Sooner 10-Q 2005 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005.

OR

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

FOR THE TRANSITION PERIOD FROM                    TO                    .

COMMISSION FILE NO. 0-21911

SYNTROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	73-1565725
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
4322 South 49thWest Ave. Tulsa, Oklahoma	74107
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (918) 592-7900

Not Applicable

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES  x    NO  ¨.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES  x    NO  ¨.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES  ¨    NO  x.

At November 1, 2005, the number of outstanding shares of the issuer’s common stock was 55,533,584.

SYNTROLEUM CORPORATION

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements.
	Unaudited Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004	1
	Unaudited Consolidated Statements of Operations for the three-month and nine-month periods ended September 30, 2005 and 2004	2
	Unaudited Consolidated Statements of Stockholders’ Equity for the nine-month period ended September 30, 2005	3
	Unaudited Consolidated Statements of Cash Flows for the nine-month periods ended September 30, 2005 and 2004	4
	Notes to Unaudited Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Submission of Matters to a Vote of Security Holders	34
Item 5.	Other Information	34
Item 6.	Exhibits	34
SIGNATURES		35

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes forward-looking statements as well as historical facts. These forward-looking statements include statements relating to the Syntroleum Process and related technologies including Synfining, gas-to-liquids (“GTL”) and coal-to-liquids (“CTL”) plants based on the Syntroleum Process, including our barge or ship-mounted GTL plants, anticipated costs to design, construct and operate these plants, the timing of commencement and completion of the design and construction of these plants, expected production of ultra-clean diesel fuel, obtaining required financing for these plants and our other activities, the economic construction and operation of GTL and CTL plants, the value and markets for plant products, testing, certification, characteristics and use of plant products, the continued development of the Syntroleum Process (alone or with co-venturers), our sub-quality gas monetization project and the economic production of oil and gas reserves, anticipated capital expenditures, anticipated expense reductions, anticipated cash outflows, anticipated expenses, use of proceeds from our equity offerings, anticipated revenues, availability of catalyst materials, our support of and relationship with our licensees, and any other statements regarding future growth, cash needs, capital availability, operations, business plans and financial results. When used in this document, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, these kinds of statements involve risks and uncertainties. Actual results may not be consistent with these forward-looking statements. Important factors that could cause actual results to differ from these forward-looking statements are described in this Quarterly Report on Form 10-Q and under the caption “Risk Factors” in Item  1 of our Annual Report on Form 10-K for the year ended December 31, 2004.

As used in this Quarterly Report on Form 10-Q, the terms “we,” “our” or “us” mean Syntroleum Corporation, a Delaware corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

SYNTROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share data)

	September 30, 2005			December 31, 2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	82,024		$	31,573
Restricted cash		3,776			221
Accounts receivable		512			632
Note receivable		1,804			—
Other current assets		621			1,530
Total current assets		88,737			33,956
PROPERTY AND EQUIPMENT:
Oil and gas properties, using full cost method, including $5,533 on September 30, 2005 and $4,746 on December 31, 2004 excluded from amortization		11,989			4,822
Gas processing equipment		1,583			545
Other property, plant, and equipment		7,761			6,852
Accumulated depletion, depreciation and amortization		(11,311	)		(4,486	)
Total property and equipment		10,022			7,733
NOTE RECEIVABLE		—			1,809
OTHER ASSETS, net		3,050			1,253
	$	101,809		$	44,751
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	5,058		$	3,257
Accrued liabilities		1,037			2,201
Current deferred revenue		—			5,873
Current maturities of convertible debt		25,496			—
Total current liabilities		31,591			11,331
LONG-TERM CONVERTIBLE DEBT		—			24,221
OTHER NONCURRENT LIABILITIES		93			115
STRANDED GAS VENTURE		3,229			—
DEFERRED REVENUE		21,405			21,702
MINORITY INTERESTS		706			706
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY:
Preferred stock, $0.01 par value, 5,000 shares authorized, no shares Outstanding		—			—
Common stock, $0.01 par value, 150,000 shares authorized, 63,131 and 54,482 shares outstanding as of September 30, 2005 and December 31, 2004, respectively, including shares in treasury		631			545
Additional paid-in capital		316,228			228,295
Deferred compensation		(2,875	)		(577	)
Accumulated deficit		(269,122	)		(241,510	)
		44,862			(13,247	)
Less-treasury stock, 7,675 shares at cost		(77	)		(77	)
Total stockholders’ equity		44,785			(13,324	)
	$	101,809		$	44,751

The accompanying notes are an integral part of these unaudited consolidated balance sheets.

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SYNTROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share data)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2005			2004			2005			2004
REVENUES:
Joint development revenues	$	616		$	215		$	7,044		$	612
Catalyst materials revenues		—			—			—			5,674
Gas Sales		9			—			70			—
Other revenues		92			—			98			3
Total revenues		717			215			7,212			6,289
COST AND EXPENSES:
Cost of catalyst materials sales		—			—			—			3,033
Leased operating expenses		2			—			16			—
Catoosa Demonstration Facility		2,456			3,764			7,039			10,161
Pilot plant, engineering and research and development		2,980			2,228			7,586			7,026
Depreciation, depletion, amortization and impairment		6,118			150			7,499			440
General, administrative and other (Including non-cash equity compensation of $552 and $1,234 for the three months ended September 30, 2005 and 2004, respectively, and $3,788 and $3,151 for the nine months ended September 30, 2005 and 2004, respectively.)		4,955			5,656			17,163			15,786
OPERATING INCOME (LOSS)		(15,794	)		(11,583	)		(32,091	)		(30,157	)
INVESTMENT AND INTEREST INCOME		785			178			1,731			682
INTEREST EXPENSE		(430	)		(454	)		(1,275	)		(1,338	)
OTHER INCOME (EXPENSE)		2			(200	)		3,730			(420	)
FOREIGN EXCHANGE GAIN		23			(416	)		293			589
INCOME (LOSS) BEFORE INCOME TAXES		(15,414	)		(12,475	)		(27,612	)		(30,644	)
INCOME TAXES		—			—			—			(12	)
NET INCOME (LOSS)	$	(15,414	)	$	(12,475	)	$	(27,612	)	$	(30,656	)
BASIC AND DILUTED NET INCOME (LOSS) PER SHARE	$	(0.28	)	$	(0.27	)	$	(0.52	)	$	(0.72	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING, BASIC AND DILUTED		55,443			45,729			52,888			42,474

The accompanying notes are an integral part of these unaudited consolidated statements.

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SYNTROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(in thousands)

	Common Stock					Additional Paid-In Capital			Deferred Compensation			Accumulated Deficit			Treasury Stock			Total Stockholders’ Equity
	Number of Shares		Amount
BALANCE, December 31, 2004	54,482		$	545		$	228,295		$	(577	)	$	(241,510	)	$	(77	)	$	(13,324	)
STOCK OPTIONS EXERCISED	185			2			606			—			—			—			608
STOCK WARRANTS EXERCISED	210			2			959			—			—			—			961
ISSUANCE OF COMMON SHARES	8,000			80			79,838			—			—			—			79,918
EQUITY COMPENSATION	312			3			7,159			(2,850	)		—			—			4,312
VESTING/CANCELLATION OF RESTRICTED SHARES	—			—			(31	)		552			—			—			521
PURCHASE AND RETIREMENT OF TREASURY STOCK	(58	)		(1	)		(598	)		—			—			—			(599	)
NET INCOME (LOSS)	—			—			—			—			(27,612	)		—			(27,612	)
BALANCE, September 30, 2005	63,131		$	631		$	316,228		$	(2,875	)	$	(269,122	)	$	(77	)	$	44,785

The accompanying notes are an integral part of these unaudited consolidated statements.

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SYNTROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	For the Nine Months Ended September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(27,612	)	$	(30,656	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, amortization and impairment		7,499			442
Foreign currency exchange		(298	)		(494	)
Non-cash compensation expense		3,788			3,151
Non-cash interest expense		1,275			1,338
Non-cash settlement of Australia liability		—			408
Gain on sale of assets and interest in projects		(3,558	)		(23	)
Changes in assets and liabilities—
Accounts and notes receivable		120			993
Catalyst materials		—			2,898
Other assets		319			848
Accounts payable		1,806			(152	)
Accrued liabilities and other		(1,186	)		(372	)
Deferred revenue		(5,873	)		(9,635	)
Net cash used in operating activities		(23,720	)		(31,254	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment		(909	)		(778	)
Oil and gas related expenditures		(14,372	)		(2,633	)
Proceeds from note receivable		5			—
Proceeds from conveyance of interest in project and sale of assets		9,440			—
Change in restricted cash		(3,555	)		22,568
Proceeds from sale of investments		—			121
Net cash used in investing activities		(9,391	)		19,278
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock, warrants and option exercises		81,487			31,765
Joint venture costs		(500	)		—
Proceeds from joint venture		3,178			—
Proceeds from issuance of convertible debt		—			682
Proceeds from settlement of note receivable from officer		—			100
Settlement of Australia Liability		—			(14,477	)
Purchase and retirement of common stock		(599	)		(238	)
Net cash provided by financing activities		83,566			17,832
FOREIGN EXCHANGE EFFECT ON CASH		(4	)		(95	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		50,451			5,761
CASH AND CASH EQUIVALENTS, beginning of period		31,573			32,695
CASH AND CASH EQUIVALENTS, end of period	$	82,024		$	38,456

The accompanying notes are an integral part of these unaudited consolidated statements.

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SYNTROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

1. Basis of Reporting

The primary operations of Syntroleum Corporation and subsidiaries (the “Company” or “Syntroleum”) to date have consisted of the research and development of a proprietary process (the “Syntroleum Process”) designed to convert natural gas or synthesis gas into synthetic liquid hydrocarbons (“gas-to-liquids” or “GTL”) and activities related to the commercialization of the Syntroleum Process. Synthetic liquid hydrocarbons produced by the Syntroleum Process can be further processed using the Syntroleum Synfining Process into high quality liquid fuels such as diesel, jet fuel, kerosene and naphtha, high quality specialty products such as synthetic lubricants, synthetic drilling fluid, waxes, liquid normal paraffin solvents and certain chemical feedstocks. The Company is also developing methods of applying its technology to convert synthesis gas derived from coal into these same high quality products (“coal-to-liquids” or “CTL”).

The Company’s current focus is to commercialize the Syntroleum Process and the Synfining Process through participation in projects that would utilize the Company’s GTL technologies in the production of hydrocarbons. The Company’s particular interests include projects where it would be involved in the upstream field development of the feedstock for GTL plants. The Company is currently participating in a project offshore Nigeria on Oil Mining Lease 113 (“OML 113”) in which it is involved in the upstream field development of oil and gas reserves. The Company is also focused on being a recognized provider of GTL and CTL technology to the energy industry through strategic partnerships and licensing of its technology. The Company has sold GTL licenses for the Syntroleum Process to seven oil companies and the Commonwealth of Australia.

The Company participated in the design and operation of a demonstration GTL plant located at ARCO’s Cherry Point refinery in Washington State. This demonstration plant was relocated to the Tulsa Port of Catoosa and is the basis for the Company’s Catoosa Demonstration Facility. This new GTL facility is designed to produce up to approximately 70 barrels per day (“b/d”) of synthetic products. As part of the U. S. Department of Energy (“DOE”) Ultra-Clean Fuels Production and Demonstration Project (“DOE Catoosa Project”), the fuels from this facility have been tested in bus fleets by the Washington Metropolitan Area Transit Authority and the U.S. National Park Service at Denali National Park in Alaska and by other project participants together with advanced power train and emission control technologies. The Company also owns and operates a two b/d pilot plant and various laboratory facilities in Tulsa, Oklahoma, which are used in demonstrating process performance and conducting various studies.

The Company has also pursued gas monetization projects in the United States, which include conventional gas field development of sub-quality natural gas in concert with available third-party gas processing technologies. The assets related to these projects are currently held for sale. Management does not intend to pursue similar projects in the future.

The consolidated financial statements included in this report have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, these statements reflect all adjustments (consisting of normal recurring entries), which are, in the opinion of management, necessary for a fair statement of the financial results for the interim periods presented. These financial statements should be read together with the financial statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the SEC under the Securities Exchange Act of 1934.

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 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.

2. Operations and Liquidity

Construction of GTL and CTL plants and other activities, including exploration and production of energy assets and research and development programs in which the Company participates, will require significant capital expenditures by the Company. The Company may obtain funding through joint ventures, license agreements and other strategic alliances, as well as various other financing arrangements to meet its capital and operating cost commitments for various projects. The Company is currently exploring alternatives for raising capital to fund the growth of its CTL business, including the development, and demonstration of effectiveness, of its technology with coal-derived synthesis gas. The Company may also seek debt or equity

5

financing in the capital markets. The Company has an effective registration statement for the proposed offering from time to time of shares of its common stock, preferred stock, debt securities, depositary shares or warrants for a remaining aggregate offering price of approximately $102,000,000 as of September 30, 2005. If these capital resources are not available to the Company, its GTL and/or CTL plant development and other activities may be curtailed.

If adequate funds are not available, the Company may be required to reduce, delay or eliminate expenditures for these capital projects, as well as its research and development and other activities, or seek to enter into a business combination transaction with or sell assets to another company. The Company could also be forced to license to third parties the rights to commercialize additional products or technologies that it would otherwise seek to develop itself. If the Company obtains additional funds by issuing equity securities, dilution to stockholders may occur. In addition, preferred stock could be issued in the future without stockholder approval and the terms of the preferred stock could include dividend, liquidation, conversion, voting and other rights that are more favorable than the rights of the holders of the Company’s common stock. The transactions outlined above may not be available to the Company when needed or on terms acceptable or favorable to the Company.

3. Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents consist of cash and highly liquid investments with an original maturity of three months or less, primarily in the form of money market instruments. The Company’s cash and cash equivalents are held in a few financial institutions; however, management believes that the Company’s counter-party risks are minimal based on the reputation and history of the institutions selected.

The Company has restricted cash held in escrow at September 30, 2005 related to its agreement with Sovereign Oil and Gas Company II, LLC (“Sovereign”), a consulting firm that has assisted the Company in acquiring oil and natural gas fields worldwide, in the amount of $2,566,000, and to secure a $10,000,000 letter of credit provided to Yinka Folawiyo Petroleum Co. Ltd. (“YFP”) pursuant to the terms of a Joint Venture Agreement between YFP and the group of companies assembled by the Company (the “Participants”) to develop OML 113 offshore Nigeria. This letter of credit is required to be secured by cash. YFP had the right to draw the full amount from the letter of credit as liquidated damages if the initial well was not drilled on OML 113 before February 2006. The Participants have contributed their respective share of the cash required to secure the letter of credit and other costs associated with the letter of credit. The Company has recorded its 10 percent of the cash on deposit as security for the letter of credit as restricted cash on the balance sheet as of September 30, 2005. Subsequent to September 30, 2005, the requirements for drilling the initial test well were fulfilled, and the letter of credit was released. The restricted cash on hand at December 31, 2004 was related to the Company’s agreement with Sovereign.

