Sooner 10Q 2006 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, 2006.

o	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

(State or other jurisdiction of

incorporation or organization)

73-1565725

(I.R.S. Employer

Identification No.)

4322 South 49^th West 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer___

Accelerated filer X

Non-accelerated filer___

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, 2006, the number of outstanding shares of the issuer’s common stock was 55,972,262.

SYNTROLEUM CORPORATION

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006

PART I – FINANCIAL INFORMATION

Page

Item 1. Financial Statements.

Unaudited Consolidated Balance Sheets as of September 30, 2006 and
		December 31, 2005			1
Unaudited Consolidated Statements of Operations for the three and nine-month
	periods ended September 30, 2006 and 2005			2
Unaudited Consolidated Statement of Stockholders’ Equity for the nine-month
			period ended September 30, 2006		3
Unaudited Consolidated Statements of Cash Flows for the nine-month
		periods ended September 30, 2006 and 2005			4
Notes to Unaudited Consolidated Financial Statements				5

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

	and Results of Operations	16
Item 3. Quantitative and Qualitative Disclosures About Market Risk		31
Item 4. Controls and Procedures		32

PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	36
Item 4.	Submission of Matters to a Vote of Security Holders	36
Item 5.	Other Information	36
Item 6.	Exhibits	36
SIGNATURES		37

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), and the economic production of oil and gas reserves, application of these technologies to other feedstocks, 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, 2005.

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

Our GTL technology can be used for converting natural gas or synthesis gas from coal, into synthetic liquid hydrocarbons. Generally, any reference to GTL is also applicable to CTL unless the context indicates otherwise.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

SYNTROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

(in thousands, except per share data)

	September 30,	December 31,
	2006	2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$ 38,251		$ 69,663
Restricted cash	2,595		1,684
Accounts receivable	2,489		1,224
Current maturities of note receivable	-		1,802
Other current assets	292		3,085
Total current assets	43,627		77,458

OIL AND GAS PROPERTY AND EQUIPMENT HELD FOR SALE	1,000		1,927
OIL AND GAS PROPERTIES - at cost, net, using full cost method, including $3,680 and $4,514 at September 30, 2006 and December 31, 2005, excluded from amortization, respectively	3,680		4,514
OTHER PROPERTY AND EQUIPMENT – at cost, net	2,665		2,959
OTHER ASSETS, net	2,682		2,937
	$ 53,654		$ 89,795

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$ 1,862		$ 2,632
Accrued liabilities and other	1,493		2,806
Current maturities of convertible debt	27,281		25,925
Total current liabilities	30,636		31,363

OTHER NONCURRENT LIABILITIES	46		114
STRANDED GAS VENTURE	5,304		4,247
DEFERRED REVENUE	21,202		20,952
COMMITMENTS AND CONTINGENCIES
MINORITY INTERESTS	706		706

STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock, $0.01 par value, 5,000 shares authorized, no shares issued	-		-
Common stock, $0.01 par value, 150,000 shares authorized, 55,941 and
55,568 shares issued and outstanding at September 30, 2006 and
December 31, 2005, respectively	559		556
Additional paid-in capital	319,732		317,350
Deferred compensation	-		(2,589)
Accumulated deficit	(324,531)		(282,904)
Total stockholders' equity (deficit)	(4,240)		32,413
	$ 53,654		$ 89,795

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

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,
	2006	2005	2006	2005
REVENUES:
Joint development revenues	$ 390	$ 616	$ 1,020	$ 7,044
Other revenues	2,470	92	2,580	98
Total revenues	2,860	708	3,600	7,142

COSTS AND EXPENSES:
Catoosa Demonstration Facility	1,988	2,456	7,642	7,039
Pilot plant, engineering and research and development	3,409	2,980	10,057	7,586
Depreciation, depletion, amortization and impairment	2,817	3,574	5,252	3,943
General, administrative and other (including non-cash equity compensation of $1,748 and $551 for the three months ended September 30, 2006 and 2005, respectively, and $5,202 and $3,788 for the nine months ended September 30, 2006 and 2005, respectively.)	7,455	4,876	21,105	17,023

OPERATING INCOME (LOSS)	(12,809)	(13,178)	(40,456)	(28,449)

INVESTMENT AND INTEREST INCOME	597	785	2,040	1,731
INTEREST EXPENSE	(580)	(430)	(1,561)	(1,275)
OTHER INCOME (EXPENSE), net	(40)	2	(1,247)	3,730
FOREIGN CURRENCY EXCHANGE	(252)	23	(253)	293

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(13,084)	(12,798)	(41,477)	(23,970)

INCOME TAXES	-	-	-	-

INCOME (LOSS) FROM CONTINUING OPERATIONS	(13,084)	(12,798)	(41,477)	(23,970)

INCOME (LOSS) FROM DISCONTINUED DOMESTIC OIL AND GAS BUSINESS	63	(2,616)	(150)	(3,642)

NET INCOME (LOSS)	$ (13,021)	$ (15,414)	$ (41,627)	$ (27,612)

BASIC AND DILUTED NET INCOME (LOSS) PER SHARE:
Income (loss) from continuing operations	$ (0.23)	$ (0.23)	$ (0.74)	$ (0.45)
Loss from discontinued domestic oil and gas business	-	(0.05)	-	(0.07)
Net income (loss)	$ (0.23)	$ (0.28)	$ (0.74)	$ (0.52)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic and Diluted	55,870	55,443	55,803	52,888

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

SYNTROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)

(in thousands)



	Common Stock
	Number of Shares	Amount	Additional Paid-In Capital	Deferred Compensation	Accumulated Deficit	Total Stockholders’ Equity (Deficit)

Balance, December 31, 2005	55,568	$ 556	$ 317,350	$ (2,589)	$ (282,904)	$ 32,413
Adoption of Statement of Financial Accounting Standards No. 123(R)	-	-	(2,589)	2,589	-	-
Stock options exercised	141	1	339	-	-	340
Stock warrants exercised	2	-	12	-	-	12
Vesting of awards granted	146	1	4,290	-	-	4,291
Issuance of equity-based compensation for bonuses	161	2	1,017	-	-	1,019
Purchase and retirement of treasury shares	(77)	(1)	(687)	-	-	(688)
Net income (loss)	-	-	-	-	(41,627)	(41,627)
Balance, September 30, 2006	55,941	$ 559	$ 319,732	$ -	$ (324,531)	$ (4,240)

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

SYNTROLEUM CORPORATION AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	For the Nine Months Ended September 30,
	2006	2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (41,627)	$ (27,612)
Loss from discontinued domestic oil and gas business	150	3,642
Loss from continuing operations	(41,477)	(23,970)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, amortization and impairment	5,252	3,943
Foreign currency exchange	251	(298)
Non-cash compensation expense	5,202	3,788
Non-cash interest expense	1,561	1,275
Gain on sale of assets and interest in projects	(33)	(3,558)
Changes in assets and liabilities:
Accounts and notes receivable	(959)	120
Other assets	2,758	319
Accounts payable	(768)	1,821
Accrued liabilities and other	(1,381)	(1,186)
Deferred revenue	-	(5,873)
Net cash used in continuing operations	(29,594)	(23,619)
Net cash provided by discontinued operations	67	(101)
Net cash used in operating activities	(29,527)	(23,720)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment	(206)	(865)
Oil and gas expenditures	(7,649)	(10,187)
Proceeds from disposal of assets and conveyance of interests	5,461	9,440
Proceeds from note receivable	1,802	5
Increase in restricted cash	(911)	(3,567)
Net cash used in continuing operations	(1,503)	(5,174)
Net cash used in discontinued operations	(550)	(4,217)
Net cash used in investing activities	(2,053)	(9,391)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock, warrants and option exercises	352	81,487
Stranded gas venture costs	-	(500)
Proceeds from stranded gas venture	506	3,178
Purchase and retirement of treasury stock	(688)	(599)
Net cash provided by financing activities	170	83,566

FOREIGN EXCHANGE EFFECT ON CASH	(2)	(4)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(31,412)	50,451
CASH AND CASH EQUIVALENTS, beginning of period	69,663	31,573
CASH AND CASH EQUIVALENTS, end of period	$ 38,251	$ 82,024

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

SYNTROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2006

1.	Basis of Reporting

The primary operations of Syntroleum Corporation and its 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 (subject to certification), kerosene and naphtha, and 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”) and is reviewing the application of these technologies for the conversion of other feedstocks.

The Company's focus has been the commercialization of the Syntroleum Process and the Synfining Process through participation in projects that would utilize the Company’s technologies in the production of hydrocarbons. 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. Syntroleum’s particular interests include projects in which the Company would be involved in the upstream field development of the feedstock for these plants.

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 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 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 (“Tulsa Pilot Plant”) and various laboratory facilities in Tulsa, Oklahoma, which are used in demonstrating process performance and conducting various studies. In September 2006, the Company completed the production of our contract committed volume of fuels to the United States Department of Defense. In addition, we also successfully completed the longest run of our catalyst testing activity at the Tulsa pilot plant. In line with the program completion of our demonstration plants, the Company has placed both plants in standby mode.

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, 2005 filed with the SEC under the Securities Exchange Act of 1934. Results of operations for the three month and nine month periods ending September 30, 2006 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2006.

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.

Operations and Liquidity

The Company has sustained recurring losses and negative cash flows from operations. Over the periods presented in the accompanying financial statements, the Company’s operations have been funded through a combination of equity and convertible debt financings, and the sale of certain assets. As of September 30, 2006, the Company had approximately $38,251,000 of cash and cash equivalents available to fund operations. The Company reviews cash flow forecasts and budgets periodically. Management believes that the Company currently has sufficient cash and financing capabilities to meet its funding requirements over the next year. However, the Company has experienced, and continues to experience, negative operating margins and negative cash flows from operations, as well as an ongoing requirement for substantial additional capital investment related to construction of GTL or CTL plants and other activities, including exploration and production of energy assets and research and development programs in which the Company participates.

The Company expects that it will need to raise substantial additional capital to accomplish its business plan over the next several years. The Company expects to seek to obtain additional funding through debt or equity financing in the capital markets as well as various other financing arrangements. 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, depository shares or warrants for a remaining aggregate offering price of approximately $102,000,000 as of September 30, 2006. 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. There can be no assurance as to the availability or terms upon which such financing and capital might be available.

