such as gas oil.

Independent refiner A refiner that does not have crude oil exploration or production operations. Independent refiners process crude oil purchased from third parties.

Intermediate products Products of the refining process that must be further processed to yield higher-value products.

LA CARB Los Angeles California Air Resources Board.

LA CARBOB Los Angeles California Reformulated Gasoline Blendstock for Oxygenate Blending.

Light crude oil A crude oil characterized by low relative density and viscosity. Because light crude oil requires less processing than heavy crude oil to produce the same percentage of high value products, light crude oil typically costs more than heavy crude oil.

Liquefied petroleum gas Light hydrocarbon gases such as propane and butane which are held in the liquid state by pressure to facilitate storage, transport and handling.

MMBTU Million British thermal units: A measure of energy. One Btu of heat is required to raise the temperature of one pound of water by one degree Fahrenheit.

MSCC Milli-second catalytic cracking. A type of catalytic cracking unit.

Naphtha A light hydrocarbon fraction extracted from crude oil during the refining process. Naphtha can be blended directly with gasoline or processed further to make octane. Typically serves as feed to a reformer unit.

Nelson Complexity Rating The Nelson complexity rating provides a measure of how complex a refinery is relative to others in the industry, with higher ratings indicating higher conversion capability to refine products from sour or heavy crude oils. Complexity ratings are calculated by refiners using a standard calculation process.

NYMEX New York Mercantile Exchange.

B-2

OPIS Oil Price Information Service. An independent provider of energy-related information and commodity pricing data.

PADD I East Coast Petroleum Area for Defense District.

PADD II Midwest Petroleum Area for Defense District.

PADD III Gulf Coast Petroleum Area for Defense District.

PADD IV Rocky Mountains Petroleum Area for Defense District.

PADD V West Coast Petroleum Area for Defense District.

Platt’s An independent provider of energy-related information and commodity pricing data.

Refined products Hydrocarbon compounds, such as gasoline, diesel fuel, jet fuel and residual fuel, that are produced by a refinery.

Reformer unit A refining unit that uses a platinum/rhenium catalyst to modify intermediate products such as naptha into high-octane gasoline.

Reformulated gasoline A cleaner-burning gasoline that reduces smog and other air pollution.

Sweet crude oil A crude oil that is relatively low (<0.5%) in sulfur content. Sweet crude oil is typically more expensive than sour crude oil.

SWWS Light, sweet crude produced in the southwest region of Wyoming. It is the condensate associated with natural gas production in the region.

Syncrude A light sweet crude oil produced from the upgrading of Canadian oil sands heavy crude oil.

Throughput The volume of feedstock (including but not limited to crude oil) processed through a unit or a refinery.

Turnaround A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units.

Unfinished wax One of two vacuum distillation fractions produced from yellow wax gas oil. The vacuum gas oil was sold to wax refiners who produced various finished wax products. The heavy vacuum gas oil was sold primarily as a component in the production of fire logs.

Utilization Ratio of actual refinery crude throughput to the rated crude oil throughput capacity.

Vacuum distillation A refining process which uses low pressure to reduce the boiling point of the feedstock so that the hydrocarbon mixture can be separated without cracking or decomposition.

WTI West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 38 and 40 and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.

B-3

Yellow wax A light, high paraffin crude oil that is relatively low in sulfur content.

Yield The percentage of refined products that are produced from feedstocks.

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[LOGO]

            Common Units

Representing Limited Partner Interests

Big West Oil Partners, LP

PROSPECTUS

                    , 2008

Citi Lehman Brothers UBS Investment Bank

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee, the Financial Industry Regulatory Authority Inc. filing fee, and the New York Stock Exchange listing fee the amounts set forth below are estimates.

SEC registration fee		$	6,024
Financial Industry Regulatory Authority Inc. filing fee			20,422
Printing and engraving expenses			*
Fees and expenses of legal counsel	��		*
Accounting fees and expenses			*
Transfer agent and registrar fees			*
NYSE listing fee			*
Miscellaneous			*
Total			*

* To be provided by amendment.