4. Oil and Gas Property

The Company follows the full cost method of accounting for exploration, development, and acquisition of oil and gas reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits, and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method on a country-by-country basis. The Company excludes all costs of unevaluated properties from immediate amortization. For each cost center, the Company’s unamortized costs of oil and gas properties are limited to the sum of the future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of any unproved properties. If the Company’s unamortized costs in oil and gas properties exceed this ceiling amount, a provision for additional depreciation, depletion, amortization and impairment is required.

The Company’s total investment in oil and gas activities consisted of the following (in thousands):

	September 30, 2005
	United States			Nigeria			Other			Total
Evaluated properties	$	3,115		$	3,331		$	10		$	6,456
Unevaluated properties		1,589			3,944			—			5,533
Gross oil and gas properties		4,704			7,275			10			11,989
Accumulated depreciation, depletion, amortization, and impairment		(3,115	)		(3,331	)		(10	)		(6,456	)
Net oil and gas properties	$	1,589		$	3,944		$	—		$	5,533

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	December 31, 2004
	United States			Nigeria		Other		Total
Evaluated properties	$	76		$	—	$	—	$	76
Unevaluated properties		3,881			865		—		4,746
Gross oil and gas properties		3,957			865		—		4,822
Accumulated depreciation, depletion, amortization, and impairment		(76	)		—		—		(76	)
Net oil and gas properties	$	3,881		$	865	$	—	$	4,746

United States. The Company’s oil and gas activities in the United States have included the acquisition of oil and gas leases in the Central Kansas Uplift, geological and geophysical work, drilling and completion of eight wells and the re-entry of three wells. All of the activities in the United States have been exploratory oil and gas investments. Limited production from the first well began in January 2005 and the Company had no oil and gas production prior to January 2005.

In September 2005, management completed evaluation of potential reserves related to drilled properties in the United States. Subsequent to September 30, 2005, management decided to focus efforts on aligning the Company with specific goals and to discontinue further expenditures in the Central Kansas Uplift area. Management determined potential reserves to be zero based on the decision to discontinue further expenditures. The Company has amortized these properties based on the evaluated reserves. The Company has recognized depreciation, depletion, amortization and impairment expense of $2,052,000 related to its evaluated properties in the United States during the three months ended September 30, 2005 and $3,040,000 for the nine months ended September 30, 2005 based on the units-of-production method. The Company considers parts of leasehold costs to be unevaluated as many of these leaseholds have not been drilled to evaluate reserve potential. The Company includes leasehold costs in the evaluated full cost pool based on lease terms. Subsequent to the quarter ended September 30, 2005, the Company has been pursuing liquidation of the oil and gas activities in the Central Kansas Uplift area. Certain leasehold acres were sold in November 2005 for $1,000,000. Management expects to sell the remaining acreage by the end of 2006.

Nigeria. The Company’s Nigerian oil and gas activities have included leasehold acquisition, geological and geophysical work over various areas in Nigeria, and drilling costs for the Aje-3 well in OML 113 offshore Nigeria. All of the capitalized costs for Nigerian oil and gas activities are for exploration purposes. Certain leasehold costs are considered to be unevaluated and are therefore excluded from amortization. No production from these properties had occurred as of September 30, 2005 and December 31, 2004.

The Company’s Nigerian oil and gas activities include the acquisition of OML 113 offshore Nigeria. All costs associated with the acquisition of OML 113 were capitalized under the full cost accounting policy described above. As a result of the approval of assignment and the drilling permit by the Nigerian government on April 14, 2005, the Company received a cash bonus in the amount of $9,438,000 from certain Participants in the project as consideration for the conveyance of interests and made a bonus payment to Sovereign in the amount of $3,719,000, resulting in net proceeds to the Company of $5,719,000. Under the agreement with Sovereign, the Company issued warrants to purchase shares of the Company’s common stock to Sovereign having a value of $157,000 using a Black-Scholes valuation. The bonus paid and warrants issued to Sovereign were capitalized to the full cost pool as they are directly related to the acquisition cost of OML 113. The proceeds from the conveyance of interests to certain other Participants was accounted for as an adjustment to the Nigerian full cost pool for costs incurred by the Company prior to the assignment. The Nigerian full cost pool was completely eliminated and a gain on conveyance of interest of $3,556,000 was recognized as other income during the nine months ended September 30, 2005. All costs incurred subsequent to the Nigerian government approval and relating to work performed on the first well to be drilled on OML 113 have been capitalized.

The first well, Aje-3, was drilled in the quarter ended September 30, 2005 to help further delineate the Aje Field in OML 113. Test results were evaluated after drilling for consideration of commercial completion. The Participants found the economics for commercial completion to be unfavorable. Subsequent to the quarter ended September 30, 2005, the well was plugged and abandoned. The Company’s total drilling, logging, and dry hole costs of Aje-3 are $3,331,000 at September 30, 2005. The Company has charged the excess unamortized cost of drilling and testing as a non-cash expense in the amount of $3,331,000 as of September 30, 2005. The Company has participated in other activities in Nigeria, including Nigerian geological and geophysical work within OML 113 and other areas of Nigeria. The total of capitalized cost for these activities is considered unevaluated and totaled $3,944,000 as of September 30, 2005.

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The Participants agreed to pay promoted costs to drill and test one delineation well in the Aje Field discovery and one option well in order to earn a participating interest in OML 113. The Participants must decide on the drilling of the second well by March 31, 2006. Management plans to further explore within OML 113 and in Nigeria and expects to make firm plans before September 30, 2006 in accordance with its agreements on OML 113.

Retirement Obligations. The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 143,Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The standard requires that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. The asset retirement obligations consist primarily of costs associated with the future plugging and abandonment of oil and gas wells, site reclamation and facilities dismantlement. A corresponding amount is capitalized as part of the related property’s carrying amount. The discounted capitalized asset retirement cost is amortized to expense through the depreciation, depletion, amortization and impairment calculation over the life of the asset. The liability accretes over time with a charge to accretion expense. The Company has recognized an asset retirement obligation of approximately $11,000 related to total oil and gas properties at both September 30, 2005 and December 31, 2004 using a 10 percent discount rate over the estimated life of the properties.

5. Impairment of Long-Lived Assets

The Company follows provisions of SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. The Company makes assessments of impairment on a project-by-project basis. Management reviews assets for impairment upon the occurrence of certain events indicating that the asset may be impaired. An asset is considered to be impaired when the estimated undiscounted future cash flows are less than the carrying value of the asset. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future cash flows of a project. During the three months ended September 30, 2005, the Company recorded a write down of approximately $481,000 related to its gas processing plant and equipment. The write down included costs associated with engineering, equipment, the proposed gas processing plant and other gas processing equipment. Subsequent to the quarter ended September 30, 2005, the Company began pursuing liquidation of the gas processing plant and related equipment related to the Kansas low-btu project. The liquidation is expected to occur by the end of 2006. The processing plant and equipment is considered as held for sale subsequent to the quarter ended September 30, 2005 at an impaired value of $1,569,000, net of $14,000 in accumulated depreciation.

6. Research and Development

The Company incurs significant costs for research, development and engineering programs. Expenses classified as research and development include salaries and wages, rent, utilities, equipment, engineering and outside testing and analytical work associated with our research, development and engineering programs. Because these costs are for research and development purposes, and not commercial or revenue producing, they are charged to expense when incurred in accordance with SFAS No. 2,Accounting for Research and Development Costs.

7. Earnings Per Share

Basic and diluted earnings (losses) per common share were computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the reporting period. Options and warrants equivalent to 11,360,962 and 8,916,218 shares of common stock are outstanding and exercisable at a weighted average exercise price of $6.88 and $5.63 for the periods ended September, 30, 2005 and 2004, respectively, were not included in the computation of diluted earnings (loss) per share, as inclusion of these items would be anti-dilutive. Unvested restricted common stock units totaling 409,654 and 268,480 were also not included in the computation of diluted earnings (loss) per share for the periods ended September 30, 2005 and 2004, respectively, as they are anti-dilutive.

The number of shares that could be issued as a result of the Company’s convertible debt outstanding at September 30, 2005 and September 30, 2004 totals 4,249,211 and 3,977,020 shares of common stock, respectively, based on the minimum conversion rate of $6.00 per common share. These shares also are excluded from the computation of diluted earnings (loss) per share, as they are anti-dilutive for the periods ended September 30, 2005 and 2004.

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8. Stock-Based Compensation

The Company has elected to follow the intrinsic-value method of accounting for employee stock-based compensation as prescribed by Accounting Principles Board Opinion (“APBO”) No. 25,Accounting for Stock Issued to Employees(“APBO No. 25”).Additionally, the Company applies the disclosure-only provisions of SFAS No. 123,Accounting for Stock-Based Compensation (“SFAS No. 123”) as amended by SFAS No. 148, Accounting for Stock-Based Compensation- Transition and Disclosure (“SFAS No. 148”) for options granted to employees. No compensation cost has been recognized for stock options issued to employees under the Company’s stock option plans, because the options awarded under the plans qualify for fixed plan accounting and the exercise price of the options is equal to or greater than the market value of the Company’s common stock on the date of grant. However, pursuant to the requirements of SFAS No. 123 and SFAS No. 148, the following disclosures are presented to reflect the Company’s pro forma net income (loss) for the nine month periods ended September 30, 2005 and 2004 as if the fair value method of accounting prescribed by SFAS No. 123 had been used. If compensation cost for options granted to employees under the Company’s stock option plans had been determined consistent with the provisions of SFAS No. 123, the Company’s net income (loss) and income (loss) per share would have changed to the pro forma amounts indicated below, using the assumptions described:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2005			2004			2005			2004
	(in thousands, except per share data)
Net income (loss), as reported	$	(15,414	)	$	(12,475	)	$	(27,612	)	$	(30,656	)
Add: Total variable stock-based employee compensation expense included in net income (loss), as reported and determined under intrinsic- value method for awards granted, modified, or settled, net of related tax effects, if any		308			—			308			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for awards granted, modified, or settled, net of related tax effects, if any		(1,201	)		(516	)		(2,369	)		(1,483	)
Pro forma net income (loss)	$	(16,307	)	$	(12,991	)	$	(29,673	)	$	(32,139	)
Earnings (loss) per share:
Basic and diluted- as reported	$	(0.28	)	$	(0.27	)	$	(0.52	)	$	(0.72	)
Basic and diluted- pro forma	$	(0.29	)	$	(0.28	)	$	(0.56	)	$	(0.76	)

The fair values of options have been estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions:

	September 30, 2005		September 30, 2004
Expected dividend yield	0	%	0	%
Expected volatility	52	%	56	%
Risk-free interest rate	3.84	%	3.38	%
Expected life	5 yrs.		5 yrs.

Stock and Restricted Stock Unit Grants. In February 2004, the Company announced to its employees an incentive compensation plan whereby employees could receive a certain number of shares of common stock based on the achievement of certain goals and objectives by the individual employee and by the Company. The Board of Directors establishes the objectives on which the Company will be measured and determines the number of shares to be issued based on a rating system. Individual objectives are measured by management based on a similar rating system. The Company recognized compensation expense of $774,000 during the year ended December 31, 2004 for 84,081 stock awards that were granted to employees in 2005 for service completed during 2004 related to this plan. This compensation expense was based on the value of the Company’s common stock on January 24, 2005.

The Company has also issued 141,837 shares of common stock during 2005 as a result of the vesting of restricted common stock units previously granted and other stock awards to employees. In connection with the issuance of shares to employees, the Company repurchased and subsequently cancelled a total of 58,036 shares of common stock as settlement for the employees’ payroll taxes.

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2005 Stock Incentive Plan. On April 25, 2005, the stockholders of the Company approved the adoption of the Syntroleum Corporation 2005 Stock Incentive Plan (the “Plan”), which provides for the issuance of up to 6,600,000 shares of the Company’s common stock pursuant to the grant of stock options, stock appreciation rights, stock awards (including restricted stock and stock units) and performance awards. Awards will be available for grant to employees, independent contractors and non-employee directors of the Company, except that non-employee directors may only be granted awards of stock appreciation rights, stock options or restricted stock under the Plan.

The Board of Directors has established an annual incentive plan under which employees are eligible to receive a certain number of shares of common stock based on the achievement of certain Company-wide objectives and the individual’s performance rating for the year. The Board of Directors has established objectives for the year ended December 31, 2005 on which the Company will be measured which determines a number of shares to be issued to employees based on a rating system. The annual incentive plan has no impact on the financial statements as of September 30, 2005, as the achievement of the Company and individual objectives cannot be predicted with certainty.

Long-Term Incentive Compensation Plan. In June 2005, the Company entered into stock option award agreements under the plan with certain of its officers. The agreements granted the officers options to purchase up to 2,000,000 of its shares of the Company’s common stock at an exercise price of $10.52 per share. Depending on the sustained stock price (as defined below) of the Company’s common stock and the net present value of future cash flows (as defined below), a percentage of the options will vest as determined in a performance vesting schedule with respect to the period commencing on the date of grant and ending on December 31, 2010 (the “Performance Period”). The performance vesting schedule is defined below.

In July 2005, the Company entered into similar stock option award agreements under the Plan with certain of its officers. The agreements granted the officers options to purchase up to 600,000 shares of the Company’s common stock at an exercise price of $10.14 per share. Depending on the sustained stock prices of the Company’s common stock and the net present value of future cash flows, a percentage of options will vest as according to the Performance Period. The performance vesting schedule is as follows:

	Net Present Value of Future Cash Flows
Sustained Stock Price	Less than $1,375 million		$1,375 million but less than $1,650 million		$1,650 million but less than $1,925 million		$1,925 million but less than $2,200 million		$2,200 million or more
$40 or more	100	%	100	%	100	%	100	%	100	%
$35 but less than $40	75	%	75	%	75	%	75	%	100	%
$30 but less than $35	50	%	50	%	50	%	75	%	100	%
$25 but less than $30	25	%	25	%	50	%	75	%	100	%
Less than $25	0	%	25	%	50	%	75	%	100	%

“Sustained stock price” means the average fair market value of a share of the Company’s common stock during any six-month period commencing on or after the first day of the Performance Period and ending on or before the last day of the Performance Period. “Net present value of future cash flows” means the net present value of estimated future cash flows from executed agreements (such as a contract to supply natural gas), proven reserves or any other source of future cash flows with analogous certainty to the aforementioned sources as estimated by an independent auditor designated by the Company’s Board of Directors. For this purpose, an annual discount rate of 10% is used to calculate net present value.