The Company is currently exploring alternatives for raising capital to fund the growth of its GTL business, its CTL business and its acquisition of oil and gas properties, including the formation of joint ventures and other strategic alliances. If adequate funds are not available, or if the Company is not successful in establishing a strategic alliance, the Company may be required to reduce, delay or eliminate expenditures for its GTL and CTL plant development and other activities, as well as its research and development and other activities, or may 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. The transactions outlined above may not be available to the Company when needed or on terms acceptable or favorable to the Company.

3.	Oil and Gas Properties

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. These costs plus future development costs of undeveloped properties are 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. All of the costs that were unevaluated for the quarter ended September 30, 2006 related to either leasehold, geological and geophysical or acquisition-type costs. The Company will evaluate these costs at least quarterly, or when circumstances warrant, determining if any of the costs should be included in the amortization computation. In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 106, the Company excludes the future cash outflows associated with asset retirement obligations accrued on the balance sheets, if any, from the present value of future net revenues used in the ceiling limitation calculation. For purpose of computing depreciation, depletion and amortization, the Company includes the estimated future expenditures for dismantlement and abandonment costs, net of salvage values, of proved undeveloped properties, if any, in the costs to be amortized. 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 investment in oil and gas activities consisted of the following, excluding activities in the United States, which are included in discontinued operations (in thousands):

	September 30, 2006
	Nigeria	Other		Total
Evaluated properties	$ 7,350	$ 1,662		$ 9,012
Unevaluated properties	3,601	-		3,601
Gross oil and gas properties	10,951	1,662		12,613
Accumulated depreciation, depletion, amortization, and Impairment	(7,350)	(1,662)		(9,012)
Net oil and gas properties	$ 3,601	$ -		$3,601




	December 31, 2005
	Nigeria	Other	Total
Evaluated properties	$ 4,365	$ 10	$ 4,375
Unevaluated properties	3,505	1,009	4,514
Gross oil and gas properties	7,870	1,019	8,889
Accumulated depreciation, depletion, amortization, and Impairment	(4,365)	(10)	(4,375)
Net oil and gas properties	$ 3,505	$ 1,009	$ 4,514

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 (“Aje-3”) well in Oil Mining Lease (“OML”) 113 offshore Nigeria. All of the capitalized costs for Nigerian oil and gas activities have been for exploration purposes. The Company’s total drilling, logging, and dry hole evaluated costs of Aje-3 was $3,331,000. The Company recognized depletion, depreciation, amortization and impairment expense for the costs of drilling and testing this well in 2005. No production from these properties has occurred as of September 30, 2006.

The Company has participated in other activities in Nigeria, including geological and geophysical work within other areas of OML 113 and other areas of Nigeria. The Company has acquired a 40% participating interest in the Ajapa Marginal Field (the “Ajapa Field”) in OML 90 offshore Nigeria. In the quarter ended September 30 2006, the Company entered into a Participation Deed with Energy Equity Resources Oil and Gas Limited (“EER”), pursuant to which EER will acquire 50 percent of the Company’s participating interest. All capitalized costs related to this field have been for exploration purposes and considered unevaluated as of September 30, 2006. Management has reviewed its portfolio of projects and determined that no further development will occur on some of these properties. The amount of capitalized costs for the projects that are not expected to proceed totaled $1,623,000 for the quarter ended September 30, 2006 and they are considered to be evaluated. The Company has charged $2,985,000 for geological and geophysical work related to these projects to depletion, depreciation, amortization and impairment expense for the nine months ended September 30, 2006. The amount of capitalized cost considered to be unevaluated as of September 30, 2006 totaled $3,680,000.

Other. The Company has participated in other international oil and gas activities. These activities have primarily included geological and geophysical reviews on fields in various areas, including Indonesia, India, Kazakhstan and others. We have charged $1,653,000 to depletion, depreciation, amortization and impairment expense for the nine months ended September 30, 2006.

4.	Discontinued Operations and Assets Held for Sale

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. The Company also acquired gas processing equipment, including a gas processing plant that was intended to be used in the Central Kansas Uplift. In October 2005, management completed an evaluation of the potential reserves and the economics related to these properties and decided to focus its efforts on aligning the Company with specific goals and projects that have GTL and CTL potential. As a result, management decided to discontinue further expenditures in the Central Kansas Uplift area and began disposing of these properties. The net effect of the United States oil and gas activities, including the related gas processing plant and equipment, is presented as discontinued operations in the financial statements for the three months and nine months ended September 30, 2006 and 2005 in

accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

Oil and Gas Properties. Certain leasehold acres in the area were sold in November 2005 for $1,000,000. The proceeds from this sale were accounted for as a reduction in the full cost pool. The remaining leasehold acreage, including the wells and well equipment, was sold for $522,000 in January 2006. The assets related to the domestic oil and gas operations have been accounted for as assets held for sale in the consolidated balance sheets. The Company no longer has any oil and gas properties in the United States.

Gas Processing Equipment. The Company follows provisions of SFAS No. 144. 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. The Company recorded an impairment of approximately $205,000 related to its gas processing plant and equipment during the nine months ended September 30, 2006 which is reflected in loss from discontinued domestic oil and gas operations. The write down included costs associated with engineering, design, the gas processing plant and other gas processing equipment. The Company recognized a gain on disposal of a portion of the gas processing equipment in the quarter of $67,000. The processing plant and remaining equipment is considered held for sale as of September 30, 2006 at an estimated fair value of $1,000,000. Management is actively seeking interested parties for the sale of this plant and related equipment. Management is focused on completing the sale of these assets in 2006.

5.	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. Since 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.

6.	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 11,729,812 and 11,360,962 shares of common stock exercisable at a weighted average exercise price of $7.00 and $6.88 for the nine months ended September 30, 2006 and 2005, 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 256,000 and 409,654 were also not included in the computation of diluted earnings (loss) per share for the nine months ended September 30, 2006 and 2005, respectively, as they are anti-dilutive.

The number of shares that could be issued as a result of the convertible debt outstanding at September 30, 2006 and September 30, 2005 totals 4,546,866 and 4,249,211 shares of common stock, respectively, based on the minimum conversion rate of $6.00 per common share. These shares are excluded also from the computation of diluted earnings (loss) per share, as they are anti-dilutive for the periods ended September 30, 2006 and 2005.

7.	Stock-Based Compensation

Effective January 1, 2006, the company adopted the provisions of SFAS No. 123 (R) Share-Based Payment (“SFAS No. 123 (R)”), which establishes accounting for equity instruments exchanged for employee services. Under the provisions of SFAS No. 123(R), share-based compensation cost is measured at grant date, based on the fair value of the award, and is recognized as an expense over the employee’s requisite service period, which is generally the vesting period of the equity grant. Prior to January 1, 2006, the Company accounted for share-based compensation to employees in accordance with the Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The Company also followed the disclosure requirements of the SFAS No. 123, Accounting for Stock-Based Compensation.

The Company adopted the modified prospective transition method as provided by SFAS No. 123(R). Accordingly, financial statement amounts for the prior periods have not been restated to reflect the fair value method of expensing share-based compensation. In accordance with the modified prospective transition method, all outstanding deferred compensation at the time of adoption was reclassified to additional paid-in capital. For the three months and nine months ended September 30, 2006, the Company recorded a total of $1,748,000 and

$5,202,000 or $(0.03) per share and $(0.09) per share of share-based compensation expense, respectively. At January 1, 2006, the Company had no cumulative effect associated with adopting SFAS No. 123(R).

The Company’s share-based incentive plans permit the Company to grant restricted stock units, restricted stock, incentive or non-qualified stock options, and certain other instruments to employees, directors, consultants and advisors of the Company. Restricted stock units generally vest over three years. The exercise price of options granted under the plan must be at least equal to the fair market value of the Company’s common stock on the date of grant. All options granted vest at a rate determined by the Nominating and Compensation Committee of the Company’s Board of Directors and are exercisable for varying periods, not to exceed ten years. Shares issued under the plans upon option exercise or stock unit conversion are generally issued from authorized but previously unissued shares. As of September 30, 2006, approximately 2,505,000 shares of common stock were available for grant under the Company’s current plan. The Company is authorized to issue up to approximately 10,709,000 shares of common stock in relation to stock options or grants outstanding or available for grant under the plans. The number and weighted average exercise price of stock options outstanding are as follows:

	Shares	Weighted
	Under	Average Price
	Stock Options	Per Share
OUTSTANDING AT DECEMBER 31, 2005	7,774,414	$7.40
Granted at market price	658,500	$8.22
Exercised	(141,349)	$2.41
Expired or forfeited	(86,993)	$7.63
OUTSTANDING AT SEPTEMBER 30, 2006	8,204,572	$7.55

The following table summarizes information about stock options outstanding at September 30, 2006:

Options Outstanding						Options Exercisable
Range of Exercise Price			Options Outstanding	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life		Options Exercisable	Weighted Average Exercise Price Per Share
$1.49	-	$1.62	1,424,912	$1.55	4.99		1,424,912	$1.55
$1.70	-	$6.21	1,368,978	$3.59	6.15		1,258,148	$3.45
$6.36	-	$7.70	1,368,415	$6.95	7.25		928,089	$6.88
$7.94	-	$10.51	1,326,700	$9.72	7.87		290,536	$9.32
$10.52	-	$10.52	2,000,000	$10.52	8.73		-	-
$10.70	-	$19.88	715,567	$15.84	3.57		704,902	$15.91
			8,204,572	$7.55			4,606,587	$5.83

A total of 3,597,985 stock options with a weighted average exercise price of $9.74 were outstanding at September 30, 2006 which had not vested.

The fair value of options granted during the quarter ended September 30, 2006 was estimated on the grant date using the Black-Scholes option pricing model. The model utilizes certain information, such as the interest rate on a risk-free security maturing generally at the same time as the option being valued, and requires certain assumptions, such as the expected amount of time an option will be outstanding until it is exercised or it expires and the volatility associated with the price of the underlying shares of common stock, to calculate the fair value of stock options granted. Expected volatilities are based on historical stock prices and historical volatilities. The Company uses historical data to estimate option exercise and employee termination within the valuation model; separate groups of employees that have similar historical exercise behavior are considered separately for valuation purposes. A forfeiture rate of five percent has been estimated to reduce the expense for awards expected to not be exercised because of termination or expiration. The Company believes that this valuation technique and the approach utilized to develop the underlying assumptions are appropriate in calculating the fair values of the Company’s stock options granted in the quarter and nine months ended September 30, 2006. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by persons who receive equity awards.