Item 14. Indemnification of Officers and Members of Our General Partner’s Board of Directors.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to the Underwriting Agreement to be filed as an exhibit to this registration statement in which Big West GP, LLC and certain of its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.

Item 15. Recent Sales of Unregistered Securities.

On December 3, 2007, in connection with the formation of Big West Oil Partners, LP (the “Partnership”) the Partnership issued to (i) Big West GP, LLC the 2.0% general partner interest in the Partnership for $20.00 and (ii) Big West Holdings, LLC the 98.0% limited partner interest in the Partnership for $980.00. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities.

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Item 16. Exhibits and Schedules.

(a) Exhibits

The following documents are filed as exhibits to this registration statement:

Exhibit Number		Description
1.1*	—	Form of Underwriting Agreement
3.1	—	Certificate of Limited Partnership of Big West Oil Partners, LP
3.2*	—	Form of Amended and Restated Limited Partnership Agreement of Big West Oil Partners, LP (included as Appendix A to the Prospectus and including specimen unit certificate for the common units)
3.3	—	Certificate of Formation of Big West GP, LLC
3.4*	—	Amended and Restated Limited Liability Company Agreement of Big West GP, LLC
3.5*	—	Certificate of Limited Partnership of Big West Oil Operating, LP
3.6*	—	Form of Amended and Restated Agreement of Limited Partnership of Big West Oil Operating, LP
5.1*	—	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1*	—	Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*	—	Form of Credit Facility
10.2*	—	Big West Oil GP, LLC Long-Term Incentive Plan
10.3*	—	Form of Contribution, Conveyance and Assumption Agreement
10.4*	—	Form of Unit Option Award Agreement
10.5*	—	Omnibus Agreement among Flying J Inc., Big West Oil, LLC, Big West GP, LLC, Big West Oil Partners, LP, Big West Operating GP, LLC and Big West Oil Operating LP
10.6*	—	Catalytic Cracking and Alkylation Refining Agreement between Big West Oil, LLC and Big West Oil Operating, LP
10.7*	—	Shared Services Agreement between Big West Oil, LLC and Big West Oil Operating, LP
10.8*	—	Master Services Agreement among Big West Oil, LLC and Big West Oil Operating, LP
10.9*	—	Site Lease Agreement between Big West Oil, LLC and Big West Oil Operating, LP
21.1*	—	List of Subsidiaries of Big West Oil Partners, LP
23.1	—	Consent of KPMG LLP
23.2*	—	Consent of Vinson & Elkins L.L.P.
23.3*	—	Consent of Vinson & Elkins L.L.P.
24.1	—	Powers of Attorney (contained on page II-4)

* To be filed by amendment

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Item 17. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Big West GP, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Big West GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Ogden, State of Utah, on December 7, 2007.

Big West Oil Partners, LP
By:	Big West GP, LLC, its General Partner
By:	/S/    J PHILLIP ADAMS
	J Phillip Adams President, Chief Executive Officer and Chairman of the Board

Each person whose signature appears below appoints J. Phillip Adams, Robert L. Inkley and Scott Clayson, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/S/    J PHILLIP ADAMS         J Phillip Adams	Chief Executive Officer and Chairman of the Board (Principal Executive Officer)	December 7, 2007
/S/    FRED L. GREENER         Fred L. Greener	Chief Operating Officer and Director	December 7, 2007
/S/    SCOTT G. MCMILLAN         Scott G. McMillan	Chief Financial Officer and Director (Principal Financial and Accounting Officer)	December 7, 2007
/S/    ROBERT L. INKLEY         Robert L. Inkley	Director	December 7, 2007
/S/    JEFFREY O. FOOTE         Jeffrey O. Foote	Director	December 7, 2007

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