The term of each option is ten years from the date of grant. The Company follows APBO No. 25, which requires the Company to treat the plan as a variable plan for accounting purposes and causes the recognition of compensation expense or income related to changes in the intrinsic value in the options. As intrinsic value existed for both option award agreements on September 30, 2005, compensation expense of $253,000 was recognized for the June 2005 stock option award agreement and $55,000 was recognized for the July 2005 stock option award agreements for the quarter and nine months ended September 30, 2005.

During 2005, the Company granted an aggregate of 250,000 restricted common stock units to certain employees of the Company under the Company’s existing stock option and incentive plans. These restricted common stock units vest over various periods through 2010. The Company expects to recognize $238,000 in compensation expense for the year ending December 31, 2005. Throughout the remainder of the vesting period the Company expects to recognize $2,297,000 in compensation expense relating to the vesting of these restricted common stock units. The Company recorded deferred compensation for these units totaling $2,535,000 at the time of grant based on the market prices of the Company’s common stock on that date.

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Stock-Based Incentives. The Company also grants stock-based incentives to certain non-employees. These stock-based incentives are accounted for in accordance with SFAS No. 123, as amended, because the individuals receiving these instruments are not considered employees of the Company. These stock-based incentives have various vesting requirements, exercise prices and expiration dates. Certain stock-based incentives vest upon the achievement of certain performance goals associated with the consulting agreement. These stock-based incentives will be measured and expense will be recorded at the time these performance goals are met in accordance with Emerging Issues Task Forces Issue 96-18,Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services. Any stock options granted to non-employees that are not related to specific performance criteria are expensed over the period of vesting based on the assumptions described above. Compensation expense related to stock-based incentives granted to non-employees totaled $2,881,000 and $1,759,000 for the nine months ended September 30, 2005 and September 30, 2004, respectively. Compensation expense related to stock-based incentives granted to non-employees totaled $17,000 and $924,000 for the three months ended September 30, 2005 and September 30, 2004, respectively.

9. Marathon Participation and Loan Agreement

In May 2002, the Company signed a Participation Agreement with Marathon Oil Company (“Marathon”) in connection with the DOE Catoosa Project. This agreement requires Marathon to reimburse the Company for up to $5,000,000 in project costs and to provide up to $3,000,000 in Marathon personnel contributions. Marathon is entitled to credit these contributions against future license fees in specified circumstances. As of December 31, 2004, the Company had received full reimbursement of required project cost and Marathon personnel contributions according to the Participation Agreement.

Marathon also agreed to provide project funding to the Company pursuant to advances under two secured promissory notes totaling $21,300,000. The promissory notes bear interest at a rate of eight percent per year and mature in June 30, 2006. The total current balance of $25,496,000, which includes accrued interest, has been included in current liabilities in the accompanying consolidated balance sheet as of September 30, 2005. If the Company obtains capital for the project from a third party, these capital contributions will be required to be applied towards the outstanding principal and interest of the notes. The only other form of repayment to Marathon is its right to convert the promissory notes into credits against future license fees or into the Company’s common stock at no less than $6.00 per share and no more than $8.50 per share at the maturity date. Under certain circumstances, the Company may also elect to repay the notes in cash. The promissory notes are secured by a mortgage on the assets of the project. Events of default under the promissory notes include failure by the Company to comply with the terms of the promissory notes, events of bankruptcy of the Company, a material adverse effect on the Company, a change of control of the Company and the Company’s current assets minus current liabilities falling below $10,000,000, excluding amounts due under the promissory notes and liabilities associated with prepaid license fees. The Company was in compliance with the provisions of the notes as of September 30, 2005 and December 31, 2004.

10. Deferred Revenue

The Company recognized joint development revenues previously recorded in deferred revenue related to the completion of the fuel production and delivery commitments in connection with the DOE Catoosa Project in the amount of $5,798,000 during the nine months ended September 30, 2005. The Company has recorded deferred revenue of $1,000,000 as of September 30, 2005 and December 31, 2004 related to its agreement with Marathon as discussed in Note 9. The Company also has deferred revenues of $9,000,000 related to its licenses issued to other licensees.

The Company has a license agreement with the Commonwealth of Australia that includes credits against future license fees in the amount of AUD $15,000,000. License fees under this agreement have been recorded as deferred revenue of $11,405,000 and $11,702,000 million as of September 30, 2005 and December 31, 2004, respectively. Amounts payable under the license agreement are denominated in Australian dollars and are therefore subject to changes in foreign currency.

11. Contingencies

The Company is subject to contingent obligations under leases and other agreements incurred in connection with real estate activities and other operations conducted by SLH Corporation (“SLH”) prior to its merger with the Company. Through its merger with SLH, the Company acquired Scout Development Corporation (“Scout”). Scout is a successor guarantor on two sets of leases; a land lease and subleases in Hawaii and a land lease in Reno, Nevada.

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The Hawaii obligations arise out of certain land leases and subleases that were entered into by Business Men’s Assurance Company of America and Bankers Life of Nebraska (now known as “Ameritas Life”) in connection with the development of the Hyatt Regency Waikiki Hotel (“Hyatt Hotel”). The Hyatt Hotel was subsequently sold and the land was subleased to the purchasing party. During 1990, in connection with the sale of BMAA, Lab Holdings, Inc. (“Lab Holdings”) gave an indemnity to the purchaser against liabilities that may arise from the subject leases. Also during 1990, Lab Holdings transferred its right title and interest to the subject leases to Scout. If the Hyatt Hotel were to default on the leases, Scout could be liable for the lease obligations.

The current rent payments for the subject leases are $826,000 per year. The lease amount is fixed until 2006, when the payments will be renegotiated and increased based upon a stipulated formula, the product of which is the fair market value of the land, multiplied by a minimum market rate of return of seven percent. The Company projects that beginning in 2008 (the first full year following the renegotiation), rent payments will be $5,812,000 per year. Subsequent renegotiations will occur in 2017, 2027 and 2037, subject to the same formula. This lease expires in 2047. The total lease payments through 2047, based on estimated increases, would be $398,000,000. In the event of default by the property owner, the risk of these lease obligations would be shared with others. In addition to Scout, Ameritas Life shares equally in the lease obligations. LabOne Corporation (formerly known as Home Office Reference Laboratory), as a result of its merger with Lab Holdings, may also be liable for the lease obligations.

The Hyatt Hotel has an estimated market value, based on a 1998 appraisal, of $396,000,000. The Hyatt Hotel had gross revenues of $84,000,000 subject to the lease agreement for the year ended May 31, 2003. Based on the appraised value of the Hyatt Hotel and its profitability, management considers the risk of default by the Hyatt Hotel on the lease obligations to be remote and accordingly, has not recorded any liability in its consolidated balance sheets at September 30, 2005 or December 31, 2004.

Scout is also subject to lease obligations under a land lease for a Reno, Nevada parking garage. This property was sold in 2000; however, Scout was not released from the land lease by the landowner. This lease requires total remaining lease payments of $5,894,000 and will expire in August 2023. The property is currently owned by Fitzgerald’s Reno Inc. (“FRI”), which continues to make the monthly ground lease payments. If FRI were to default on its obligations, then Scout would have the right to claim the parking garage and sell the asset. Management believes that the sale of the asset and the assignment of the ground lease to the buyer would cover the contingent liability exposure for this lease. Management considers the likelihood of default by FRI under the lease obligations to be remote, and accordingly has not recorded any liability in its consolidated balance sheets at September 30, 2005 or December 31, 2004.

The Company and its subsidiaries are involved in other lawsuits that have arisen in the ordinary course of business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on the Company’s business or consolidated financial position. The Company cannot predict with certainty the outcome or effect of the litigation specifically described above or of any such other pending litigation. There can be no assurance that the Company’s belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

12. Equity Transactions

In February 2004, the Company issued warrants to purchase up to 1,170,000 shares of the Company’s common stock to Mr. Ziad Ghandour, a director of and consultant to the Company, pursuant to an amended and restated consulting agreement with TI Capital Management, a firm owned by Mr. Ziad Ghandour. In October 2005, Mr. Ziad Ghandour became a full time employee of the Company. The warrants to purchase 170,000 shares at an exercise price of $5.00 per share are exercisable from the date of stockholder approval, which was received on April 26, 2004. The warrants to purchase 500,000 shares at an exercise price of $4.50 per share vested in September 2004 in relation to work completed with Dragados Industrial S.A. The warrants to purchase 500,000 shares at an exercise price of $5.25 per share became exercisable in February 2005 as a result of the Company’s agreement with Bluewater Energy Services B.V. All of these warrants will expire on November 4, 2007. On January 24, 2005, Mr. Ziad Ghandour exercised 200,000 of these warrants to purchase shares of the Company’s common stock at an exercise price of $4.50 per share, resulting in proceeds to the Company of approximately $900,000.

On January 28, 2005, Sovereign exercised warrants to purchase 8,750 shares of the Company’s common stock at an exercise price of $6.40 per share, resulting in proceeds to the Company of approximately $56,000.

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On March 17, 2005, the Company completed the sale of 7,000,000 shares of common stock at a price of $10.00 per share. The Company sold all of these shares directly to Legg Mason Opportunity Trust, a series of Legg Mason Investment Trust, Inc., a registered investment company. The sale resulted in net proceeds to the Company of approximately $69,950,000.

On April 14, 2005, the Company completed the sale of 1,000,000 shares of its common stock at a price of $10.00 per share. The Company sold all of the shares directly to Dorset Group Corporation (“Dorset”). The sale resulted in net proceeds to the Company of approximately $9,968,000.

On April 25, 2005, the Company’s stockholders approved an amendment to the Company’s consulting agreement with TI Capital Management, which provides for the issuance to Mr. Ghandour of cash, common stock and warrants to purchase common stock as compensation upon the achievement of various goals set forth in the agreement. The payment of compensation under the agreement to Mr. Ghandour is subject to the satisfaction of specific criteria. As a result of entering into the participation agreements with respect to the Company’s stranded gas venture as described in Note 14, the Company has issued 86,356 shares of common stock and paid $500,000 in cash to Mr. Ghandour in accordance with the amended consulting agreement for the period ended September 30, 2005. In October 2005, the Company issued an additional 17,271 shares of common stock and paid $100,000 in cash to Mr. Ghandour in accordance with the amended consulting agreement for the inclusion of another participant into the stranded gas venture participation agreement. This agreement expires on September 30, 2007.

13. OML 113 Participation Agreement

On January 13, 2005, the Company and the Participants finalized various agreements to begin the delineation of the Aje Field discovery located in OML 113 offshore Nigeria. The agreements require the Participants to pay the Company a signature bonus following the official assignments of interest and the drilling permit by the Nigerian government to the Participants. It also requires the Participants to pay promoted costs to drill one delineation well in the Aje Field discovery and one option well in order to earn a participating interest in OML 113. The Company also was granted an overriding royalty interest from each of the Participants other than YFP. The Company is entitled to receive a development bonus upon commencement of commercial production. The Company is required to pay 10 percent of the cost to drill and log the first two wells to retain a 32.5 percent cost-bearing working interest in the project. Following the finalization of the agreements, the Participants put into place a $10,000,000 letter of credit, which is secured by cash totaling $10,200,000 and accrued interest. Each Participant paid its proportionate share to secure this letter of credit. The Company has recorded its 10 percent share of the funds securing the letter of credit as restricted cash as of September 30, 2005.

On April 14, 2005, the Company received approval from the Nigerian government for the assignment of interest in OML 113 offshore Nigeria to the Company and the Participants. As a result of the approval of the assignment of interests and the receipt of the drilling permit for the first well, the Company received a signature bonus of approximately $9,438,000 from certain Participants as part of the consideration for joining the Aje project. The Company subsequently made a payment to Sovereign in the amount of $3,719,000 and issued warrants to purchase 25,000 shares of the Company’s common stock at an exercise price of $6.40 per share to Sovereign under the joint development agreement between the Company and Sovereign. The Company recorded a gain on the conveyance of interest resulting from this transaction in the amount of $3,556,000 as of September 30, 2005.

During the third quarter ended September 30, 2005, the Company and the Participants drilled the initial test well, Aje-3. Subsequent to the end of the third quarter, the well reached its reservoir objectives as anticipated and a detailed logging program was acquired and interpreted. Test results were evaluated for consideration of commercial completion. The Participants found the economics for commercial completion to be unfavorable. Subsequent to the quarter ended September 30, 2005, the well was plugged and abandoned. The Company has determined the delineation well to have assisted in further estimating potential reserves within the block. Management and the other Participants expect to meet prior to the end of the fourth quarter to discuss further development of this block, according to the terms of the Participation Agreement. As the requirements to secure the letter of credit were met with the drilling of the initial test well, Aje-3, the letter of credit was released subsequent to the quarter ended September 30, 2005.

14. Stranded Gas Venture

On April 11, 2005, the Company’s wholly owned subsidiary, Syntroleum International Corporation (“Syntroleum International”), entered into a Participation Agreement with Dorset pursuant to which Dorset has committed to provide approximately $40,000,000 to Syntroleum International to be used to evaluate investment opportunities, conduct oil and gas project development activities, and acquire interests in oil and gas properties (the “Stranded Gas Venture”). On April 20, 2005, Ernest Williams II Q-TIP TUA dated 01/25/02 joined the

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Participation Agreement as a venture participant and agreed to provide an additional capital commitment of $10,000,000. In September 2005, Selim K. Zilkha Trust joined the Participation Agreement as a venture participant and agreed to provide a capital commitment of $10,000,000 to us.

Under the terms of the Participation Agreement, the other venture participants will fund 100 percent of the costs to acquire the rights to stranded gas and liquids projects and will receive 20 percent of the interest acquired by the Company in any such project. Net cash proceeds received from the Company’s share of any project, including bonuses, or net revenues from the sale of production attributable to the Company’s working interest or overriding royalty interests in a project, less the payment of any operating expenses and maintenance capital expenditures, taxes, royalties or other required payments to a governmental entity, will be paid as follows:

• first, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to 80 percent of the sum of such participant’s individual cost basis in all of the then existing projects in which such participant participated;

• second, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to a return of 10 percent per annum, compounded annually, on 80 percent of the sum of such participant’s individual costs basis in all of the projects in which such participant participated; and

• third, 100 percent to Syntroleum International.