The total grant date fair value of stock options that were granted during the three and nine months ended September 30, 2006 was $143,000 and $3,865,000, respectively at a weighted average grant date fair value of $2.87 and $5.87 per stock option. The fair value of these options was estimated with the following weighted average assumptions:

	Three Months Ended	Nine Months Ended
	September 30, 2006	September 30, 2006
Expected dividend yield	0%	0%
Expected volatility	76%	82%
Risk-free interest rate	4.88%	4.69%
Expected life	4.50 yrs.	5.68 yrs.

During the nine months ended September 30, 2006, the total intrinsic value of options exercised (i.e., the difference between the market price on the exercise date and the price paid by the employee to exercise the options) was $668,000 and the total amount of cash received by the Company from the exercise of these options was $340,000. As of September 30, 2006, there was no aggregrate intrinisic value of stock options that are fully vested or are expected to vest. The remaining weighted average contractual term is approximately seven years. In addition, as of September 30, 2006, unrecognized compensation cost related to non-vested stock options was $14,122,000 which will be fully amortized using the straight line basis over the vesting period of the options, which is generally three to five years.

The Company also grants common stock and restricted common stock units to employees. These awards are recorded at their fair value on the date of grant and compensation cost is recorded over the vesting period. The total grant date fair value of 256,000 common stock and restricted common stock units outstanding as of September 30, 2006 was $2,620,980. The total grant date fair value of 185,696 common stock and restricted stock units granted during the nine months ended September 30, 2006 was approximately $1,708,000 with a weighted average grant date fair value of $9.20 per share. The total fair value of 277,084 shares vested or exercised during the nine months ended September 30, 2006 was $2,441,000. As of September 30, 2006, the aggregrate intrinsic value of restricted stock units that are expected to vest was approximately $1,226,000. In addition, as of September 30, 2006, unrecognized compensation cost related to non-vested restricted stock units was $1,832,000, which is expected to be recognized over a weighted average period of three years. The number of restricted common stock units and common stock grants outstanding and changes in these common stock units are as follows:

	Shares / Units
OUTSTANDING AT DECEMBER 31, 2005	409,654
Granted	185,696
Vested or Exercised	(277,084)
Expired or forfeited	(62,266)
OUTSTANDING AT SEPTEMBER 30, 2006	256,000

Prior to adoption of SFAS No. 123 (R), the Company did not recognize compensation expense for employee stock option grants, when the exercise price of the Company’s employee stock options equaled the market price of the underlying stock on the date of grant. For the three and nine months ended September 30, 2005, the Company used the Black-Scholes option-pricing model to determine the pro forma impact under SFAS No. 123 on the Company’s net income and earnings per share.

The following table illustrates the effect on net income and earnings per share if the company had applied the fair value recognition provisions of SFAS No. 123 to its stock option plan prior to January 1, 2006 (in thousands, except per share data):

	Three Months Ended September 30,	Nine Months Ended September 30,
	2005	2005

Net income (loss), as reported	$ (15,414)	$ (27,612)
Total Variable Stock Based Employee compensation expense included in net income (loss) as reported and determined under the Intrinsic Value Method for awards granted, modified or settled, net of any related tax affects, 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)	(2,369)
Pro forma net income (loss)	$ (16,307)	$ (29,673)
Earnings (loss) per share:
Basic and diluted- as reported	$ (0.28)	$ (0.52)
Basic and diluted- pro forma	$ (0.29)	$ (0.56)

The weighted average assumptions used for the stock options granted during the quarter ended September 30, 2005 are summarized as follows:

	September 30, 2005
Expected dividend yield	0%
Expected volatility	52%
Risk-free interest rate	3.84%
Expected life	5.0 yrs.

8. Defined Contribution Plan -401(k)

The Company sponsors a defined contribution plan, named the Syntroleum 401(k) Plan (the “401(k) Plan”), covering virtually all employees of Syntroleum Corporation and its wholly-owned subsidiaries who have met the eligibility requirements. Employees of the Company may participate in the 401(k) Plan upon employment with the Company. Participants become eligible for Company matching and profit sharing contributions upon employment on the last day of the 401(k) Plan quarter.

Effective July 1, 2006, the Plan adopted an amendment to allow Company contributions in the form of shares of common stock of the Company (“Syntroleum Stock”). The Plan will include investments in shares of Syntroleum Stock to the extent that such shares are contributed by the Company as a matching or profit sharing contribution. No purchases of Syntroleum Stock will be permitted.

The Company contributes a matching contribution equal to 50 percent of employees’ contributions quarterly. The Company issued 30,299 shares of Syntroleum Stock for the matching contribution for the first and second quarters of 2006. The Company accrued for the issuance of 16,331 shares of Syntroleum stock for the quarter ended September 30, 2006. The shares were issued in October. The expense for this matching contribution totaled $69,000 and $210,000, respectively, and has been recorded in the statement of operations for the three and nine months ended, September 30, 2006. The Company did not elect to contribute to the 401(k) Plan for the nine months ended September 30, 2005.

9. Note Receivable

In February 2000, the Company sold its parking garage in Reno, Nevada to Fitzgerald’s Reno, Inc. ("FRI"), a Nevada corporation doing business as Fitzgerald’s Hotel & Casino Reno, for $3,000,000. FRI paid $750,000 in cash and executed a promissory note in the original principal amount of $2,250,000 and interest rate of 10 percent per year (based on a twenty-year amortization). The note was payable in monthly installments of principal and interest, with the entire unpaid balance due on February 1, 2010. The note was secured by a deed of trust, assignment of rents and security interest in favor of the Company on the parking garage. FRI also executed an Assumption and Assignment of Ground Lease dated February 1, 2000, under which FRI agreed to make the lease payments due under the ground lease. FRI’s obligations under the Assumption and Assignment of Ground Lease are secured by the deed

of trust, assignment of rents and security interest in the parking garage and the ground lease.

FRI, along with several affiliates, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court, District of Nevada. On August 28, 2003, the bankruptcy plan filed by FRI went into effect and FRI agreed to pay the Company $50,000 to be applied towards the outstanding principal balance of the promissory note. FRI then issued a new note under the same terms and conditions as the original promissory note, except that the maturity date was accelerated to August 28, 2006.

In March 2006, FRI and the Company entered into a debt settlement agreement of the promissory note. FRI then paid to the Company $1,848,000, which represented the outstanding principal amount together with all accrued but unpaid interest due on the note. The Company has agreed to discount the total amount due on the note by $159,000 in return for release of the ground lease with the city of Reno (See Note 11). In accordance with the debt settlement agreement amendment, FRI has ninety days from July 19, 2006 to effectively release the Company from the ground lease in order to receive a discount on the full payment of the note. As of September 30, 2006, the Company had not been released from the ground lease and has provided FRI a 30 day extension to resolve the outstanding issues. The Company has recorded the escrow account as restricted cash in the accompanying balance sheet.

10.

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 million in project costs and to provide up to $3 million in Marathon personnel contributions. Marathon is entitled to credit these contributions against future license fees in specified circumstances. As of September 30, 2006, the Company had received reimbursement of $5 million of project costs ($1 million of which is included in deferred revenue as a fuel delivery commitment) and $3 million in personnel contributions.

Marathon also agreed to provide project funding pursuant to advances under a $21.3 million secured promissory note with the Company. The promissory note bears interest at a rate of eight percent per year and the maturity date was extended in May 2006 to December 15, 2006. The Company is currently reviewing various options with regards to this note. The current balance of $27.3 million, which includes accrued interest, has been included in current liabilities in the accompanying consolidated balance sheet as of September 30, 2006. 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 note. The only other form of repayment to Marathon is its right to convert the promissory note 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. Under certain circumstances, the Company may also elect to repay the note in cash. The promissory note is secured by a mortgage on the assets of the project that would allow Marathon to complete the project in the event of a default by the Company. Events of default under the promissory note include failure by the Company to comply with the terms of the promissory note, 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 million, excluding amounts due under the promissory note and liabilities associated with prepaid license fees. The Company was in compliance with the provisions of the note as of September 30, 2006.

11.

Commitments and 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 Syntroleum. 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.

The Hawaii obligations arise out of certain land leases and subleases that were entered into by Business Men’s Assurance Company of America (“BMAA”) 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 through 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, times 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 $4,524,000 per year. This projection was based on assessed property values and certain clauses in the lease agreement. 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, are $269,151,000. 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 property tax records indicate a fair market value for the hotel and the land of $244,143,000. The Hyatt Hotel had gross revenues of $92,800,000 subject to the lease agreement for the year ended May 31, 2006.

In December 2005, management learned that the owner of the Hyatt Hotel, Azabu Buildings Co., Ltd. (“Azabu”) has been petitioned for an involuntary Chapter 11 bankruptcy by Beecher Limited and others, creditors of Azabu in various business ventures. Subsequent to December 31, 2005, Azabu filed for Chapter 11 bankruptcy. Management believes that based on the performance of this asset, that the bankruptcy court would more than likely require Azabu to continue to make all required rent payments in order for the hotel to continue operations. Based on the appraised value of the Hyatt Hotel and management’s evaluation of this contingency, 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 sheet at September 30, 2006 or December 31, 2005.

Scout is also subject to lease obligations under a land lease for a Reno, Nevada parking garage. This property was sold in 2000 (See Note 9); however, Scout was not released from the land lease by the landowner. This lease requires total remaining lease payments of $5,535,741 and will expire in August 2023. The property is currently owned by FRI, which continues to make the monthly ground lease payments. In accordance with the debt settlement agreement amendment, FRI has ninety days from July 19, 2006 to effectively release the Company from the ground lease in order to receive a discount on the full payment of the note. 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, 2006 or December 31, 2005.

Syntroleum Nigeria Limited, a wholly owned subsidiary of Syntroleum Corporation, entered into a Heads of Agreement with Brittania-U Nigeria Limited (“Brittania-U”) in November 2005, to acquire a 40 percent participating interest in the Ajapa Marginal Field (the “Ajapa Field”) in OML 90 offshore Nigeria. On February 26, 2006, the Company entered into a Participation Agreement and Joint Operating Agreement with Britannia-U regarding the Ajapa Field. The Company received approval from the Nigerian government on June 12, 2006 with regards to the Participation Agreement. On September 13, 2006, the Company received written notification from Brittania-U that all of the required approvals under the Participation Agreement had been received. Syntroleum paid Brittania-U bonuses totaling $4 million for the interest in the Ajapa Field. Subject to rig availability and receipt of appropriate governmental permits, Syntroleum must commence or cause to commence Phase I of the work programs set forth in the Participation Agreement by March 15, 2007. Under Phase 1, the Company must spend at least $6 million to drill, evaluate, test and either complete or plug and abandon one well in the Ajapa Field. If the costs of the Phase 1 drilling program exceed $6 million, the Company has the option to either withdraw from this phase or continue this phase using additional funds. The Company currently estimates that it will cost more than $6 million for the Company to complete the Phase 1 drilling program. After Phase 1, the Company may either withdraw from the entire project or enter into continuing phases as outlined in the applicable agreements.

Until the completion of all three phases of the drilling program or the expenditure of the total commitment of $50 million and before project payout, the Company must pay 100 percent of all costs, including bonuses, in return for a 80 percent net revenue interest. After the completion of all three phases of the drilling program or the expenditure of the total commitment of $50 million and before project payout, the Company must pay 50 percent of all costs in return for an 80 percent net revenue interest in the field. After project payout, but before 15 million barrels of crude oil have been produced, the Company must pay 50 percent of all costs in return for a 50 percent net revenue interest in the field. After payout and after 15 million barrels of crude oil have been produced, the Company must pay 40 percent of all costs in return for a 40 percent net revenue interest. The Company is currently evaluating the financing options for this project.

There are three phases of the drilling program for the Ajapa Field with a total commitment of $50 million.

In addition, the Company is required to pay certain bonuses to Brittania-U, including the $4 million bonus paid out in September of 2006, a $3 million bonus if the Company elects to proceed to Phase 2 of the drilling program, and a final bonus based on the reserves established if the Company elects to proceed to Phase 3 of the drilling program.

On July 26, 2006, Syntroleum entered into a Participation Deed with EER, pursuant to which EER will acquire 50 percent of Syntroleum’s participating interest in the Ajapa Field. On September 14, 2006, EER paid Syntroleum a bonus of $4 million for the interest in the Ajapa Field. The transfer of the participating interest to EER is subject to approval of the Nigerian government, the Nigerian National Petroleum Corporation (“NNPC”) and Chevron Nigeria Limited. On October 20, 2006, Brittania-U formally notified the Company that it approved Syntroleum’s assignment of the interest to EER. Until the remaining required approvals are obtained, EER will pay to Syntroleum its proportionate share of all costs of the work programs discussed above. If all necessary approvals are not obtained by April 30, 2007, then Syntroleum will be required to repay EER for all costs, including bonuses, EER paid in supporting the participating interest.

The Company’s license agreements require it to indemnify its licensees, subject to a cap of 50 percent of the related license fees, against specified losses. Specified losses include the use of patent rights and technical information relating to the Syntroleum Process, acts or omissions by the Company in connection with the preparation of Process Design Packages (“PDPs”) for licensee plants and performance guarantees related to plants constructed by licensees. All amounts received for license fees have been recorded as deferred revenue in the consolidated balance sheets.

The accuracy and appropriateness of costs charged to the U.S. government contracts are subject to regulation, audit and possible disallowance by the Defense Contract Audit Agency or other government agencies. Accordingly, costs billed or billable to U.S. government customers are subject to potential adjustment upon audit by such agencies.

Most of the company’s U.S. government contracts are funded incrementally on a year-to-year basis. Changes in government policies, priorities or funding levels through agency or program budget reductions by the U.S. Congress or executive agencies could materially adversely affect the Company’s financial condition or results of operations. Furthermore, contracts with the U.S. government may be terminated or suspended by the U.S. government at any time, with or without cause. Such contract suspensions or terminations could result in unreimbursable expenses or charges or otherwise adversely affect the Company’s financial condition and/or results of operations. As of September 30, 2006 the Company has not experienced any violations in appropriateness of costs charged and priorities or funding levels have not been changed from original appropriations.

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.

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 Group Corporation (“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”). Subsequently, Ernest Williams II Q-TIP TUA dated 01/25/02 and Selim K. Zilkha Trust joined the Participation Agreement as venture participants and agreed to provide an additional capital commitment of $10,000,000 each, making the total commitment amount $60,000,000. Under the terms of the participation agreements entered into with the venture participants, the 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 the Company will acquire in any such project as well as repayment for 80 percent, plus accrued interest, of the funds contributed to the venture from the revenues of the projects acquired jointly. The current balance of $5,304,000, which includes accrued interest, has been included in liabilities in the accompanying consolidated balance sheet as of September 30, 2006. Interest is allocated to a portion of principal at an annual rate of 10 percent, compounded annually, in accordance with the Participation Agreement. The Company capitalizes interest associated with the Stranded Gas Venture to oil and gas properties in accordance with the full cost method.

The Company formed the Stranded Gas Venture for the primary purpose of obtaining funds to be used to evaluate investment opportunities, conduct oil and gas project development activities and acquire interests in oil and gas properties with previously discovered reserves, such as our Aje project in OML 113 offshore Nigeria. The effort was initially concentrated on oil projects with associated gas in West Africa, principally Nigeria, and successfully acquired rights in the Ajapa project in OML 90 offshore Nigeria. The Company is currently in discussions with the venture participants in the Stranded Gas Venture with regards to the portion of that interest that they are entitled to receive in Ajapa.

On September 22, 2006, the Company delivered written notice of default to Dorset for breach of the Participation Agreement due to Dorset’s failure to remit the funds necessary to meet its pro rate share of each capital call within ten business days of its notice of the capital call. Such breach had a cure period of five business days pursuant to the Participation Agreement during which Dorset failed to cure. The Company and Dorset are in discussions concerning the terms of the termination of the Participation Agreement. The Company does not expect to incur any material penalties in connection with the negotiations of the termination of the Participation Agreement with Dorset.

Dorset and Mr. Ziad Ghandour, a member of the board of directors of Syntroleum Corporation and a consultant to Syntroleum Corporation, were party to a separate arrangement, pursuant to which Mr. Ghandour agreed to be a participant in the Dorset Group Corporation. The Company has been informed that Mr. Ghandour is seeking to withdraw as a participant in Dorset, that Dorset has not consented to such withdrawal, and that discussions are occurring between Mr. Ghandour and Dorset concerning his desire to withdraw from Dorset.

The Company has reduced the Stranded Gas Venture liability by $1,254,000 for the amount requested of Dorset but not yet received in the accompanying consolidated balance sheet as of September 30, 2006. This amount was previously recorded in accounts receivable and the Stranded Gas Venture liability in the accompanying balance sheet as of December 31, 2005. The Company has received $4,423,000 in participant contributions as of September 30, 2006. The remaining participant receivable amount of $507,000 as of September 30, 2006 was received by Syntroleum on October 2, 2006.

13.

Reclassifications

Certain reclassifications have been made to the September 30, 2005 consolidated statements of operations and cash flows to reflect the impact of discontinued domestic oil and gas activities (Note 4). These reclassifications had no impact on consolidated net income (loss).

14.

New Accounting Pronouncements

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“FIN 48”) “Accounting for Uncertainty In Income Taxes – an Interpretation of FASB Statement 109”. FIN 48 clarifies that an entity’s tax benefits recognized in tax returns must be more likely than not of being sustained prior to recording the related tax benefit in the financial statements. As required by FIN 48, the Company will adopt this new accounting standard effective January 1, 2007. Management is currently reviewing the impact of FIN 48 on the Company’s financial statements.

In September 2006, the SEC Staff issued Staff Accounting Bulletin (SAB) 108, Financial Statements – Considering the Effects of Prior Years Misstatements When Quantifying Misstatements in Current Year Financial Statements. The application of SAB 108 is encouraged for an interim period of the first fiscal year ending after November 15, 2006. As of September 30, 2006, management is not aware of any prior year misstatements that would involve the application of SAB 108.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company will adopt SRAS No. 157 effective January 1, 2007. The adoption of SFAS No. 157 will not have a material impact on the Company’s consolidated results of operations and financial condition.

15.

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 our mobile facility, and ongoing research and development efforts focusing primarily on commercialization of the technology we 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.

The Domestic Oil and Gas segment includes the acquisition of oil and gas leases, geological and geophysical work, drilling and completion of wells and related administrative work in the United States. All of the assets of the Domestic Oil and Gas segment have been disposed of or are classified as held for sale. Management has classified this segment as discontinued operations in the consolidated statements of operations for the nine months ended September 30, 2006 and 2005 (See Note 4).

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 our GTL technologies in international areas. International Oil and Gas revenues will include revenues from production and processing of oil and gas.

The reportable business segments are summarized below (in thousands):

	Three Months Ended September 30,		Nine Months Ended September 30,
	2006	2005	2006	2005
Revenue
Technology, General, Administrative and Other	$ 2,860	$ 708	$ 3,600	$ 7,142
International Oil and Gas	-	-	-	-
Domestic Oil and Gas	-	-	-	-
Total	$ 2,860	$ 708	$ 3,600	$ 7,142
Operating Cost
Technology, General, Administrative and Other	$ 13,054	$ 10,464	$ 39,410	$ 32,056
International Oil and Gas	2,615	3,422	4,646	3,535
Domestic Oil and Gas	-	-	-	-
Total	$ 15,669	$ 13,886	$ 44,056	$ 35,591

Net Income/(Loss)
Technology, General, Administrative and Other	$ (10,390)	$ (9,389)	$ (36,648)	$ (24,006)
International Oil and Gas	(2,694)	(3,409)	(4,829)	36
Domestic Oil and Gas	63	(2,616)	(150)	(3,642)
Total	$ (13,021)	$ (15,414)	$ (41,627)	$ (27,612)
Capital Expenditures
Technology, General, Administrative and Other	$ (50)	$ 314	$ 206	$ 909
International Oil and Gas	5,337	2,776	7,678	10,155
Domestic Oil and Gas	-	2,271	-	4,217
Total	$ 5,287	$ 5,361	$ 7,884	$ 15,281

Total Assets		September 30, 2006	December 31, 2005
Technology, General, Administrative and Other		$ 41,321	$ 79,733
International Oil and Gas		11,254	8,135
Domestic Oil and Gas		1,000	1,927
Total		$ 53,575	$ 89,795

16.

Subsequent Events

On November 7, 2006, the Company filed a form S-3 to register shares to cover the offer and sale of warrants for the purchase of common stock and shares of common stock (including shares issuable upon exercise of the warrants and shares issuable in repayment of secured promissory notes dated May 8, 2002, as amended, and February 1, 2003, as amended, issued pursuant to the Participation Agreement between us and Marathon Oil Company dated May 8, 2002, as amended). Common stock and warrants were registered to cover the amounts granted to Sovereign Oil and Gas Company II, LLC in accordance with the joint development agreement. The total amount of shares registered was 4,706,986 and 100,000 warrants. The Company will not receive any proceeds from these sales.

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, 2005 (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 or other materials, 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 we expect will later include the use of our GTL technologies.