As of September 30, 2005, the Company has received proceeds in the amount of $3,178,000 from the Stranded Gas Venture to be used to evaluate investment opportunities. The current balance of $3,229,000, which includes proceeds and accrued interest, has been recognized as a Stranded Gas Venture liability included in liabilities in the accompanying consolidated balance sheet as of September 30, 2005. Interest is allocated to a portion of principal at an annual rate of 10 percent, compounded annually, in accordance with the Participation Agreement.

15. New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123R,Share-Based Payment(“SFAS No. 123R”). This standard is a revision of SFAS No. 123 and supersedes APBO 25 and its related implementation guidance. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values and is effective for the first annual reporting period beginning after June 15, 2005. The Company expects to adopt SFAS No. 123R on January 1, 2006, using the standard’s modified prospective application method. Adoption of SFAS No. 123R will not affect the Company’s cash flows or financial position, but it will reduce reported income and earnings per share because the Company will be required to recognize compensation expense for stock options granted under the Company’s stock-based compensation plans. The Company has not been required to record such expense under current accounting rules. Under SFAS No. 123R, the Company will recognize compensation expense for stock-based compensation over the requisite service period, which is generally three years following the grant date. If the Company had expensed employee stock options under SFAS No. 123 for the three months ended September 30, 2005, net income and diluted earnings per share would have been reduced by the amounts disclosed above in Note 7. Because stock options are determined each year, the impact to the Company’s financial statements of the adoption of SFAS No. 123R cannot be predicted with certainty. However, the weighted average fair value of stock option awards disclosed in the footnotes to the financial statements, but not included in compensation expense, over the last three fiscal years ranged from $1.41 to $3.12 per share. Under SFAS No. 123R, the fair value would be amortized into compensation expense over the service period, which is generally the vesting period of the stock options.

In March 2005, the Financial Standards Board issued FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations (“FIN 47”), an interpretation of SFAS No. 143,Accounting for Asset Retirement Obligation. FIN 47 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. The interpretation is effective for fiscal years ending on or after December 15, 2005. The Company expects to adopt FIN 47 by December 31, 2005. The Company will be required to recognize a liability for all conditional asset retirement obligations at that time, if any. Management has not yet determined the impact to the Company’s financial statements of the adoption of FIN 47.

In May 2005, the Financial Standards Board issued SFAS No. 154,Accounting Changes and Error Corrections(“SFAS No. 154”), a replacement of APB Opinion No. 20,Accounting Changes, and FASB Statement No. 3Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the

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new accounting principle, unless it is impracticable to do so. The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The Company has elected to adopt SFAS No. 154 as of September 30, 2005. At the time of adoption, there was no impact to the Company’s financial statements.

16. Reclassifications

Certain reclassifications have been made to the September 30, 2004 consolidated statements of operations to conform to the 2005 presentation. These reclassifications had no impact on net income (loss).

17. Segment Information

The Company applies SFAS No. 131,Disclosures About Segments of an Enterprise and Related Information. The Company’s reportable business segments have been identified based on the differences in products or services provided. The Technology, General, Administrative and Other segment includes research and development expenses for further development of GTL technology, including operations of the Catoosa Demonstration Facility and the Tulsa pilot plant, engineering and design of the Company’s mobile GTL facility, and ongoing research and development efforts focusing primarily on commercialization of the technology the Company previously developed, as well as general and administrative expenses. Revenues in the Technology, General, Administrative and Other segment consist of joint development revenues from government agencies and major oil companies as well as catalyst materials sales. Management determined that the Domestic Oil and Gas segment includes the acquisition of oil and gas leases, geological and geophysical work, drilling and completion of wells and administrative work in the United States. Revenues for Domestic Oil and Gas activities include revenues from production and processing of oil and gas. Subsequent to the quarter ended September 30, 2005, the Domestic Oil and Gas segment will be discontinued and all assets will be liquidated. The International Oil and Gas segment includes project development expenses and capital expenditures for projects that involve traditional methods of production and processing and projects that may later include the use of the Company’s GTL technologies in international areas. International Oil and Gas revenues will include revenues from production and processing of oil and gas.

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The reportable business segments are summarized below for the three-month and nine-month periods ended September 30, 2005 and 2004 (in thousands):

	Domestic Oil and Gas			International Oil and Gas			Technology, General, Administrative and Other			Total
Three Months Ended September 30, 2005
Revenue	$	9		$	—		$	708		$	717
Operating cost	$	2,624		$	3,422		$	10,465		$	16,511
Net income/(loss)	$	(2,615	)	$	(3,409	)	$	(9,390	)	$	(15,414	)
Capital expenditures	$	134		$	4,913		$	314		$	5,361
Depreciation, depletion, amortization and Impairment	$	2,546		$	3,398		$	174		$	6,118
Three Months Ended September 30, 2004
Revenue	$	—		$	—		$	215		$	215
Operating cost	$	89		$	464		$	11,245		$	11,798
Net income/(loss)	$	(89	)	$	(464	)	$	(11,922	)	$	(12,475	)
Capital expenditures	$	1,357		$	328		$	241		$	1,926
Depreciation, depletion, amortization and Impairment	$	2		$	—		$	148		$	150
Nine Months Ended September 30, 2005
Revenue	$	70		$	—		$	7,142		$	7,212
Operating cost	$	3,711		$	3,535		$	32,057		$	39,303
Net income/(loss)	$	(3,641	)	$	36		$	(24,007	)	$	(27,612	)
Capital expenditures	$	2,080		$	12,292		$	909		$	15,281
Depreciation, depletion, amortization and Impairment	$	3,558		$	3,437		$	504		$	7,499
Nine Months Ended September 30, 2004
Revenue	$	—		$	—		$	6,289		$	6,289
Operating cost	$	390		$	1,455		$	34,601		$	36,446
Net income/(loss)	$	(390	)	$	(1,455	)	$	(28,811	)	$	(30,656	)
Capital expenditures	$	2,305		$	328		$	778		$	3,411
Depreciation, depletion, amortization and Impairment	$	2		$	—		$	438		$	440

Total net assets related to each business segment consisted of the following as of September 30, 2005 and December 31, 2004 (in thousands):

	Domestic Oil and Gas		International Oil and Gas		Technology, General, Administrative and Other		Total
September 30, 2005	$	3,412	$	8,547	$	89,850	$	101,809
December 31, 2004	$	4,524	$	1,067	$	39,160	$	44,751

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

You should read the following information together with the information presented elsewhere in this Quarterly Report on Form 10-Q and with the information presented in our Annual Report on Form 10-K for the year ended December 31, 2004 (including our audited financial statements and the accompanying notes).

Overview

We are seeking to develop and employ innovative technology to acquire and cause the production of stranded energy assets in various regions of the world. We are focusing our efforts on:

• projects that will allow us to use our proprietary processes for converting natural gas, or synthesis gas from coal, into synthetic liquid hydrocarbons, a process generally known as gas-to-liquids (“GTL”) or coal-to-liquids (“CTL”) technology, utilizing Fischer-Tropsch synthesis; and

• projects in which we are directly involved in the field development, production and processing of hydrocarbons, including projects that involve traditional methods of production and processing, projects that may later include the use of our GTL technology and projects that utilize other available technology.

We seek to form joint ventures and acquire equity interests in oil and gas development projects where GTL is critical to a project’s success by monetizing remote and/or stranded natural gas. These efforts include projects that would involve development, production and processing of hydrocarbons using our GTL and other traditional technologies and projects in which we would only process developed gas using our GTL technology on a fee basis. We also license our GTL technologies, which we refer to as the “Syntroleum Process” and the “Synfining Process,” to others. We believe that our use of air in the conversion process provides our technology with a competitive advantage compared to other technologies that use pure oxygen, thereby allowing us to build smaller footprint plants, like our barge or ship-mounted GTL plant (“GTL Mobile Facility”), and avoid the inherent operating risks associated with operating using pure oxygen. We are also seeking opportunities for applying our technology to convert synthesis gas derived form coal into synthetic liquid hydrocarbons or CTL.

We are currently investing a significant amount of our resources into our GTL Mobile Facility, our project offshore Nigeria on Oil Mining Lease 113 (“OML 113”), and the acquisition of other potential international or domestic GTL or CTL projects. We believe that these projects offer the greatest potential to meet our objective of generating near-term cash flow and utilizing the advantages of our processes. We also have projects ongoing and at varying stages of development with co-venturers and licensees in various geographical areas, including, Australia, Egypt, Nigeria, Papua New Guinea, Qatar and the United States. We may obtain funding through joint ventures, license arrangements and other strategic alliances, as well as various other financing arrangements to meet our capital and operating needs for various projects. We are currently exploring alternatives for raising capital to fund the growth of our CTL business, including the development, and demonstration of effectiveness, of our technology with coal-derived synthesis gas. We expect to incur increases in our costs as we continue to develop and commercialize these projects. Our longer-term survival will depend on our ability to obtain additional revenues or financing.

We are incurring substantial operating and research and development costs with respect to developing and commercializing the Syntroleum Process, our proprietary process of converting natural gas or gasified coal into synthetic liquid hydrocarbons, and the Synfining Process, our proprietary process for refining synthetic liquid hydrocarbons produced by the Syntroleum Process, and do not anticipate recognizing any significant revenues from licensing our technology or from production from either a GTL or CTL plant in the near future. As a result, we expect to continue to operate at a loss until sufficient revenues are recognized from licensing activities, or commercial operation of GTL or CTL plants or non-GTL projects we are developing.

Operating Revenues

During the periods discussed below, our revenues were primarily generated from reimbursement for research and development activities associated with the Syntroleum Process and catalyst sales. During 2005, we received revenue from our domestic oil and gas efforts; however, current revenues from our domestic oil and gas efforts have been lower than expected from the sale of natural gas in the United States, and we plan to discontinue further capital expenditures for these projects. Management has classified these assets as held for sale subsequent to the quarter ended September 30, 2005. In the future, we expect to receive revenue from sales of products or fees for the use of GTL plants in which we will own an equity interest, catalyst sales, licensing, revenues from research and development activities carried out with industry participants, and non-GTL projects we are developing.

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Until the commencement of commercial operation of GTL or CTL plants in which we own an interest or a non-GTL or CTL project we are developing, we expect that cash flow relating to the Syntroleum Process will consist primarily of license fee deposits, site license fees and revenues associated with joint development activities. We will not receive any cash flow from GTL or CTL plants in which we own an equity interest until the first of these plants is constructed. Our future operating revenues will depend on the successful commercial construction and operation of GTL or CTL plants based on the Syntroleum Process, the success of competing GTL or CTL technologies, the success of our non-GTL or CTL projects, and other competing uses for natural gas. We expect our results of operations and cash flows to be affected by changing crude oil, natural gas, fuel and specialty product prices and trends in environmental regulations. If the price of these products increases (decreases), there could be a corresponding increase (decrease) in operating revenues.

Oil and Gas Sales Revenues. We are pursuing projects in which we are directly involved in oil and gas field development and the processing of natural gas using available gas processing technologies. These include projects in which we only process developed gas on a fee basis and projects that may later evolve into integrated projects that would involve development, production and processing of hydrocarbons. Revenue from these projects will be recognized based on actual volumes processed for customers and sold to purchasers. Projects we are currently pursuing include the upstream development of OML 113 offshore Nigeria and others. We expect these projects will be pursued by us and with co-venturers through various arrangements. We anticipate receiving revenues from these projects, including sales of oil and gas from properties owned by us or jointly with another party, as well as processing and gathering fees from facilities in which we own an interest.

GTL Plant Revenues.We intend to develop GTL plants and to retain equity interests in these plants. These plants will enable us to gain experience with the commercial operation of the Syntroleum Process and, if successful, are expected to provide ongoing revenues. Some of the anticipated products of these plants (i.e., synthetic crude oil, Fischer-Tropsch waxes, synthetic diesel and other fuels, naphtha, lube base oils, process oils, drilling fluid and/or liquid normal paraffins) have historically been sold at premium prices and may result in relatively high sales margins. We anticipate forming joint ventures with energy industry and financial participants in order to finance and operate these plants. We anticipate that our GTL plants will include co-venturers who have low-cost gas reserves in strategic locations and/or have distribution networks in place for the synthetic products to be made in each plant as well as engineering, procurement, and construction contractors and FPSO operators.

Catalyst Revenues. We expect to earn revenue from the sale of our proprietary catalysts to our licensees. Our license agreements currently require our catalyst to be used in the initial loading of the catalyst into the Fischer-Tropsch reactor for the licensee to receive a process guarantee. After the initial fill, the licensee may use other catalyst vendors if appropriate catalysts are available. The price for catalysts purchased from us pursuant to license agreements is equal to our cost plus a specified margin. We will receive revenue from catalyst sales if and when our licensees purchase catalysts. We expect that catalysts will need to be replaced every three to five years. During 2004 and 2003, we marketed a certain amount of the catalyst materials we had on-hand, and we had classified these materials as current assets at their current market price. Revenues and costs of sales related to the sale of these materials are recorded on our statement of operations in the period in which the materials are sold. All of the materials that we were marketing were liquidated as of March 31, 2004.

License Revenues. We expect to generate revenue earned from licensing the Syntroleum Process and Synfining Process through four types of contracts: master license agreements, volume license agreements, regional license agreements and site license agreements. Master, volume and regional license agreements provide the licensee with the right to enter into site license agreements for individual GTL plants. A master license agreement grants broad geographic and volume rights, while volume license agreements limit the total production capacity of all GTL plants constructed under the agreement to specified amounts, and regional license agreements limit the geographical rights of the licensee. Master, volume and regional license agreements signed in the past have required an up-front cash deposit that may offset or partially offset license fees for future plants payable under site licenses. In the past, we have acquired technologies or commitments of funds for joint development activities, services or other consideration in lieu of the initial cash deposit in cases where we believed the technologies or commitments had a greater value.

Our site license agreements currently require fees to be paid in increments when milestones during the plant design and construction process are achieved. The amount of the license fee under our existing master and volume license agreements is currently determined pursuant to a formula based on the present value of the product of: (1) the yearly maximum design capacity of the plant, (2) an assumed life of the plant and (3) our per barrel rate, which has generally been approximately $0.50 per barrel of daily capacity for the licensing of the Syntroleum Process only and $0.65 per barrel of daily capacity for the licensing of both our Syntroleum and Synfining Processes. Our licensee

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fees may change from time to time based on the size of the plant, improvements that reduce plant capital cost and competitive market conditions. Our existing master and volume license agreements allow for the adjustment of fees for new site licenses under certain circumstances. Our accounting policy is to defer all up-front deposits under master, volume and regional license agreements and license fees under site license agreements and recognize 50 percent of the deposits and fees as revenue in the period in which the engineering process design package (“PDP”) for a plant licensed under the agreement is delivered and recognize the other 50 percent of the deposits and fees when the plant has passed applicable performance tests. The amount of license revenue we earn will be dependent on the construction of plants by licensees, as well as the number of licenses we sell in the future. To date we have received $39.5 million in cash as initial deposits and option fees under our existing license agreements. Except for $2.0 million recorded as revenue in connection with option expirations, $8.8 million of license credits returned by the Commonwealth of Australia as part of the settlement for the Sweetwater project and $10.0 million recorded as revenue as a result of the release of license credits and indemnifications, these amounts have been recorded in deferred revenue. Our obligations under these license agreements are to allow the use of the technology, provide access to engineering services to generate a PDP at an additional cost, and to refund 50 percent of the advances should the licensee build a plant that does not pass all mechanical completion testing. These licenses generally begin to expire in 2011 and the initial deposits will be recognized as licensing revenue as the licenses expire should a licensee not purchase a site license and begin construction of a plant prior to expiration of the license.