We seek to form joint ventures for projects and acquire equity interests in these projects. 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 designed barge- or ship-mounted GTL plant (“GTL Mobile Facility”), and avoid the inherent operating risks associated with using pure oxygen. We are reviewing the application of our technologies for the conversion of other feedstocks.

We are currently investing a significant amount of our resources into our designed GTL Mobile Facility and other potential international or domestic GTL or CTL projects. We believe that these projects offer the greatest potential to meet our objective of generating 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, Germany, Nigeria, Papua New Guinea, and the United States.

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 which we own an interest in the near future. As a result, we expect to continue to operate at a loss until sufficient revenues are recognized from licensing activities, commercial operation of GTL or CTL plants or non-GTL projects we are developing. As of September 30, 2006, we had approximately $38,251,000 of cash and cash equivalents available to fund operations. We believe that we currently have sufficient cash and financing capabilities to meet our funding requirements over the next year. However, we have experienced, and continue to experience, negative operating margins and negative cash flows from operations, as well as an ongoing requirement for substantial additional capital investment related to construction of GTL or CTL plants and other activities, including exploration and production of energy assets and research and development programs in which we participate.

We are currently exploring alternatives for raising capital to fund the growth of our GTL business, our CTL business and our acquisition of oil and gas properties, including the formation of joint ventures and other strategic alliances. We may also seek to obtain additional funding through debt or equity financing in the capital markets, as well as other financing arrangements. If adequate funds are not available, or if we are not successful in establishing a strategic alliance, we may be required to reduce, delay or eliminate expenditures for our GTL and CTL plant development and other activities, as well as our research and development and other activities, or may 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. The transactions outlined above may not be available to us when needed or on terms acceptable or favorable to us.

Operating Revenues

During the periods discussed below, our revenues were primarily generated from joint development activities with government entities and other oil and gas companies for research and development activities associated with the Syntroleum Process and various types of fuel sales. In the future, we expect to receive revenue from sales of products or fees for the use of GTL and CTL plants in which we will own an equity interest, demonstration plant product sales, licensing, catalyst sales, research and development activities carried out with industry participants, and oil and gas projects we are developing.

Until the commencement of commercial operation of GTL or CTL plants in which we own an interest or an oil and gas project we are developing, we expect that cash flow relating to the Syntroleum Process will consist primarily of 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 and will not receive additional license fees until we enter into additional license agreements or existing licensees develop commercial plants. 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 technologies, the success of our non-GTL projects, and other competing uses for natural gas or coal. 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.

GTL/CTL Plant Revenues. We intend to develop GTL or CTL 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 or CTL plants will include co-venturers who have low-cost gas or coal 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 Floating, Production, Storage and Offloading vessel (“FPSO”) operators.

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 produce oil or natural gas 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 produced and sold to purchasers. Projects we are currently pursuing include the upstream development of OML 113, including the Aje Field, and the Ajapa field within OML 90 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.

License Revenues. We expect to generate revenue earned from licensing the Syntroleum 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) an agreed royalty rate. Our licensee 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 performance 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.

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.

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 and CTL 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”) and Ivanhoe. Currently, Marathon is the only party to receive 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 (the “Catoosa Demonstration Facility”) used as part of the DOE Ultra-Clean Fuels Production and Demonstration Project with Marathon affect the comparability of the periods presented.

Demonstration Plant Product Sales Revenues. We expect to provide synthetic ultra-clean diesel fuel, such as our S-2 diesel fuel, S-8 jet fuel (subject to certification) and FC-1 naphtha fuels to the U.S. Department of Transportation (“DOT”), DOD and various other 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 and alcohols. The fuels are produced at our Catoosa Demonstration Facility. Revenues will be recognized upon delivery of the requested fuels. During the periods presented, product sales revenues consisted primarily of amounts received from the DOD and DOT.

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 expenses 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, pilot plant 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 and CTL technologies including our GTL Mobile Facility project. These costs, which relate primarily to outside contract services for initial engineering, design, and development, are included in pilot plant, engineering and 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 all of the required 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. In September 2006, the Company completed the production of our contract committed volume of fuels to the United States Department of Defense. In addition, we also successfully completed the longest run of our catalyst testing activity at the Tulsa pilot plant. In line with the program completion of our demonstration plants, we have placed both plants in standby mode.

We have also recognized depreciation, depletion, amortization, and impairment expense primarily related to

oil and gas assets, 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. During the quarter ended September 30, 2006, we made a strong effort to further reduce operating costs. In line with the program completion of our demonstration plants, we reduced our operating costs by placing the plants in standby mode, reducing our workforce and focusing on cost minimization. We recorded $566,000 of severance expense related to workforce reductions. This workforce reduction amounted to 46 employees. We do not expect to rehire any of the employees included in the reductions if we accelerate the development of a commercial project. We expect to pay in full a significant portion of the severance payments related to our staff reduction by the end of 2006. We plan to continue to monitor our expenditures with regards to general and administrative expense throughout 2007 as well. Our operating expenses could increase further if we accelerate our development of these or other 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 or coal feedstocks for the plant 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.

Discontinued Operations

We were pursuing gas monetization projects in which we were directly involved in gas field development using available gas processing technologies from third parties. We 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. The project consisted of acquiring leases of approximately 85,000 acres in the Central Kansas Uplift area, drilling of eight and the re-entry of three wells throughout 2004 and 2005. Limited production from the first well began in January 2005.

We have completed an evaluation of potential reserves related to drilled properties in the United States and decided to discontinue further expenditures in the Central Kansas Uplift area based on management’s decision to focus efforts with company specific goals in line with strategic activities. We recorded impairment expense of $205,000 related to the associated gas processing plant and equipment during the quarter ended March 31, 2006. We successfully sold certain leasehold acres during 2005 for $1,000,000. The remaining leasehold acreage, including the wells and equipment, sold for $522,000 in January, 2006. We are actively seeking prospects for sale of our gas processing plant and related equipment and expect to complete the sale in 2006. We recognized a gain on the disposal of some of the related equipment in September 2006 of $67,000. Net oil and gas equipment classified as held for sale is $1,000,000 as of September 30, 2006.

Significant Developments During 2006

Commercial and Licensee Projects

OML 90. In November 2005, we entered into a Heads of Agreement with Brittania-U Nigeria Limited (“Brittania-U”) to acquire a 40 percent participating interest in the Ajapa Marginal Field (the “Ajapa Field”) in OML 90 offshore Nigeria, which has a size of approximately 11,367 acres. On February 26, 2006, we entered into a Participation Agreement and Joint Operating Agreement with Britannia-U regarding the Ajapa Field. We received approval from the Nigerian government on June 12, 2006. On September 13, 2006, the Company received written notification from Brittania-U that all of the required approvals under the Participation Agreement had been received. Syntroleum paid Brittania-U bonuses totaling $4 million for the interest in the Ajapa Field. Subject to rig availability and receipt of appropriate governmental permits, Syntroleum must commence or cause to commence Phase I of the work programs set forth in the Participation Agreement by March 15, 2007. Under Phase 1, we must spend at least $6 million to drill, evaluate, test and either complete or plug and abandon one well in the Ajapa Field. If the costs of the Phase 1 drilling program exceed $6 million, we have the option to either withdraw from this phase or continue this phase using additional funds. We currently estimate that it will cost more than $6 million for us to complete the Phase 1 drilling program. After Phase 1, we may either withdraw from the entire project or enter into continuing phases as outlined in the applicable agreements.

Until the completion of all three phases of the drilling program or the expenditure of the total commitment of $50 million and before project payout, we must pay 100 percent of all costs, including bonuses, in return for a 80 percent net revenue interest. After the completion of all three phases of the drilling program or the expenditure of the total commitment of $50 million and before project payout, we must pay 50 percent or all costs in return for an 80 percent net revenue interest in the field. After project payout, but before 15 million barrels of crude oil have been produced, we must pay 50 percent of all costs in return for a 50 percent net revenue interest in the field. After payout and after 15 million barrels of crude oil have been produced, we must pay 40 percent of all costs in return for a 40 percent net revenue interest. We are currently evaluating the financing options for this project. In accordance with our agreement with Sovereign, we issued Sovereign warrants to purchase 25,000 shares of our common stock for its efforts related to this project. This is a non-cash expense to the Company.

There are three phases of the drilling program for the Ajapa Field with a total commitment of $50 million. In addition, we are required to pay certain bonuses to Brittania-U, including the $4 million bonus paid out in September of 2006, a $3 million bonus if we elect to proceed to Phase 2 of the drilling program, and a final bonus based on the reserves established if we elect to proceed to Phase 3 of the drilling program.

On July 26, 2006, we entered into a Participation Deed with EER, pursuant to which EER will acquire 50 percent of our participating interest in the Ajapa Field. On September 14, 2006, EER paid us a bonus of $4 million for the interest in the Ajapa Field. The transfer of the participating interest to EER is subject to approval of the Nigerian government, the Nigerian National Petroleum Corporation (“NNPC”) and Chevron Nigeria Limited. On October 20, 2006, Brittania-U formally notified us that it approved our assignment of the interest to EER. Until the remaining required approvals are obtained, EER will pay to us its proportionate share of all costs of the work programs discussed above. If all necessary approvals are not obtained by April 30, 2007, then we will be required to repay EER for all costs, including bonuses, EER paid in supporting the participating interest. In accordance with our agreement with Sovereign, we issued Sovereign warrants to purchase 25,000 shares of our common stock for its efforts related to this project. This is a non-cash expense to the Company.

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. On October 7, 2004 we and YFP entered into a Joint Venture Agreement pursuant to the Heads of Agreement. The license covers approximately 413,000 acres.

On January 13, 2005, we finalized agreements to begin the delineation of the Aje Field. The agreements are with YFP and several other companies, to which we refer collectively as the “Participants.” The agreements required the Participants to pay 90 percent of the cost to drill and log one delineation well in the Aje Field 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.

We secured and drilled the first delineation well, which we refer to as the “Aje-3 well” during the third quarter of 2005. 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. The Participants found the economics for commercial completion to be unfavorable. In October 2005, the well was plugged and abandoned. 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. As noted above, 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. In early October 2006, Challenger Minerals (Nigeria) Limited, Providence Resources, EER, YFP and Syntroleum agreed to pursue the drilling of an additional appraisal well (“Aje-4”) on OML 113. Lundin Nigeria Limited and Palace Exploration Nigeria Limited have opted not to participate in the drilling of Aje-4. As a result of Lundin’s and Palace’s decision not to participate, YFP and Syntroleum are in discussions with several additional companies interested in joining the participant group. Under the original joint venture agreement with YFP, Syntroleum and its partners have until April 5, 2007 to commence drilling Aje-4, subject to rig availability. The rights to this block will be returned to YFP if the drilling of a second well does not commence by April 5, 2007, subject to rig availability. Howard Energy Co., Inc. is no longer a Participant in this project as of December 2005. Their respective interest has been assumed by the Participants remaining as of December 2005. We expect to incur additional expenditures relating to this project in the future, and the amount of such expenditures could be substantial.