Joint Development Revenues. We continually conduct research and development activities in order to improve the conversion efficiency and reduce the capital and operating costs of GTL plants based on the Syntroleum Process. We receive joint development revenues primarily through two initiatives: (1) prospect assessment and feasibility studies and (2) formal joint development arrangements with our licensees and others. Through these joint development arrangements, we may receive revenue as reimbursement for specified portions of our research and development or engineering expenses. Under some of these agreements, the joint development participant may receive credits against future license fees for monies expended on joint research and development. During the periods presented, joint development revenues consisted primarily of amounts received from Marathon Oil Company (“Marathon”), the U.S. Department of Energy (“DOE”), the U.S. Department of Defense (“DoD”), Ivanhoe and Oil Search Ltd. Currently, Marathon is the only party that has credits against future license fees as the result of joint development activities. To date, our revenues and costs have been related to certain projects and are wholly dependent upon the nature of our projects. The various sizes and timing of these projects, including the demonstration plant located at the Port of Catoosa near Tulsa, Oklahoma (the “Catoosa Demonstration Facility”) used as part of the DOE Ultra-Clean Fuels Production and Demonstration Project (the “DOE Catoosa Project”) with Marathon, affect the comparability of the periods presented.

Product Sales Revenues. We expect to provide synthetic ultra-clean diesel fuel, such as our S-2 diesel fuel, produced from natural gas and FC-1 naphtha fuels to various customers for their use in further research and testing upon their request. Our ultra-clean S-2 diesel fuel is a paraffinic, high-cetane distillate fuel that is essentially free of sulfur, olefins, metals, aromatics or alcohols. The fuels are currently produced at our Catoosa Demonstration Facility. Revenues will be recognized upon delivery of the requested fuels.

Operating Expenses

Our operating expenses historically have consisted primarily of the construction and operation of the Catoosa Demonstration Facility, pilot plant, engineering, including third party engineering, research and development expenses and general and administrative expenses, which include costs associated with general corporate overhead, compensation expense, legal and accounting expense and expenses associated with other related administrative functions.

Our policy is to expense costs associated with the Catoosa Demonstration Facility and pilot plant, engineering and research and development costs as incurred in accordance with SFAS No. 2,Accounting for Research and Development Costs. All of these research and development expenses are associated with our development of the Syntroleum Process. The Catoosa Demonstration Facility expenses include costs to construct, maintain, and operate the facility for further research and development as well as for demonstrations for licensees and other customers. Research and development expenses include costs to operate our laboratory and technology center, salaries and wages associated with these operations, research and development services performed by universities, consultants and third parties and additional supplies and equipment for these facilities. Our policy is to expense costs associated with the development of GTL plants or other projects until we begin our front-end engineering and design program on the respective projects. We also capitalize any costs associated with a project that would have economic value for future projects. We have incurred costs related specifically to the development of our GTL Mobile Facility project. These costs, which relate primarily to outside contract services for initial

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engineering, design, and development, are included in pilot plant, engineering, research and development costs in our consolidated statements of operations.

We commenced operations at the Catoosa Demonstration Facility in the first quarter of 2004, with production of the initial finished fuels occurring on March 4, 2004. We have produced all of our contractual commitment to the DOE and have delivered fuels to a fuels testing facility in Detroit, Michigan, Denali National Park in Alaska, the University of Alaska in Fairbanks and the Washington D.C. Area Metropolitan Transit Authority. We completed our delivery requirements to the DOE during the second quarter of 2005. We are also providing fuels to several states under contracts with the Department of Transportation. We plan to continue to operate the plant through 2005, producing fuels, seeking to create new efficiency improvements, increasing our data and extending our operating experience, after which we intend to mothball the plant until such time as additional joint development programs or government fuels production contracts are forthcoming. These additional operations are estimated to cost approximately $2,700,000 for the remaining quarter of 2005.

We have also recognized depreciation, depletion, amortization and impairment expense related to our oil and gas properties in Kansas and office and computer equipment, buildings and leasehold improvements and patents. We have incurred significant costs and expenses over the last several years as we have expanded our research and development, engineering and commercial activities, including staffing levels. We expect to incur increases in our operating expenses as we continue to develop and commercialize our Mobile GTL Facility, which includes development of a barge-mounted GTL facility and development of a GTL facility placed on a floating, production, storage, and offloading vessel (“FPSO”), and other GTL and CTL technologies and commercial projects. Our operating expenses could increase further if we accelerate our development of these commercial projects.

If we are successful in developing a GTL or CTL plant in which we own an interest, we expect to incur significant expenses in connection with our share of the engineering design, construction and start-up of the plant. Upon the commencement of commercial operations of a plant, we will incur our share of cost of sales expenses relating primarily to the cost of natural gas feedstocks for and operating expenses relating to the plant, including labor, supplies and maintenance, and product marketing costs. Due to the substantial capital expenditures associated with the construction of GTL or CTL plants, we expect to incur significant depreciation and amortization expense in the future. We also expect to incur expenses related to other gas monetization projects, which could include lease operating costs, gathering and processing fees and other typical costs associated with traditional oil and gas exploration, production and processing.

Significant Developments During 2005

Commercial and Licensee Projects

OML 113.On August 27, 2004, we entered into a Heads of Agreement with Yinka Folawiyo Petroleum Company Ltd. (“YFP”), pursuant to which we are required to delineate and potentially develop an oil and gas discovery on OML 113 offshore Nigeria. The license covers approximately 413,000 acres, and our current project development plans include using our Mobile GTL Facility for development of the gas reserves in the field. Based on our review of data tapes from a previously shot 3D seismic survey, we believe that areas in this lease have the potential to contain a significant amount of oil, condensate, natural gas liquids and natural gas. We believe that the oil and condensate in the field further enhances the economics of the project by providing the potential for near term cash flows.

On October 7, 2004, we and YFP entered into a Joint Venture Agreement pursuant to the Heads of Agreement. The agreement required us to include in the project an experienced international operator of offshore oil and gas projects as the technical advisor. The agreement also required the drilling of the delineation well within the area of the Aje Field in OML 113 before February 2006. We and the international operator will bear all capital costs in the project. YFP will bear a share of operating costs after project payout, which is the date on which we achieve the full recovery of all capital, operating and production costs incurred to that date. We and YFP will also share any cash signature bonus paid by the international operator.

On January 13, 2005, we finalized agreements to begin the delineation of the Aje Field. The agreements are with YFP and the following companies, to which we refer collectively as the “Participants”: Lundin Petroleum, a publicly traded Swedish exploration and production company who will serve as the technical advisor to the project; Challenger Minerals Inc., a subsidiary of GlobalSantaFe Corporation, one of the largest international drilling contractors; Providence Resources PLC, a publicly traded Irish exploration and production company; and Howard Energy Co., Inc. and Palace Exploration Company, both privately owned U.S. exploration and production companies. In selecting these companies to participate in the Aje delineation, we have assembled the required

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technical assistance for the project. Together, we and the Participants are required to fulfill the terms of the Joint Venture Agreement between us and YFP.

We and the Participants provided to YFP a letter of credit in the amount of $10,000,000. This letter of credit is required to be secured by cash. YFP has the right to draw the full amount from the letter of credit as liquidated damages if the initial well is not drilled by February 2006. The Participants have contributed their respective shares of the cash required to secure the letter of credit and other costs associated with the letter of credit. We have recorded our 10 percent of the cash on deposit as security for the letter of credit as restricted cash on the balance sheet as of September 30, 2005.

The agreements require the Participants to pay us a signature bonus upon approval by the Nigerian authorities of the assignments of interest and the drilling permit for the first well and to pay 90 percent of the cost to drill and log one delineation well in the Aje discovery and one option well in order to earn 67.5 percent of our participating interest in OML 113. Additionally, upon commencement of commercial production, the Participants are required to pay a development bonus to us. Our net revenue interest in the project before payout is 31 percent; after project payout, our net revenue interest is reduced to approximately 25 percent. In addition, we received an overriding royalty interest from all of the interest owners in OML 113 other than YFP.

On April 14, 2005, we and other participants received approval from the Nigerian government for the assignment of interest in OML 113 offshore Nigeria to us and the participants. As a result of the approval and the receipt of the drilling permit for the first well, we received a signature bonus of approximately $9,438,000 from the Participants as part of the consideration for joining the Aje project. As a result of these agreements, payment to Sovereign in the amount of $3,719,000 was made and warrants to purchase 25,000 shares of our common stock will be issued to Sovereign at an exercise price of $6.40 per share under the joint development agreement between us and Sovereign. We recorded a gain in conveyance of interest resulting from this transaction in the amount of $3,556,000 as of September 30, 2005, after elimination of the costs of our Nigerian full cost pool at the time of conveyance.

We secured and drilled the first delineation well, which we refer to as the “Aje-3 well” during the third quarter. Our total net cost of drilling the delineation well totaled $3,331,000. In October 2005, we reached the reservoir objectives as anticipated and a detailed logging program was acquired and interpreted. Test results were evaluated after drilling for consideration of commercial completion. The Participants found the economics for commercial completion to be unfavorable. Subsequent to the quarter ended September 30, 2005, the well was plugged and abandoned. The Participants expect to meet before the end of 2005 to discuss further development of this block, according to the terms of the Participation Agreement. Three wells, including the Aje-3 well, have been drilled on the Aje structure and have proven the existence of an active petroleum system and the presence of a well developed reservoir and seal in the block. We expect further geological and geophysical evaluation of this structure to occur before the year ended December 31, 2005. The Participants agreed to pay promoted costs to drill and log one delineation well in the Aje Field discovery and one option well in order to earn a participating interest in OML 113. The Participants must decide on the drilling of a second well by March 31, 2006. We expect to incur additional expenditures relating to this project in the future, and the amount of such expenditures could be substantial.

Nigeria. We are continuing to pursue negotiations with numerous independent Nigerian field owners to farm into their blocks. These arrangements would allow Nigerian field owners to assign all or part of the working interest in their respective blocks to us in return for obligations to explore and develop the property. We believe that our GTL technology and our experience with OML 113 increase our ability to form an industry consortium to begin development of these blocks. At least one well with discovered crude oil, natural gas or both previously has been drilled on each of the blocks with respect to which we are in negotiations.

The Nigerian government has been focused on developing plans to monetize their gas reserves. We and NNPC, Nigeria’s state-owned oil company, have been discussing solutions to the monetization of gas reserves. We have signed a confidentiality agreement with NNPC, which has begun to provide us with data and several senior technical staff personnel to work with us. Based on information from IHS data and satellite imagery, we and Sovereign have identified numerous potential locations in the Niger Delta where we believe a significant amount of non-producing natural gas exists and which have water access for a mobile GTL facility to produce the stranded and flared natural gas. We anticipate reaching a heads of agreement with NNPC and their partners to select the most attractive of these potential opportunities for GTL installations in the future.

The Nigerian government had been seeking companies for further development of many of its blocks and accepted bids for these blocks. We evaluated these blocks based on the opportunities contemplated by our business model. The Nigerian government has indicated its preference for companies with downstream solutions, such as our GTL technology. After careful evaluation of these blocks we did not bid on the blocks. All of our Nigerian activities are partially funded by the Stranded Gas Venture as described below.

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Stranded Gas Venture. In April 2005, we formed a venture for the primary purpose of providing funds to acquire rights to stranded gas and liquids with respect to projects currently being evaluated and future projects (“Stranded Gas Venture”). We may use funds from the venture to fund our costs of evaluation and acquisition of rights to stranded gas and liquids reserves, including cost to (1) conduct geologic, geophysical and reservoir analysis of investment opportunities, (2) conduct oil and gas project development activities and (3) acquire interests in oil and gas properties, including projects that involve traditional methods of production and processing, as well as projects that may later include the use of our GTL technologies. In connection with this venture, we have entered into a Participation Agreement with Dorset Group Corporation (“Dorset”), which committed $40,000,000 to the venture.

In April 2005, we also entered into a Joinder Agreement with the Ernest Williams II Q-TIP TUA dated 01/25/2002, which joined the Participation Agreement as a venture participant and agreed to provide a capital commitment of $10,000,000 to us.

In September 2005, we entered into a Joinder Agreement with Selim K. Zilkha Trust which joined the Participation Agreement as a venture participant and agreed to provide a capital commitment of $10,000,000 to us.

Under the terms of the Participation Agreement, the other venture participants will fund 100 percent of the costs to acquire the rights to stranded gas and liquids projects and will receive 20 percent of the interest that we acquire in any such project. Net cash proceeds received from our share of any project, including bonuses, or net revenues from the sale of production attributable to our working interest or overriding royalty interests in a project, less the payment of any operating expenses and maintenance capital expenditures, taxes, royalties or other required payments to a governmental entity, will be paid as follows:

• first, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to 80 percent of the sum of such participant’s individual cost basis in all of the then existing projects in which such participant participated;

• second, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to a return of 10 percent per annum, compounded annually, on 80 percent of the sum of such participant’s individual costs basis in all of the projects in which such participant participated; and

• third 100 percent to us.

On April 25, 2005, our stockholders approved an amendment to the our consulting agreement with TI Capital Management, a firm owned by Mr. Ziad Ghandour, one of our directors, which provides for the issuance to Mr. Ghandour of cash, common stock and warrants to purchase common stock as compensation upon the achievement of various goals set forth in the agreement. In October 2005, Mr. Ziad Ghandour became a full time employee of our company. The payment of compensation under the agreement to Mr. Ghandour is subject to the satisfaction of specific criteria. As a result of entering into the Participation Agreement and related Joinder Agreements with respect to the Stranded Gas Venture, we have issued 103,627 shares of common stock and paid $600,000 in cash to Mr. Ghandour in accordance with the amended consulting agreement. This agreement expires on September 30, 2007.