Stranded Gas Venture. On April 11, 2005, our wholly owned subsidiary, Syntroleum International Corporation (“Syntroleum International”), entered into a Participation Agreement with Dorset Group Corporation

(“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”). Subsequently, Ernest Williams II Q-TIP TUA dated 01/25/02 and Selim K. Zilkha Trust joined the Participation Agreement as a venture participant and agreed to provide an additional capital commitment of $10,000,000 each, making the total commitment amount $60,000,000. Under the terms of the participation agreements entered into with other venture participants, 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 will acquire in any such project as well as repayment for 80 percent, plus accrued interest, of the funds contributed to the venture from the revenues of the projects acquired jointly. The current balance of $5,304,000, which includes accrued interest, has been included in liabilities in the accompanying consolidated balance sheet as of September 30, 2006. Interest is allocated to a portion of principal at an annual rate of 10 percent, compounded annually, in accordance with the Participation Agreement. We capitalize interest associated with the Stranded Gas Venture to oil and gas properties in accordance with the full cost method.

We formed the Stranded Gas Venture for the primary purpose of obtaining funds to be used to evaluate investment opportunities, conduct oil and gas project development activities and acquire interests in oil and gas properties with previously discovered reserves, such as our Aje project in OML 113 offshore Nigeria. The effort was initially concentrated on oil projects with associated gas in West Africa, principally Nigeria, and successfully acquired rights in the Ajapa project in OML 90 offshore Nigeria. We are currently in discussions with the venture participants in the Stranded Gas Venture with regards to the portion of that interest that they are entitled to receive in Ajapa.

On September 22, 2006, we delivered written notice of default to Dorset for breach of the Participation Agreement due to Dorset’s failure to remit the funds necessary to meet its pro rate share of each capital call within ten business days of its notice of the capital call. Such breach had a cure period of five business days pursuant to the Participation Agreement during which Dorset failed to cure. We are in discussions with Dorset concerning the terms of the termination of the Participation Agreement. We do not expect to incur any material penalties in connection with the negotiations of the termination of the Participation Agreement.

Dorset and Mr. Ziad Ghandour, a member of our board of directors and a consultant to us, were party to a separate arrangement, pursuant to which Mr. Ghandour agreed to be a participant in the Dorset Group Corporation. We have been informed that Mr. Ghandour is seeking to withdraw as a participant in Dorset, that Dorset has not consented to such withdrawal, and that discussions are occurring between Mr. Ghandour and Dorset concerning his desire to withdraw from Dorset.

We reduced the Stranded Gas Venture liability by $1,254,000 for the amount requested of Dorset but not yet received in the accompanying consolidated balance sheet as of September 30, 2006. This amount was previously recorded in accounts receivable and the Stranded Gas Venture liability in the accompanying balance sheet as of December 31, 2005. We have received $4,423,000 in participant contributions as of September 30, 2006. The remaining participant receivable amount of $507,000 as of September 30, 2006 was received by us on October 2, 2006.

Mobile GTL Facility. We refer to both our GTL Barge and GTL FPSO as a Mobile GTL Facility. In August 2003, we announced our plan to commercialize a GTL Barge. The GTL Barge is designed to develop near-shore coastal natural gas fields and the GTL FPSO is designed to develop offshore natural gas fields. The Mobile GTL Facility focuses on 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 Mobile GTL Facility builds on the strengths and advantages of the Syntroleum Process, which utilizes air instead of oxygen. The Mobile GTL Facility is also designed to have equipment to process 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. 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.

In February 2006, we executed a Letter of Intent with Bluewater to memorialize the intentions of the formation of a joint venture to develop, construct, own and operate a FPSO vessel equipped with gas-to-liquids conversion capability. We and Bluewater will each bear 50 percent of the costs associated with the formation of the

joint venture. The Letter of Intent will terminate on the first date to occur of an executed and mutually signed definitive agreement with respect to the joint venture or December 31, 2007.

Ivanhoe Energy. In November 2005, 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 TCF of natural gas for the anticipated 20-year operating life of the proposed project.

Sustec AG. On January 31, 2006, we entered into a Memorandum of Understanding (the “MOU”) with Sustec AG (“Sustec”), a private company based in Basel, Switzerland and parent company of Future Energy of Freiberg, Germany that provides for exclusive joint business development of projects that will integrate Future Energy’s GSP gasification technology with our Fischer-Tropsch technology. The purpose of the joint venture is to develop projects for the conversion of coal and other carbonaceous materials such as pet-coke, reside and biomass into ultra-clean fuels. Subsequent to the execution of this MOU, Sustec completed a transaction with Siemens whereby ownership of the GSP gasification technology and certain other assets were transferred to Siemens. Sustec retained access rights to the GSP gasification technology and has a license to utilize the GSP technology with certain Syntroleum Fischer-Tropsch projects at market rates.

On June 2, 2006 a Project Framework Agreement (“Agreement”) was entered into by us and Sustec outlining the framework for the first project with Sustec in accordance with the MOU. Together we are jointly developing the Spreetal project, up to a 3,000 bpd Fischer-Tropsch Plant which represents Phase One of a planned 20,000 bpd plant. We are considering means to lower the capital cost and reduce the time to commercial operation for this plant, which may include reducing the size of the initial phase of the project. This Agreement will terminate on December 31, 2007 subject to any written extensions by mutual agreement of the parties.

Papua New Guinea. In November 2005, we entered into a Memorandum of Understanding with the government of Papua New Guinea to examine the development of an approximately 50,000 b/d GTL plant as part of an industrial complex dedicated to gas-based industries near the capital city of Port Moresby. We will work with the government of Papua New Guinea Ministry of Planning and Development to study the feasibility of a large GTL plant that would share natural gas pipeline infrastructure facilities with various other possible gas conversion participants, including ammonia, methanol and power plant developers.

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 would enable our technology to benefit from Linc Energy’s underground coal gasification (“UCG”) expertise, is part of Linc Energy’s ongoing Chinchilla 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 has been extended to terminate on December 31, 2006, unless extended further by mutual agreement of the parties.

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 project included the construction of the Catoosa Demonstration Facility, a plant 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. 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 have installed additional facilities at the Catoosa Demonstration Facility outside the scope of the DOE Catoosa Project.

In September 2006, the Company completed the production of our contract committed volume of fuels to the United States Department of Defense. In addition, we also successfully completed the longest run of our catalyst testing activity at the Tulsa pilot plant. In line with the program completion of our demonstration plants, the Company has placed both plants in standby mode.

DOD Project. 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 our contracts occurred in the fourth quarter and we began work at that time. We have recognized $263,000 in joint development revenue in the nine months ended September 30, 2006 and $435,000 from this project during the year ended December 31, 2005. This contract was completed in the quarter ended September 30, 2006.

In August 2004, Congress appropriated $4.5 million for Phase III development of our Flexible JP-8 single battlefield fuel Pilot Plant Program 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 $658,000 in joint development revenue from this project in the nine months ended September 30, 2006 and $747,000 during the year ended December 31, 2005. We expect to complete the contract in early 2007.

In June 2006, we signed a contract to deliver the initial 100,000 gallons of FT alternative fuel to the DOD for evaluation under the DOD’s larger program aimed at long-term prospects for the domestic manufacture and supply of synthetic aviation fuels from FT plants. We completed production and shipment of our 100,000 gallons of FT alternative fuel commitment in early September 2006. On September 19, 2006, Syntroleum’s ultra-clean jet fuel was successfully tested in a United States Air Force B-52 Stratofortress Bomber aircraft. The plane lifted off from Edwards Air Force Base with a 50/50 blend of FT and traditional JP-8 jet fuel which was burned in two of the eight engines on the plane. This marks the first time that FT jet fuel has been tested in a military flight demo, and is the first of several planned test flights. The Company expects to recognize approximately $2,216,000 in revenue from the sale of jet fuel and labor associated with this contract. We recognized other revenue in the amount of $2,183,000 in the third quarter related to shipment of FT alternative fuel and related contract approved costs. The government is currently seeking up to 200 million gallons of alternative synthetic aviation fuel in 2008 and we anticipate submitting a proposal to them.

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 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. We expect to finalize this contract in 2006. We anticipate receiving revenues from this contract in 2007.

DOT Fuel Evaluation Program. In November 2005, the 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. We have recognized $282,000 in other revenue from this in the nine months ended September 30, 2006 and $364,000 during the year ended December 31, 2005.

Coal Derived Synthesis Gas. In November 2005, we announced an agreement to conduct laboratory-scale demonstration of our FT catalyst with coal-derived synthesis gas produced at an established gasification facility. The new testing program will demonstrate the effectiveness of the Syntroleum FT catalysts with proven coal-derived synthesis gas clean-up and treatment processes for use in a CTL application. The testing protocol will include two bench-scale FT reactors and gas sampling connections to the clean synthesis gas production flow. The testing program is planned to begin during 2006 and is expected to run for approximately six months. Our specialists will work with the personnel from the gasification company in this program funded by us.

Research and Development Projects

Our primary research and development projects during the nine months ended September 30, 2006 related to our GTL technologies for use in GTL plants, including catalyst performance evaluation and enhanced reactor designs. Expenses for pilot plant, engineering and research and development incurred during the nine months ended

September 30, 2006 totaled $10,057,000. 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 GTL Mobile Facility. We also operated our Catoosa Demonstration Facility through August of 2006 for further research and development, fuel production for fuels sales contracts, and additional testing. Expenses incurred for the operations and modifications to our Catoosa Demonstration Facility during the nine months ended September 30, 2006 totaled $7,642,000.

Results of Operations

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005

Revenues	September 30, 2006	September 30, 2005
	(in thousands)
Joint Development Revenue	$ 390		$ 616
Other	2,470		92
Total Revenues	$ 2,860		$ 708

Joint Development Revenue. Revenues from our joint research and development and demonstration operations were $390,000 for the quarter ended September 30, 2006 compared with $616,000 for the same period in 2005. The decrease was primarily due to:

•	lower revenues received from joint development activities with the DOD for technical studies and design for our FPSO and further research of conversion and testing of fuels as a majority of the conversion work was completed and recognized in 2005.
•	2005 revenues also consisted of revenues for joint development activities associated with other licenses.

Other Revenue. Other revenues were $2,470,000 for the quarter ended September 30, 2006 compared to $92,000 for the same period in 2005. The increase was primarily due to GTL fuel sales to the Tulsa Transit Authority in Oklahoma and Fairbanks North Star Borough in Fairbanks, Alaska in accordance with our sub-agreement with the Department of Transportation and GTL fuel sales to the United States Department of Defense under the DOD’s fuel initiative in the third quarter of 2006.

Operating Costs and Expenses	September 30, 2006	September 30, 2005
	(in thousands)
Catoosa Demonstration Facility	$ 1,988	$ 2,456
Pilot plant, engineering and research and development	3,409	2,980
Depreciation, depletion, amortization and impairment	2,817	3,574
General and administrative and other	7,455	4,876
Total Operating Costs and Expenses	$ 15,669	$ 13,886

Catoosa Demonstration Facility. Expenses related to the Catoosa Demonstration Facility totaled $1,988,000 during the quarter ended September 30, 2006 compared to $2,456,000 during the same period in 2005. The decrease primarily resulted from decreased costs associated with the DOD fuel run as the refinery was the only portion of the plant incurring expenses and no feedstock was consumed during the three months ended September 30, 2006.

Pilot Plant, Engineering and R&D Expense. Expenses from pilot plant, engineering and research and development activities were $3,409,000 for the quarter ended September 30, 2006 compared to $2,980,000 during the same period in 2005. The increase in expenditures resulted primarily from:

•	Construction of a laboratory-scale demonstration of our FT catalyst with coal-derived synthesis gas produced at an established gasification facility in 2006.

•	Continuous and increased studies and documentation for process design of a GTL plant.

•	Modifications, commissioning and continuing operations costs associated with the Tulsa Pilot Plant in 2006.

Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expenses were $2,817,000 for the quarter ended September 30, 2006 compared to $3,574,000 during the same period in 2005. The decrease relates to impairment of Aje-3 drilling costs in 2005 in the amount of $3,331,000. In 2006 an impairment of $2,600,000 was recognized for projects that management intends to not pursue further.

General and Administrative and Other. General and administrative expenses for the quarter ended September 30, 2006 were $7,455,000 compared to $4,876,000 during the same period in 2005. The increase primarily resulted from:

•	Non-cash equity compensation of $1,748,000 during the quarter ended September 30, 2006 related to the adoption of SFAS 123(R), and continuing efforts of SFAS 123(R) for new employee grants which changes the valuation technique for all share based compensation for employees and requires the value of the shares to be expensed and also related to the vesting of warrants and options granted to consultants in 2006 compared to non-cash equity compensation of $551,000 during the quarter ended September 30, 2005.
•	Severance expenses in the amount of $566,000 in the third quarter related to the necessary staff reductions due to placing our demonstration and testing facilities on standby.
•	We have incurred increased professional consultant charges in efforts to market our technology.

Other Income and Expenses and Net Income (Loss)	September 30, 2006	September 30, 2005
	(in thousands)
Investment and Interest Income	$ 597	$ 785
Interest Expense	(580)	(430)
Other Income (Expense), net	(40)	2
Foreign Currency Exchange	(252)	23
Income Taxes	-	-
Income from discontinued domestic oil and gas business	63	(2,616)

Net Income (Loss)	$ (13,021)	$ (15,414)

Investment and Interest Income. Investment and interest income was $597,000 in the quarter ended September 30, 2006 compared to $785,000 during the same period in 2005. The decrease primarily resulted from decreased interest income earned on a lower cash balance compared to the same quarter in 2005.

Interest Expense. Interest expense was $580,000 during the first quarter ended September 30, 2006 compared to interest expense of $430,000 during the same period in 2005. The increase primarily resulted from compounding of interest related to the Marathon convertible debt.

Other Income (Expense) and Foreign Exchange. Other income (expense), including foreign exchange loss, was a loss of $292,000 for the quarter ended September 30, 2006, compared to income of $25,000 during the same period in 2005. The decrease resulted primarily from foreign currency losses in 2006 due to the change in the exchange rate between the United States dollar and the Australian dollar, which relates to our license with the Commonwealth of Australia which is denominated in Australian dollars.

Income from Operations of Discontinued Domestic Oil and Gas Business. We recognized income from the discontinuation of the domestic oil and gas business for the quarter ended September 30, 2006 of $63,000 compared to a loss of $2,616,000 for the same period in 2005. In September 2006 we sold some of the gas processing equipment for a gain of $67,000. In 2005 we recognized depletion, depreciation, amortization and impairment on the domestic oil and gas assets of $3,556,000. These assets were determined to be a part of a discontinued operation in 2005 and impaired to their current fair market value.

Net Income (Loss). The total net loss for the quarter ended September 30, 2006 was $13,021,000 compared to $15,414,000 for the same period in 2005. The decreased loss primarily resulted from:

•	Variances stated above and an increase in General and Administrative expenses, foreign currency, and non-cash equity compensation partially offset by increased revenue when compared to the same period in 2005.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Revenues	September 30, 2006	September 30, 2005
	(in thousands)
Joint Development Revenue	$ 1,020	$ 7,044
Other	2,580	98
Total Revenues	$ 3,600	$ 7,142

Joint Development Revenue. Revenues from our joint research and development and demonstration operations were $1,020,000 for the nine months ended September 30, 2006, compared with $7,044,000 for the same period in 2005. The decreased in 2006 was primarily related to:

•	Revenues in the nine months ended September 30, 2006 primarily consisted of revenues from the DOD related to technical studies and design for a FPSO, further research of conversion and testing of fuels.
•	The recognition during the nine months ended September 30, 2005 of previously deferred revenue in regards to the completion of our fuel delivery commitment with the DOE of $5,798,000.

Other Revenue. Other revenues were $2,580,000 for the nine months ended September 30, 2006 compared to $98,000 for the same period in 2005. The increase was primarily due to the delivery and recognition of 100,000 gallons of GTL fuels to the United States Department of Defense under their domestic fuel initiative and GTL fuel sales to the Tulsa Transit Authority in Oklahoma and Alaska in accordance with our sub-agreement with the Department of Transportation.

Operating Costs and Expenses	September 30, 2006	September 30, 2005
	(in thousands)
Catoosa Demonstration Facility	$ 7,642	$ 7,039
Pilot plant, engineering and research and development	10,057	7,586
Depreciation, depletion, amortization and impairment	5,252	3,943
General and administrative and other	21,105	17,023
Total Operating Costs and Expenses	$ 44,056	$ 35,591

Catoosa Demonstration Facility. Expenses related to the Catoosa Demonstration Facility were $7,642,000 during the nine months ended September 30, 2006 compared to $7,039,000 during the same period in 2005. The increase resulted from:

•	Modifications to the plant throughout the year for additional testing and design work.
•	Operating expenses for the facility were relatively consistent throughout 2005 and 2006.

Pilot Plant, Engineering and R&D Expense. Expenses from pilot plant, engineering and research and development activities were $10,057,000 for the nine months ended September 30, 2006 compared to $7,586,000 during the same period in 2005. The increase in expenditures primarily resulted from:

•	Construction of a laboratory-scale demonstration of our FT catalyst with coal-derived

synthesis gas produced at an established gasification facility in 2006.

•	Continuous and increased studies and documentation with professional engineering firms for process design of a GTL plant.

Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expenses were $5,252,000 for the nine months ended September 30, 2006 compared to $3,943,000 during the same period in 2005, the increase primarily resulted from:

•	Geological and geophysical costs in the amount of $4,638,000 impaired in 2006 due to the unlikely future development of certain projects primarily in Nigeria and Indonesia
•	In 2005 we impaired the costs associated with the drilling and testing of Aje-3 in the amount of $3,331,000.

General and Administrative and Other. General and administrative expenses for the nine months ended September 30, 2006 were $21,105,000 compared to $17,023,000 during the same period in 2005. The increase primarily resulted from:

•	Non-cash equity compensation of $5,202,000 during the nine months ended September 30, 2006 and primarily related to the adoption of SFAS 123(R), and continuing effects of SFAS 123 (R) for new employee grants which changes the valuation technique for all share based compensation for employees and requires the value of the shares to be expensed and also related to the vesting of warrants and options granted to consultants, compared to non-cash equity compensation of $3,788,000 during the same period in 2005 and related to the vesting of warrants granted to a consultant upon the achievement of our agreement with Bluewater and vesting of restricted stock units.
•	Severance expenses in the amount of $566,000 in the third quarter related to the necessary staff reductions due to placing our demonstration and testing facilities on standby.
•	We have incurred increased professional consultant charges in efforts to market our technology

Other Income and Expenses and Net Income (Loss)	September 30, 2006	September 30, 2005
	(in thousands)
Investment and Interest Income	$ 2,040	$ 1,731
Interest Expense	(1,561)	(1,275)
Other Income (Expense), net	(1,247)	3,730
Foreign Currency Exchange	(253)	293
Income Taxes	-	-
Income from discontinued domestic oil and gas business	(150)	(3,642)

Net Income (Loss)	$ (41,627)	$ (27,612)

Investment and Interest Income. Investment and interest income was $2,040,000 in the nine months ended September 30, 2006 compared to $1,731,000 during the same period in 2005. The increase primarily resulted from:

•	Increased interest income earned on a higher cash balance for the nine months ended September 30, 2006 compared to cash balance in 2005, which increased in the second quarter of 2005.

•	Settlement of Note Receivable with Fitzgeralds in the first quarter of 2006.

Interest Expense. Interest expense was $1,561,000 during the nine months ended September 30, 2006 compared to interest expense of $1,275,000 during the same period in 2005. The increase primarily resulted from compounding of interest related to the Marathon convertible debt.

Other Income (Expense) and Foreign Exchange. Other income (expense), including foreign exchange loss, was a loss of $1,500,000 for the nine months ended September 30, 2006, compared to income of $4,023,000 during the same period in 2005. The increase primarily resulted from:

•	Foreign currency losses in 2006 due to the change in the exchange rate between the United States dollar and the Australian dollar, which relates to our license with the Commonwealth of Australia which is denominated in Australian dollars.
•	A $3,556,000 gain recognized in connection with the signature bonus we received in the second quarter of 2005 from the Participants in the Aje Field development project.
•	A $1,200,000 expense associated with proposed financing of our CTL technology and business development opportunities. This amount was previously capitalized and deemed to be an expense as management does not believe that it is probable that this financing will occur under the original terms of the financing agreement.