Mobile GTL Facility. In August 2003, we announced our plan to commercialize a GTL Barge. The GTL Barge is designed to develop offshore and near-shore coastal natural gas fields in the one to three trillion cubic feet (“TCF”) range where there is currently no infrastructure to produce and transport the stranded reserves. These fields are generally considered to be too small to support a liquefied natural gas facility. The GTL Barge builds on the strengths and advantages of the Syntroleum Process, which utilizes air instead of oxygen. The GTL Barge is also designed to have equipment to process natural gas liquids. We expect that a single GTL Barge would be designed to produce approximately 20,400 barrels per day (“b/d”) of total products, of which 8,700 b/d would be zero sulfur diesel fuel. The balance would be a mix of naphtha and natural gas liquids.

In February 2005, we executed an agreement with Bluewater Energy Services B.V. (“Bluewater”) to conduct a feasibility study and engineering study for placing a small GTL plant on an FPSO. The study is expected to cost $2.0 million, of which we and Bluewater will bear 25 percent and 75 percent of the costs, respectively. If, after the study, the parties to the agreement elect to pursue opportunities for a GTL FPSO, the parties will seek to negotiate definitive agreements covering the possible acquisition of oil and gas reserves or other opportunities for use of the GTL FPSO. Neither we nor Bluewater may pursue a study of opportunities for the GTL FPSO with third parties before December 31, 2006 without the consent of the other party.

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Coal-to-Liquids.In addition to enabling monetization of stranded natural gas, we expect that our GTL technology can be applied to coal. The largest coal reserves are located in the United States, Russia, India, China and Australia. Much of these reserves are difficult and expensive to utilize because of environmental concerns and distance to markets. By applying the Syntroleum Process, integrated with third party gasification and syngas clean up technology, these underused coal resources could be converted to ultra-clean transportation fuels, thus providing a new source of clean energy and reducing dependence on oil from politically unstable regions. In response to the growing demand for development and application of clean-coal technologies in the United States and availability of stranded coal at prices comparable to standard natural gas internationally, we are undertaking a comprehensive evaluation of this opportunity. We are currently exploring alternatives for raising capital, including entering into joint ventures or other relationships with companies, to fund the growth of our coal to liquids business, including the development, and demonstration of effectiveness, of our technology with coal-derived synthesis gas.

Linc Energy, Ltd.On August 15, 2005, we entered into a Memorandum of Agreement with Australian- based Linc Energy, Ltd. (“Linc Energy”) to pursue the development of a CTL project using the Syntroleum Process in Queensland, Australia. The agreement, which enable our technology to benefit from Linc Energy’s underground coal gasification (“UCG”) expertise, is part of Linc Energy’s ongoing Chinchila Project. The terms of the agreement include cooperation on the Chinchilla Project and future UCG-CTL projects to be pursued by Linc Energy under a CTL license from us, and provide us with an option to invest in the equity of these projects. We and Linc Energy have agreed to jointly fund a series of technology demonstration programs in advance of developing engineering designs for the CTL projects. The agreement terminates on December 31, 2005, unless extended by mutual agreement of the parties.

Domestic Gas Monetization. We are pursuing gas monetization projects in which we are directly involved in gas field development using available gas processing technologies from third parties. We have secured the exclusive rights to use two different gas processing technologies from third parties in certain areas in Central Kansas and three counties in the Permian Basin of Texas. To date, we have leased approximately 85,000 acres in the Central Kansas Uplift area. Drilling of eight and the re-entry of three wells commenced during the third quarter of 2004, with successful testing of the first well drilled. Limited production from the first well began in January 2005.

As of September 30, 2005, we have capitalized $4,704,000 in oil and gas property and equipment related to drilling, geological and geophysical costs, and lease acquisitions and $1,583,000 in oil and gas property and equipment related to gas processing equipment. We completed our evaluation of potential reserves related to drilled properties in the United States. Subsequent to September 30, 2005, we decided to discontinue further expenditures in the Central Kansas uplift area based on current economics of the area and, therefore, determined potential reserves to be zero. We have amortized these properties based on the evaluated reserves. We recorded amortization and depletion of $2,195,000 during the nine months ended September 30, 2005 for these properties. Because the discounted estimated future net revenues attributable to proved reserves were less than the unamortized costs of the evaluated oil and gas properties, an impairment of $846,000 was recognized for the oil and gas properties. We recorded an additional impairment of $481,000 related to the gas processing plant and equipment. Management has decided to focus efforts on aligning the company with specific goals and has classified these assets as held for sale as they are not in line with current strategic activities. We have successfully completed a sale of certain leasehold acres in the amount of $1,000,000 subsequent to the quarter ended September 30, 2005. We expect to sell the remaining acreage by the end of 2006.

Qatar.In the Middle East, Qatar has one of the world’s largest single gas fields, the North Field, with recoverable reserves that are sufficient to support multiple GTL projects. Marathon, one of our licensees, currently has development plans underway for building a large commercial GTL plant in Qatar. Marathon is currently working with various industry participants and Qatar Petroleum to pursue technical and commercial discussions that could lead to a GTL project capable of converting natural gas from the North Field of Qatar into ultra-clean diesel and other liquid hydrocarbon products for export to world markets. In June 2004, we entered into a letter of intent with Marathon on terms for a site license for the Qatar project to be executed contingent upon the signing of a Heads of Agreement (“HOA”) with Qatar Petroleum for a nominal 120,000 b/d GTL plant. Under the site license terms, we will receive approximately $125 million, approximately 40 percent of which would be realized upon achievement of certain project milestones over the first five years following the HOA. The remainder of the revenue would be based upon actual production volumes from the plant over the first 15 years of the plant’s operation. The terms of this letter of intent are subject to the execution of definitive agreements. We are also continuing to support Marathon in its GTL product development efforts through the use of our technology demonstration facilities and technology support staff. In April 2005, the Minister of Energy of Qatar announced that the Marathon GTL project in Qatar, along with ConocoPhillips, Chevron and others, are being delayed for approximately three years. Marathon has announced that it remains interested in pursuing the project in Qatar, notwithstanding the delay, as well as other GTL projects around the world.

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Ivanhoe Energy.Ivanhoe Energy Inc. (“Ivanhoe”) and Egyptian Natural Gas Holding Company (“EGAS”), the state organization charged with the management of Egypt’s natural gas resources, signed a memorandum of understanding to enable Ivanhoe to conduct and prepare a feasibility study to construct and operate a GTL plant in Egypt. Ivanhoe holds a master unlimited-volume license with us. Ivanhoe has announced that, if the results of the feasibility study are positive, EGAS has agreed to commit up to 4.2 trillion cubic feet of natural gas per day for the anticipated 20-year operating life of the proposed project.

Demonstration and Scale-up Activities

DOE Catoosa Project. The DOE concluded an agreement in 2001 with Integrated Concepts and Research Corporation to provide funding to a team of companies for the DOE Catoosa Project for which we received preliminary approval in October 2000. In May 2002, we signed a participation agreement with Marathon in connection with this project. The agreement provides for an executive committee comprised of a majority of Syntroleum representatives to govern the project. Under the program, our Cherry Point GTL facility has been disassembled and relocated from ARCO’s Cherry Point Refinery in Washington State to a site located at the Port of Catoosa near Tulsa, Oklahoma. This facility was the basis for construction of a new GTL facility designed to produce up to approximately 70 b/d of synthetic product. The plant was mechanically completed and dedicated on October 3, 2003, and startup and fuel deliveries commenced in the first quarter of 2004. We and Marathon have installed additional facilities at the Catoosa Demonstration Facility outside the scope of the DOE Catoosa Project.

Funding received from the DOE during 2003 and 2004 was recorded in deferred revenue until the final shipment of the finished fuels is completed, which occurred in the second quarter of 2005. As a result, we have recognized $5,798,000 in joint development revenues for the nine months ended September 30, 2005. The fuels from this facility have been tested by other project participants in advanced power train and emission control technologies and were also tested in bus fleets by the Washington Metropolitan Area Transit Authority and the U.S. National Park Service at Denali National Park in Alaska.

We expensed $7,039,000 during the nine months ended September 30, 2005 for our Catoosa Demonstration Facility, including costs of operations and other projects at the facility. Since this project is not for commercial operations, these costs have been expensed in accordance with SFAS No. 2,Accounting for Research and Development Costs. The project has been funded by us and the other project participants, including $12.0 million from the DOE, labor contributions of $4.3 million and a $5.0 million cash contribution by Marathon, and a $21.3 million loan agreement between Marathon and us. DOE funding of approximately $1.2 million has been approved for the fourth budget period from December 15, 2003 through December 31, 2005. We have received all funding for the prior budget periods. We have completed our fuel production and delivery commitments in connection with the DOE Catoosa Project. We plan to continue to operate the plant through 2005, producing fuels, seeking to create new efficiency improvements, increasing our data and extending our operating experience, after which we intend to mothball the plant until such time as additional joint development programs or government fuels production contracts are forthcoming.

DOE Coal-to-Liquids Project. In March 2005, Congress appropriated funding of $4.5 million to Integrated Concepts and Research Corporation and us to evaluate commercially available coal gasification and synthesis gas or “syngas” cleanup technologies and the integration of these processes with a cobalt catalyst based Fischer-Tropsch (“FT”) technology. We anticipate that the results of this work will provide a foundation for the development of a coal-to-liquids plant based on a cobalt catalyst FT technology. Additionally, engineering and economic analysis will be utilized to evaluate the commercial feasibility of a plant in a coal-producing state.

DoD Project. In January 2002, Congress appropriated $3.5 million for a proposed Flexible JP-8 (“single battlefield fuel”) Pilot Plant program under the Department of Defense Appropriation Bill, 2002. In September 2002, we signed a $2.2 million contract with the DoD to participate in the program, in which we will provide for the design of a marine-based fuel-production plant, as well as testing of synthetically made GTL JP-8 fuel in military diesel and turbine engine applications. Phase I of this program is now complete, and all the work done to date has validated our beliefs in the performance of the single battlefield fuel product and in the design of the barge-mounted unit to produce the fuel. We have recorded joint development revenues totaling $2.2 million over the life of this contract, including $1.7 million during 2003 and $0.5 million in 2002.

Congress has appropriated $2.0 million for Phase II development of our proposed Flexible JP-8 single battlefield fuel Pilot Plant Program under fiscal year 2004 DoD appropriations legislation. We expect to receive approximately $950,000 under the appropriation. Phase II will include expanded engineering and design work for fuel production systems and further single battlefield fuel characterization and demonstration work. Finalization of

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our contracts occurred in the fourth quarter of 2004, and we began work at that time. We have recognized $368,000 in joint development revenue from this project for the nine months ended September 30, 2005 and expect to complete the remainder of the work by 2007.

In August 2004, Congress appropriated $4.5 million for Phase III development of our Flexible JP-8 single battlefield fuel Pilot Plant Program for advanced concept technology development under the DoD fiscal 2005 appropriations legislation. We expect to receive approximately $2.8 million under the appropriation. Phase III of this program will include expanded engineering and design work for single battlefield fuel production systems for sea and land and further single battlefield fuel characterization and demonstration work for all branches of the military. Finalization of the contracts for this phase occurred in the second quarter of 2005. We have recognized $456,000 in joint development revenue from this project for the nine months ended September 30, 2005 and expect to complete the remainder of the work by August 2006.

DOT Fuel Evaluation Program.In November 2005, the Department of Transportation, (“DOT”) concluded an agreement with ICRC to provide funding for demonstration of the operating performance benefits and development of the market acceptance of Ultra-Clean Fischer-Tropsch diesel fuels in transit bus fleet covering a range of climates. Oklahoma and Alabama transit bus fleets will demonstrate and test our S-2 FT diesel fuel. Alaskan transit bus fleets will demonstrate and test our S-1 arctic-grade FT diesel fuel. We expect to receive approximately $1.0 million in fuel sales and labor for this program.

Research and Development Projects

Our primary research and development projects during the nine months ended September 30, 2005 related to our GTL technologies for use in GTL plants, including confirmation of catalyst performance and reactor designs. Expenses for pilot plant, engineering and research and development incurred during the nine months ended September 30, 2005 totaled $7,586,000. These expenses related to salaries and wages, outside contract services, lab equipment and improvements and laboratory operating expenses, which primarily supported work on technology we plan to use in fuels plants and our Mobile GTL Facility.

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004

Joint Development Revenue. Revenues from our joint research and development and pilot plant operations were $616,000 during the three months ended September 30, 2005, an increase of $401,000 from the same period in 2004 when they were $215,000. The majority of our joint development revenues for the period ended September 30, 2005 and 2004 is related to funding for research and development activities by licensees, the United States government and other third parties.

Gas Sales. Natural gas sales from the production in our Central Kansas Uplift area were $9,000 during the three months ended September 30, 2005. There were no natural gas sales during the three months ended September 30, 2004.

Other.Revenues from our sales of synthetic diesel fuel and other byproducts to third parties for research and testing were $92,000 during the three months ended September 30, 2005. There were no sales of synthetic diesel fuel or other byproducts during the three months ended September 30, 2004.

Lease Operating Expenses.Expenses related to the production and sale of oil and gas totaled $2,000 for the three months ended September 30, 2005. There were no expenses related to the production and sale of oil and gas for the three months ended September 30, 2004.

DOE Catoosa Project. Expenses related to the DOE Catoosa Project totaled $2,456,000 during the three months ended September 30, 2005, a decrease of $1,308,000 compared to $3,764,000 of expenses incurred during the three months ended September 30, 2004. The decrease in these expenses is a result of modifications made to the facility during the period ended September 30, 2004 and a decrease in operating time for the period ended September 30, 2005.

Pilot Plant, Engineering and R&D Expense. Expenses from pilot plant, engineering and research and development activities were $2,980,000 during the three months ended September 30, 2005, up $752,000 from the three months ended September 30, 2004 when these expenses were $2,228,000. These expenditures relate to salaries and wages for our technology group, modifications and operations of the pilot plant, process design documentation, as well as continued research on other projects.

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Depreciation, Depletion, Amortization, and Impairment.Depreciation, depletion, amortization and impairment expense totaled $6,118,000 and $150,000 for the three months ended September 30, 2005 and 2004, respectively. The increase is a result of depletion and amortization of our oil and gas properties in Kansas in the amount of $1,736,000, an impairment of $806,000 for our Kansas and other oil and gas properties and gas processing equipment and a write down for the Aje-3 delineation well on OML 113 in Nigeria totaling $3,331,000.

General and Administrative Expense. General and administrative expenses were $4,955,000 during the three months ended September 30, 2005, down $701,000 from the three months ended September 30, 2004 when these expenses were $5,656,000. The decrease is attributable to our non-cash equity compensation expense. Equity compensation expense for the vesting of stock compensation awards to employees and consultants totaled $552,000 and $1,234,000 for the three months ended September 30, 2005 and 2004, respectively. The decrease in non-cash equity compensation is the result of the vesting of warrants issued to consultants for the achievement of goals under agreements with these consultants for the period ended June 30, 2004.

Investment and Interest Income. Investment and interest income was $785,000 during the three months ended September 30, 2005, up $607,000 from the three months ended September 30, 2004 when this income was $178,000. The increase is due to higher interest received on our increased cash balance.

Interest Expense. Interest expense was $430,000 during the three months ended September 30, 2005 compared to $454,000 during the three months ended September 30, 2004. The interest expense is related to the Marathon convertible debt. This principal and interest may be repaid through capital contributions from a third party, credits against future license fees, conversion into our common stock at no less than $6.00 and not more than $8.50 per share, or a cash payment at our option.

Other Income (Expense) and Foreign Exchange. Other income (expense), including foreign exchange gain (loss) and minority interest, was income of $25,000 during the three months ended September 30, 2005, compared to loss of $616,000 during the three months ended September 30, 2004. This increase is the result of foreign exchange losses in relation to the Australian dollar regarding our license agreement totaling $416,000 and the settlement of a lawsuit for $200,000 for the period ending September 30, 2004.

Net Income (Loss). During the three months ended September 30, 2005, we experienced a loss of $15,414,000. The loss was $2,939,000 higher than in the three months ended September 30, 2004 when we experienced a loss of $12,475,000. The increase in the net loss is primarily a result of increased joint development revenues, depreciation, depletion, amortization, impairment, and other factors described above.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004

Joint Development Revenue. Revenues from our joint research and development and pilot plant operations were $7,044,000 in the first nine months of 2005, compared to $612,000 in the first nine months of 2004. Joint development revenues for the nine months ended September 30, 2005 included the recognition of $5,798,000 related to the recognition of previously deferred revenue in regards to the completion of our fuel delivery commitment with the DOE and other funding for research and development activities by licensees and third parties. The majority of our joint development revenues for the nine months ended September 30, 2004 relate to funding for research and development activities by licensees, the United States government and other third parties.

Catalyst Materials Sales. There were no revenues from catalyst materials sales during the nine months ended September 30, 2005. Revenues from catalyst materials sold during the nine months ended September 30, 2004 were $5,674,000. These materials were obtained in connection with our suspended Sweetwater Project and were not necessary for any of our current projects.

Gas Sales. Natural gas sales from the production in our Central Kansas Uplift area were $70,000 during the nine months ended September 30, 2005. There were no natural gas sales during the nine months ended September 30, 2004.

Other.Revenues from our sales of synthetic diesel fuel and other byproducts to third parties for research and testing and other were $98,000 during the nine months ended September 30, 2005. Revenues from sales of synthetic diesel fuel or other byproducts and other were $3,000 during the nine months ended September 30, 2004.

DOE Catoosa Project. Expenses related to the DOE Catoosa Project totaled $7,039,000 during the first nine months of 2005, a decrease of $3,122,000 compared to the $10,161,000 of expenses incurred during the first

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nine months of 2004. The decrease in these expenses is a result in modifications made to the facility during the period ended September 30, 2004 and a decrease in operating time for the period ended September 30, 2005.

Pilot Plant, Engineering and R&D Expense. Expenses from pilot plant, engineering and research and development activities were $7,586,000 in the first nine months of 2005, up $560,000 from the first nine months of 2004 when these expenses were $7,026,000. These expenditures relate to salaries and wages for our technology group, modifications and operations of the pilot plant, process design documentation, increased joint development activities, as well as continued research on other projects.

Cost of Catalyst Materials Sales. There were no catalyst materials sold during the nine months ended September 30, 2005, compared to $3,033,000 for the nine months ended September 30, 2004.

Depreciation, Depletion, Amortization, and Impairment.Depreciation, depletion, amortization and impairment expense totaled $7,499,000 and $440,000 for the nine months ended September 30, 2005 and 2004, respectively. The increase is a result of depletion and amortization of our oil and gas properties in Kansas in the amount of $2,195,000 an impairment of $1,337,000 for our Kansas and other oil and gas properties and gas processing equipment and a write down for the Aje-3 delineation well on OML 113 in Nigeria totaling $3,331,000.

General and Administrative Expense. General and administrative expenses were $17,163,000 in the first nine months of 2005, up $1,377,000 from the first nine months of 2004 when these expenses were $15,786,000. The increase is attributable primarily to increased overhead due to workforce additions and non-cash equity compensation expense. Equity compensation expense for the vesting of stock compensation awards to employees and consultants totaled $3,788,000 and $3,151,000 for the nine months ended September 30, 2005 and 2004, respectively. The totals in non-cash equity compensation is the result of vesting of stock options to employees and warrants issued to consultants for the achievement of goals under agreements for both periods presented.

Investment and Interest Income. Investment and interest income was $1,731,000 in the first nine months of 2005, up $1,049,000 from the first nine months of 2004 when this income was $682,000. The increase is due to higher dividends and interest received on our increased cash balance.

Interest Expense. Interest expense was $1,275,000 during the first nine months of 2005, compared to $1,338,000 during the same period in 2004. This interest expense is related to the Marathon convertible debt. The principal and interest may be repaid through capital contributions from a third party, credits against future license fees, conversion into our common stock at no less than $6.00 and not more than $8.50 per share, or a cash payment at our option.

Other Income (Expense) and Foreign Exchange. Other income (expense), including foreign exchange gain (loss) and minority interest, was income of $4,023,000 in the first nine months of 2005, compared to income of $169,000 during the first nine months of 2004. This increase is due to the signature bonus we received in the second quarter of 2005 from the Participants in the Aje Field development project, compared to foreign currency exchange gains for the same period in 2004.

Provision for Income Taxes. Income tax expense was $0 and $12,000 in the first nine months of 2005 and 2004, respectively. Tax expense during the period ended September 30, 2004 represents the Australian withholding tax imposed on interest we earned on funds held in Australian bank accounts and on the second advance of loan proceeds under our loan agreement with the Commonwealth of Australia. We do not have remaining funds in Australian bank accounts and do not expect to incur similar withholding tax expense. We incurred a loss in the first nine months of 2005 and 2004 and did not recognize an income tax benefit for these losses.

Net Income (Loss).In the first nine months of 2005, we experienced a loss of $27,612,000. The loss was $3,044,000 lower than in the first nine months of 2004 when we experienced a loss of $30,656,000. The decrease in the net loss is primarily a result of the recognition of revenue for the completion of delivery of fuels for the DOE contract, receipt of the Aje signature bonus, and other factors described above.

Liquidity and Capital Resources

General

As of September 30, 2005, we had $82,024,000 in cash and short-term investments. We also had $3,776,000 in restricted cash related primarily to our agreement with Sovereign, a consulting firm that has assisted us in acquiring natural gas fields worldwide, and our letter of credit with YFP. YFP has the right to draw the full

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amount from the letter of credit as liquidated damages if the initial well is not drilled on OML 113 before February 2006. Subsequent to September 30, 2005 the requirements for drilling of the initial test well were fulfilled completed and the letter of credit was released. Our current liabilities totaled $31,591,000, including $25,496,000 of convertible debt with Marathon that matures on June 30, 2006.

At September 30, 2005, we had $512,000 in accounts receivable outstanding relating to our Catoosa Demonstration Facility, gas sales, and joint development activities. We believe that all of the receivables currently outstanding will be collected and therefore we have not established a reserve for bad debts.

Cash flows used in operations were $23,720,000 during the nine months ended September 30, 2005, compared to $31,254,000 during the nine months ended September 30, 2004. Cash flows used in operations included increased research and development costs and the continued operations of our Catoosa Demonstration Facility and non cash expenditures of depreciation, depletion, amortization and impairment. The decrease results from lower costs at the Catoosa Demonstration Facility and increased investment and interest income, increases in non-cash expenses for non-cash compensation, depreciation, depletion, amortization, and impairment, offset by the liquidation of catalyst materials in the period ended September 30, 2004

Cash flows used in investment activities were $9,391,000 during the nine months ended September 30, 2005, compared to cash flows provided by investment activities of $19,278,000 during the nine months ended September 30, 2004. The increase in cash used in investing activities is primarily related to the increase in capital expenditures of oil and gas assets and escrow accounts established for the Aje-3 well and Sovereign, offset by the increase in cash provided by the settlement with the Commonwealth of Australia in the same period in 2004.

Cash flows provided by financing activities were $83,566,000 during the nine months ended September 30, 2005, compared to $17,832,000 during the nine months ended September 30, 2004. The increase in cash flows provided by financing activities relates to the proceeds received from the sale of stock and option exercises totaling $81,487,000 during the nine months ended September 30, 2005 compared to $31,765,000 during the same period in 2004.

We have expended and will continue to expend a substantial amount of funds to continue the research and development of our GTL technologies, to market the Syntroleum Process, to design and construct GTL plants, and to develop our other commercial projects. Our current plan includes funds for projects for pilot plant, engineering and research and development activities throughout the rest of the year and operations of our Catoosa Demonstration Facility through 2005. We also expect to invest capital into our international and domestic oil and gas opportunities during 2005, with partial funding provided by our Stranded Gas Venture. We intend to obtain additional funds through collaborative or other arrangements with strategic partners and others and through debt (including debt which is convertible into our common or preferred stock) and equity financing. We also intend to obtain additional funding through joint ventures, license agreements and other strategic alliances, as well as various other financing arrangements to meet our capital and operating cost needs for various projects. We are currently exploring alternatives for raising capital to fund the growth of our CTL business, including the development, and demonstration of effectiveness, of our technology with coal-derived synthesis gas.

We have an effective registration statement for the proposed offering from time to time of shares of our common stock, preferred stock, debt securities, depository shares or warrants for an aggregate offering price of approximately $102 million. If adequate funds are not available, we may be required to delay or to eliminate expenditures for our capital projects, as well as our research and development and other activities or seek to enter into a business combination transaction with or sell assets to another company. We could also be forced to license to third parties the rights to commercialize additional products or technologies that we would otherwise seek to develop ourselves. If we obtain additional funds by issuing equity securities, dilution to stockholders may occur. In addition, preferred stock could be issued in the future without stockholder approval, and the terms of our preferred stock could include dividend, liquidation, conversion, voting and other rights that are more favorable than the rights of the holders of our common stock. We can give no assurance that any of the transactions outlined above will be available to us when needed or on terms acceptable or favorable to us.

Assuming the commercial success of the plants based on the Syntroleum Process, we expect that license fees, catalyst sales and sales of products from GTL or CTL plants in which we own an interest will be a source of revenues. In addition, we could receive revenues from other commercial projects we are pursuing. However, we may not receive any of these revenues, and these revenues may not be sufficient for capital expenditures or operations and may not be received within the expected time frame. If we are unable to generate funds from operations, our need to obtain funds through financing activities will be increased.

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Construction and operation of GTL and CTL plants will depend on the availability of feedstock at economic prices. The market for natural gas and coal is highly competitive in many areas of the world and, in many circumstances; the cost of natural gas and coal for use as a feedstock in a GTL or CTL plant is not economic.

We have sought and intend to continue to temporarily invest our assets, pending their use, so as to avoid becoming subject to the registration requirements of the Investment Company Act of 1940. These investments are likely to result in lower yields on the funds invested than might be available in the securities market generally. If we were required to register as an investment company under the Investment Company Act, we would become subject to substantial regulation that could materially adversely affect us.

Contractual Obligations

The following table sets forth our contractual obligations as of September 30, 2005:

Contractual Obligations	Payments Due by Period
	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Long Term Debt Obligations	$	25,496	$	25,496	$	—	$	—	$	—
Purchase Obligations		—		—		—		—		—
Capital (Finance) Lease Obligations		204		127		77		—		—
Operating Lease Obligations		9,344		1,415		3,212		771		3,946
Other Long-Term Liabilities reflected on the Balance Sheet under GAAP		3,245		5		—		—		3,240
Total	$	38,289	$	27,043	$	3,289	$	771	$	7,186

Long-term debt obligations represent our convertible loan agreement with Marathon related to our DOE Catoosa Project. This agreement provides project funding pursuant to advances under two secured promissory notes totaling $25.5 million between Marathon and us for costs relating to the DOE Catoosa Project. At September 30, 2005, we had received advances of $21.3 million under the loan and we had accrued interest of $4.2 million. Each note bears interest at a rate of 8 percent per year and matures on June 30, 2006. If we obtain capital for the DOE Catoosa Project from a third party, these capital contributions will be required to be applied towards the outstanding principal and interest of the notes. Under this agreement, the form of repayment includes a right for Marathon to convert the investment into a combination of credits against future license fees or into our stock at no less than $6.00 per share and no more than $8.50 per share. Under certain circumstances, we may also elect to repay the notes in cash. The promissory notes are secured by a mortgage in the assets of the project. Events of default under the promissory notes include failure by us to comply with the terms of the promissory notes, events of our bankruptcy, a material adverse effect on us, a change of control of us and our current assets minus current liabilities falling below $10 million (excluding amounts due under the promissory notes and liabilities associated with prepaid license fees). At September 30, 2005, we were in compliance with the provisions of the note agreements. The DOE Catoosa Project is partially funded with these note agreements, as changes in the scope of the project have occurred. We expect to pay off the balance of the notes with Marathon for the DOE Catoosa Project either from license fees due to us under a site license with Marathon or through other means as provided in the note.

The Participation Agreement with respect to the Stranded Gas Venture provides for project funding to be used to evaluate investment opportunities, conduct oil and gas project development activities, and acquire interests in oil and gas properties. Once proceeds are received from the venture group for these costs, a joint venture liability is recognized. This liability consists of 80 percent principal and 20 percent ownership interest. Interest is accrued on the principal amount at an annual rate of 10 percent, compounded annually, in accordance with the guaranteed rate of return in the Participation Agreement. Once proceeds are received from a venture project, the joint venture liability for the principal amount and accrued interest will be reduced appropriately for any repayment of the funds advanced by the venture group.

Our operating leases include leases for corporate equipment such as copiers, printers and vehicles. We have leases on our laboratory and our Houston office. Because the ground lessor did not remove us from the lease, we also remain the lessee of a parking garage in Reno, Nevada that we sold to Fitzgerald’s Casino in 2001. This lease is currently paid by Fitzgerald’s Casino and is part of the sale agreement executed in 2001; however, it is included in our schedule of contractual obligations above.