Income from Operations of Discontinued Domestic Oil and Gas Business. Loss from the discontinuation of the domestic oil and gas business for the nine months ended September 30, 2006 was $150,000 and $3,642,000 for the same period in 2005. The decreased loss primarily resulted from assets being classified as held for sale and were written down to estimated market value in 2006. Further impairments were recorded in 2006 as the Company obtained additional information about the estimated fair values of the assets. The 2006 loss is partially offset by a gain of $67,000 recognized on the sale of certain equipment.

Net Income (Loss). The total net income loss for the nine months ended September 30, 2006 was $41,627,000 compared to $27,612,000 for the same period in 2005. The increased loss primarily resulted from:

•	Increasing operating expenditures to increase research and development activities and other factors as described above.

•	Recognition of previously deferred revenue for the DOE contract in 2005.
•	Signature bonus from Participants in Aje Field development project in 2005.

Liquidity and Capital Resources

General

As of September 30, 2006, we had $38,251,000 in cash and cash equivalents. We also had $2,595,000 in restricted cash related primarily to our agreement with Sovereign, a consulting firm that has assisted us in acquiring oil and natural gas fields worldwide and amounts held in escrow related to the settlement of our note receivable with FRI (See Note 9). Our current liabilities totaled $30,636,000, including $27,281,000 of convertible debt with Marathon that matures on December 15, 2006.

At September 30, 2006, we had $2,489,000 in accounts receivable outstanding relating to our GTL fuel sales, joint development activities, and our stranded gas venture. 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 $29,498,000 during the nine months ended September 30, 2006, compared to $23,720,000 during the nine months ended September 30, 2005. The increase in cash flows used in operations results from increasing costs at the Catoosa Demonstration Facility from continuing operations, Pilot Plant Facility continuing operations, construction and other research and development activities from revenues compared to the same period in 2005. The Company expects a continuing decrease in cash flows used in operations in the future due to the decreased expenditures associated with both demonstration plants placed in standby mode.

Cash flows used in investment activities were $2,082,000 during the nine months ended September 30, 2006, compared to cash flows used in investment activities of $9,391,000 during the nine months ended September 30, 2005. The decrease in cash used in investing activities is primarily related to a decrease in cash held in escrow related to our Sovereign agreement and increased proceeds from the conveyance of interests in OML 90 in 2006.

Cash flows provided by financing activities were $170,000 during the nine months ended September 30, 2006, compared to cash flows provided by financing activities of $83,566,000 during the nine months ended September 30, 2005. The decrease 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 $352,000 during the same period in 2006.

We have expended and will continue to expend a substantial amount of funds to continue the research and development of our GTL and CTL technologies, to market the Syntroleum Process, to design and construct GTL and CTL plants, and to develop our other commercial projects. The CDF was placed in standby mode in the third quarter subsequent to completion of testing and fuel deliveries on current commitments and after program completion, the Pilot Plant will be placed in standby mode during the fourth quarter of 2006. This should decrease our operating expenses related to those facilities in the future. We also expect to invest capital into our international oil and gas opportunities during 2006, with partial funding provided by our Stranded Gas Venture described above in “-Significant Developments in 2006 – Commercial and Licensee Projects – Stranded Gas Venture”.

Our current efforts to fund the growth of our CTL business, including the development, and demonstration of effectiveness, of our technology with coal-derived synthesis gas, focus on joint development agreements with strategic partners. In January 2006, we entered into a memorandum of understanding with Sustec to form a joint venture to develop projects that will integrate Sustec’s coal gasification technology with our Fischer-Tropsch technology described above in “- Significant Developments in 2006 – Commercial and Licensee Projects – Sustec AG.”

If adequate funds are not available, or if we are not successful in establishing a strategic alliance, 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 may 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 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. 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.

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 and adversely affect us.

Contractual Obligations –

The following table sets forth our contractual obligations as of September 30, 2006:

Contractual Obligations	Payments Due by Period (in thousands)
	Total	Less than 1 year	1-3 years	4-5 years	After 5 years
Long Term Debt Obligations	$ 27,281	$ 27,281	$ -	$ -	$ -
Purchase Obligations	6,000	6,000	-	-	-
Capital (Finance) Lease Obligations	135	89	46	-	-
Operating Lease Obligations	7,740	1,106	1,632	1,109	3,893
Other Long-Term Liabilities reflected On the Balance Sheet under GAAP	5,304	-	-	-	5,304
Total	$ 46,460	$ 34,476	$ 1,678	$ 1,109	$ 9,197

We have entered into employment agreements, which provide severance benefits to several key employees. Commitments under these agreements totaled approximately $5.9 million at September 30, 2006.

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 $21.3 million between Marathon and us for costs relating to the DOE Catoosa Project. At September 30, 2006, we had received advances of $21.3 million under the loan and we had accrued interest of $6.0 million. Each note bears interest at a rate of eight percent per year and has been extended to mature on December 15, 2006. We are currently evaluating various options with regards to this note. 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 that would allow Marathon to complete the project in the event of a default by us. 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, 2006 we were in compliance with the provisions of the note agreements. The DOE Catoosa Project was partially funded with these note agreements, as changes in the scope of the project have occurred. Continued operation of the Catoosa Demonstration Facility has been funded by us.

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.

In accordance with our Participation Agreement and Joint Operating Agreement with Brittania-U described above in “-Significant Developments During 2006,” we must commence Phase I drilling which includes drilling and evaluation and, if necessary, testing of the Ajapa-2 well in OML 90 at a budgeted committed cost of $6 million. Based on current cost estimates, we anticipate exceeding the committed cost budget for the drilling phases. Our agreement with EER calls for them to pay 50% of our participating interest costs plus a $4 million bonus to earn 50% of our participating interest in Ajapa. EER paid the $4 million bonus in the quarter ended September 30, 2006. This agreement is subject to government and farmor approvals. If these approvals are not received by April 30, 2007, we must repay EER all costs remitted related to the participating interest in Ajapa.

Our operating leases include leases for corporate equipment such as copiers, printers and vehicles. We had leases on our laboratory, our Houston office and our Bolivian 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.

We are also in discussions with various parties regarding joint venture projects. If these discussions progress, we could enter into additional commercial commitments. These discussions currently relate to projects to be located in Australia, Egypt, Germany, Nigeria, Papua New Guinea, and the United States.

Critical Accounting Policies and Estimates

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company will adopt SFAS No. 157 effective January 1, 2007. The adoption of SFAS No. 157 will not have a material impact on the Company’s consolidated results of operations and financial condition.

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, 2005.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

We had approximately $38,251,000 in cash and cash equivalents in the form of money market instruments as of September 30, 2006. This compares to approximately $69,663,000 in cash and cash equivalents at December 31, 2005. 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.

We expect to conduct a portion of our business in currencies other than the United States 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 United States 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 United States dollar for their functional currency. Monetary assets and liabilities are translated into United States 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 United States 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 U.S. $11,202,000 at September 30, 2006. 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 United States dollar to the Australian dollar was $0.75 and $0.76 at September 30, 2006 and September 30, 2005, respectively.

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, 2006 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 has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2006 that has 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 may be involved in lawsuits from time to time 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 1A. Risk Factors

There have been no material changes to the risk factors described in our annual report on Form 10-K for the year ended December 31, 2005 other than modifications to the following risk factor.

We will need to obtain funds from additional financings or other sources for our business activities. If we do not receive these funds, we would need to reduce, delay or eliminate some of our expenditures.

We have sustained recurring losses and negative cash flows from operations. Over the periods presented in the accompanying financial statements, our growth has been funded through a combination of equity and convertible debt financings, and the sale of certain assets. As of September 30, 2006, we had approximately $38,251,000 of cash and cash equivalents available to fund operations. We review cash flow forecasts and budgets periodically. We believe that we currently have sufficient cash and financing capabilities to meet our funding requirements over the next year. However, we have experienced, and continue to experience, negative operating margins and negative cash flows from operations, as well as an ongoing requirement for substantial additional capital investment related to construction of GTL or CTL plants and other activities, including exploration and production of energy assets and research and development programs in which we participate.

We expect that we will need to raise substantial additional capital to accomplish our business plan over the next several years. In addition, we may wish to selectively pursue equity partnerships in certain gas or coal monetization projects in order to achieve operating efficiencies. We expect to seek to obtain additional funding through debt or equity financing in the capital markets, joint ventures, license agreements and other strategic alliances, as well as various other financing arrangements. 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 the 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. There can be no assurance as to the availability or terms upon which such financing and capital might be available.

If adequate funds are not available, we may be required to reduce, delay or eliminate expenditures for our GTL and CTL plant development and other activities, 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. The transactions outlined above may not be available to us when needed or on terms acceptable or favorable to us.

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

Unregistered Sales of Equity Securities.

Not applicable.

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, 2006. The table reflects our repurchase of 3,067 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, 2006.

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, 2006 – July 31, 2006	881	$6.07	-	-
August 1, 2006 – August 31, 2006	2,645	$4.56	-	-
September 1, 2006 – September 30, 2006	3,067	$4.69	-	-
Total	6,593	$4.81	-	-

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.

Robert A. Day resigned from the Board of Directors in September 2006

Item 6. Exhibits.

*3.1	Bylaws of the Company (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 filed with the Securities and Exchange Commission on March 7, 2006 (File No. 0-21911)).
*3.1.1	Amendment to the Bylaws of the Company (incorporated by reference to Exhibit 3.3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 filed with the Securities and Exchange Commission on March 7, 2006 (File No. 0-21911))
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

____________

* Incorporated by reference as indicated

+ Compensatory plan or arrangement

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 8, 2006	By:	/s/ John B. Holmes, Jr.
		John B. Holmes, Jr. Chief Executive Officer and President
Date: November 8, 2006	By:	/s/ Greg G. Jenkins
		Greg G. Jenkins Executive Vice President of Finance and Business Development and Chief Financial Officer (Principal Financial Officer)

INDEX TO EXHIBITS

No.

Description of Exhibit

*3.1	Bylaws of the Company (incorporated by reference to Exhibit 3.3 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 filed with the Securities and Exchange Commission on March 7, 2006 (File No. 0-21911)).
*3.1.1	Amendment to the Bylaws of the Company (incorporated by reference to Exhibit 3.3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005 filed with the Securities and Exchange Commission on March 7, 2006 (File No. 0-21911))
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

* Incorporated by reference as indicated

+ Compensatory plan or arrangement

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Sooner Inactive 10-Q2006 Q3 Quarterly report

Content analysis