Pursuant to the Joint Venture Agreement we entered into with YFP regarding potential development of an oil and gas discovery on OML 113 as described in “Significant Developments During 2005 — Commercial and Licensee Projects — OML 113” above, we and the Participants in the joint venture have provided to YFP a $10 million letter of credit which is guaranteed by cash totaling $10.2 million. Following the finalization of the agreements with the

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Participants in January 2005, each company paid its proportionate share to guarantee this letter of credit. If we do not commence the drilling of a delineation well by February 15, 2006, YFP will have the right to draw the full amount from the letter of credit as liquidated damages. Upon such draw, we will reassign to YFP any participating rights we hold in OML 113. Subsequent to September 30, 2005, the requirements for drilling of the initial test well were fulfilled and the letter of credit was released.

Equity Issuances During 2005

In February 2004, we issued warrants to purchase up to 1,170,000 shares of our common stock to Mr. Ziad Ghandour, one of our directors and consultant to us, pursuant to an amended and restated consulting agreement with TI Capital Management, a firm owned by Mr. Ziad Ghandour. In October 2005, Mr. Ziad Ghandour became a full time employee of our company. The warrants to purchase 170,000 shares at an exercise price of $5.00 per share are exercisable from the date of stockholder approval, which was received on April 26, 2004. The warrants to purchase 500,000 shares at an exercise price of $4.50 per share vested in September 2004 in relation to work completed with Dragados Industrial S.A. The warrants to purchase 500,000 shares at an exercise price of $5.25 per share became exercisable in February 2005 as a result of our agreement with Bluewater Energy Services B.V. All warrants will expire on November 4, 2007. On January 24, 2005, Mr. Ziad Ghandour exercised 200,000 of these warrants to purchase shares of our common stock at an exercise price of $4.50 per share, resulting in proceeds to us of approximately $900,000.

During 2004, we granted restricted common stock units to certain employees under our existing stock option and incentive plans. One-third of these restricted units vested on the date of grant, an additional one-third vest on the first anniversary of the date of grant, and the remaining units vest on the second anniversary of the date of grant. We recorded deferred compensation for these units totaling $2,137,000 at the time of grant based on the market price of our common stock on that date. Total compensation expense related to the vesting of these units was $469,000 during the nine months ended September 30, 2005. In connection with the vesting of 141,837 stock awards during the period ended September 30, 2005, we repurchased and subsequently cancelled a total of 40,754 shares of common stock as settlement for the employees’ payroll taxes.

In January 2005, we granted an aggregate of 84,081 shares of common stock to certain employees under our existing stock option and incentive plans related to service performed in 2004. These shares were fully vested on the date of grant. We recognized compensation expense of $774,000 during the year ended December 31, 2004 for the stock awards that were granted to employees in 2005 related to this plan based on the value of our common stock on January 24, 2005. In connection with the vesting of restricted shares, we repurchased and subsequently cancelled a total of 17,282 shares of common stock as settlement for the employees’ payroll taxes.

On January 28, 2005, Sovereign exercised warrants to purchase 8,750 shares of our common stock at an exercise price of $6.40 per share, resulting in proceeds of approximately $56,000.

On March 17, 2005, we completed the sale of 7,000,000 shares of common stock at a price of $10.00 per share. We sold all of these shares directly to Legg Mason Opportunity Trust, a series of Legg Mason Investment Trust, Inc., a registered investment company. The sale resulted in net proceeds to us of approximately $69,950,000.

On April 14, 2005 we completed the sale of 1,000,000 shares of our common stock at a price of $10.00 per share. We sold all of these shares directly to Dorset. The sales resulted in net proceeds to us of approximately $9,968,000.

On April 25, 2005, our stockholders approved the adoption of the Syntroleum Corporation 2005 Stock Incentive Plan (the “Plan”), which provides for the issuance of up to 6,600,000 shares of our common stock pursuant to the grant of stock options, stock appreciation rights, stock awards (including restricted stock and stock units) and performance awards. Awards will be available for grant to our employees, independent contractors and non-employee directors, except that non-employee directors may only be granted awards of stock appreciation rights, stock options or restricted stock under the Plan. The Board of Directors has established an annual incentive plan under which employees are eligible to receive a certain number of shares of common stock based on the achievement of certain company-wide objectives and the individual’s performance rating for the year. The Board of Directors has established objectives on which we will be measured which determines a number of shares to be issued to employees based on a rating system.

On April 25, 2005, our stockholders approved an amendment to the consulting agreement with TI Capital Management, which provides for the issuance to Mr. Ghandour of cash, common stock and warrants to purchase common stock as compensation upon the achievement of various goals set forth in the agreement. The payment of

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compensation under the agreement to Mr. Ghandour is subject to the satisfaction of specific criteria. As a result of entering into the Participation Agreement and Joinder Agreements with respect to the Stranded Gas Venture, described above under “Significant Developments During 2005-Commercial and Licensee Projects-Stranded Gas Venture,” we have issued 103,627 shares of common stock and paid $600,000 in cash to Mr. Ghandour in accordance with the amended consulting agreement. This agreement expires on September 30, 2007.

On June 30, 2005, we entered into stock option award agreements with certain of our officers under our 2005 Stock Incentive Plan. Depending on the sustained stock price of our common stock and the net present value of future cash flows, a percentage of the options will vest as determined in a performance vesting schedule with respect to the period commencing on the date of grant and ending on December 31, 2010 (the “Performance Period”). The term of each option is ten years from the date of grant. “Sustained stock price” means the average fair market value of a share of our common stock during any six-month period commencing on or after the first day of the Performance Period and ending on or before the last day of the Performance Period. “Net present value of future cash flows” means the net present value of estimated future cash flows from executed agreements (such as a contract to supply natural gas), proven reserves or any other source of future cash flows with analogous certainty to the aforementioned sources as estimated by an independent auditor designated by our Board of Directors. For this purpose, an annual discount rate of 10 percent is used to calculate net present value.

In July 2005, we entered into a stock option award agreements with certain of our officers under our 2005 Stock Incentive Plan similar to those described above. The agreements granted the officers options to purchase up to 600,000 shares of our common stock at an exercise prices of $10.14 per share. The term of each option is ten years from the date of grant. Depending on the sustained stock prices of our common stock and the net present value of future cash flows, a percentage of options will vest as according to the Performance Period.

The term of each option is ten years from the date of grant. We follow APBO No. 25, which requires us to treat the plan as a variable plan for accounting purposes and causes the recognition of compensation expense or income related to changes in the intrinsic value in the options. As intrinsic value existed for both option award agreements on September 30, 2005 compensation expense of $253,000 was recognized for the June stock option award agreement and $55,000 was recognized for the July stock option award agreement for the period ended September 30, 2005.

During 2005, we granted an aggregate of 250,000 restricted common stock units to certain employees under the 2005 Stock Incentive Plan in compensation expense. These restricted common stock units vest over various periods through 2010. We expect to recognize $238,000 for the year ending December 31, 2005. Throughout the remainder of the vesting period we expect to recognize $2,297,000 in compensation expense relating to the vesting of these restricted common stock units. We recorded deferred compensation for these units totaling $2,535,000 at the time of grant based on the market prices of our common stock on that date.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and use assumptions that affect reported amounts. For a discussion of our critical accounting policies and estimates, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2004.

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123R,Share-Based Payment(“SFAS No. 123R”). This standard is a revision of SFAS No. 123 and supersedes APBO 25 and its related implementation guidance. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values and is effective for the first annual reporting period beginning after June 15, 2005. We expect to adopt SFAS No. 123R on January 1, 2006, using the standard’s modified prospective application method. Adoption of SFAS No. 123R will not affect our cash flows or financial position, but it will reduce reported income and earnings per share because we will be required to recognize compensation expense for stock options granted under the our stock-based compensation plans, whereas the we have not been required to record such expense under current accounting rules. Under SFAS No. 123R, we will recognize compensation expense for stock-based compensation over the requisite service period, which is generally three years following the grant date. If we had expensed employee stock options under SFAS No. 123 for the nine months ended September 30, 2005, net income and diluted earnings per share would have been reduced by the amounts disclosed above in Note 7 to our consolidated financial statements. Because stock options are determined each year,

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the impact to our financial statements of the adoption of SFAS No. 123R cannot be predicted with certainty. However, the weighted average fair value of stock option awards disclosed in the footnotes to the financial statements, but not included in compensation expense, over the last three fiscal years ranged from $1.41 to $3.12 per share. Under SFAS No. 123R, the fair value would be amortized into compensation expense over the vesting period of the stock options.

In March 2005, the Financial Standards Board issued FASB Interpretation No.47,Accounting for Conditional Asset Retirement Obligations (“FIN 47”) an interpretation of SFAS No. 143,Accounting for Asset Retirement Obligation. FIN 47 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. The interpretation is effective for fiscal years ending on or after December 15, 2005. We expect to adopt FIN 47 on December 31, 2005. We will be required to recognize a liability for all conditional asset retirement obligations at that time, if any. We do not expect the impact to the Company’s financial statements of the adoption of FIN 47 to be material at this time.

In May 2005, the Financial Standards Board issued SFAS No. 154,Accounting Changes and Error Corrections(“SFAS No. 154”), a replacement of APB Opinion No. 20,Accounting Changes, and FASB Statement No. 3Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We have elected to adopt SFAS No. 154 as of September 30, 2005. At the time of adoption, there was no impact to our financial statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

We had approximately $82,024,000 in cash and cash equivalents in the form of money market instruments at September 30, 2005. This compares to approximately $31,573,000 in cash and cash equivalents at December 31, 2004. Our cash and cash equivalents balances are subject to fluctuations in interest rates and we are restricted in our options for investment by our short-term cash flow requirements. Our cash and cash equivalents are held in a few financial institutions; however, we believe that our counter-party risks are minimal based on the reputation and history of the institutions selected.

Pursuant to our joint venture agreement with YFP, we also hold restricted funds that secure a letter of credit which we provided to YFP in the amount of $10,000,000. We also entered into a Participation Agreement with several partners to fully develop the OML 113 block, pursuant to which the Participants have contributed 90 percent of the principal deposited, and costs associated with the letter of credit. YFP has the right to draw the full amount from the letter of credit as liquidated damages if the initial well is not drilled by February 2006. We have recorded our 10 percent interest in the total letter of credit as restricted cash on the balance sheet as of September 30, 2005. The letter of credit is held in U.S. dollars in a U.S. financial institution. We believe that our counter-party risks are minimal based on the reputation and history of the institution selected. Subsequent to September 30, 2005, the requirements for the letter of credit were fulfilled and the letter of credit was released.

We expect to conduct a portion of our business in currencies other than the U.S. dollar. We may attempt to minimize our currency exchange risk by seeking international contracts payable in local currency or we may choose to convert our currency position into U.S. dollars. In the future, we may also have significant investments in countries other than the United States. The functional currency of these foreign operations may be the local currency; accordingly, financial statement assets and liabilities may be translated at prevailing exchange rates and may result in gains or losses in current income. Currently, all of our subsidiaries use the U.S. dollar for their functional currency. Monetary assets and liabilities are translated into U.S. dollars at the rate of exchange in effect at the balance sheet date. Transaction gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the U.S. dollar are included in the results of operations as incurred.

Foreign exchange risk currently relates to deferred revenue, a portion of which is denominated in Australian dollars. The portion of deferred revenue denominated in Australian currency was AUD $15,000,000 at September 30, 2005. The deferred revenue is converted to U.S. dollars for financial reporting purposes at the end of every reporting period. To the extent that conversion results in gains or losses, such gains or losses will be reflected in our statements of operations. The exchange rate of the U.S. dollar to the Australian dollar was $0.76 at both September 30, 2005 and September 30, 2004.

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We do not have any purchased futures contracts or any derivative financial instruments, other than warrants issued to purchase common stock at a fixed price in connection with consulting agreements, private placements and other equity offerings.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures.In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2005 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Changes in Internal Controls.There have been no changes in our internal controls over financial reporting that occurred during the three months ended September 30, 2005 that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

We and our subsidiaries are involved in lawsuits that have arisen in the ordinary course of our business. We do not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on our business or consolidated financial position.

We cannot predict with certainty the outcome or effect of the litigation matter specifically described above or of any such other pending litigation. There can be no assurance that our belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered Sales of Equity Securities.

On October 14, 2005, we issued 17,271 shares of our common stock to Mr. Ziad Ghandour under the amended consulting agreement with TI Capital Management, in connection with the inclusion of an additional participant into the Stranded Gas Venture Participation Agreement. This transaction was exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof as a transaction not involving any public offering

Equity Repurchases

The following table provides purchases of our common stock by us or on behalf of our affiliated purchasers during the quarter ended September 30, 2005. The table reflects our repurchase of 393 shares of our common stock as settlement for payroll taxes of employees who were granted shares of stock as incentive compensation during the three months ended September 30, 2005.

Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2005 – July 31, 2005	—		—	—	—
August 1, 2005 – August 31, 2005	—		—	—	—
September 1, 2005 – September 30, 2005	393	$	14.49	—	—
Total	393	$	14.49	—	—

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Item 3. Defaults Upon Senior Securities.

Not applicable.

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

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

10.1	Memorandum of Agreement dated as of August 15, 2005 between Syntroleum Corporation and Linc Energy, Ltd. (portions of this document have been omitted pursuant to a request for confidential treatment and filed with the SEC).
10.2	Joinder Agreement dated as of September 19, 2005 between Syntroleum International Corporation and Selim K. Zilkha Trust
31.1	Section 302 Certification of John B. Holmes, Jr.
31.2	Section 302 Certification of Greg G. Jenkins.
32.1	Section 906 Certification of John B. Holmes, Jr.
32.2	Section 906 Certification of Greg G. Jenkins.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SYNTROLEUM CORPORATION, a Delaware
	corporation (Registrant)
Date: November 9, 2005	By:	/s/    JOHN B. HOLMES, JR.
		John B. Holmes, Jr.
		Chief Executive Officer and President
Date: November 9, 2005	By:	/s/    GREG G. JENKINS
		Greg G. Jenkins
		Executive Vice President of Finance and Business
		Development and Chief Financial Officer (Principal Financial Officer)

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INDEX TO EXHIBITS

No.	Description of Exhibit
10.1	Memorandum of Agreement dated as of August 15, 2005 between Syntroleum Corporation and Linc Energy, Ltd. (portions of this document have been omitted pursuant to a request for confidential treatment and filed with the SEC).
10.2	Joinder Agreement dated as of September 19, 2005 between Syntroleum International Corporation and Selim K. Zilkha Trust
31.1	Section 302 Certification of John B. Holmes, Jr.
31.2	Section 302 Certification of Greg G. Jenkins.
32.1	Section 906 Certification of John B. Holmes, Jr.
32.2	Section 906 Certification of Greg G. Jenkins.

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