UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2008

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

For the transition period from to

Commission file number: 001-32628

STORM CAT ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

British Columbia		06-1762942
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

1125 17th Street, Suite 2310
Denver, Colorado		80202
(Address of principal executive offices)		(Zip Code)

(registrant’s telephone number, including area code): (303) 991-5070

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. x Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, or an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

			Smaller reporting
Large accelerated filer o	Accelerated filer x	Non-accelerated filer o	company o
		(Do not check if smaller reporting company)

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

As of August 8, 2008, there were 81,278,549 common shares outstanding.

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TABLE OF CONTENTS PART I—FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Item 4. Controls and Procedures

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

Item 1A. Risk Factors

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

Item 6. Exhibits

Signatures

Certification of CEO Pursuant to Section 302

Certification of CFO Pursuant to Section 302

Certification of CEO Pursuant to 18 U.S.C. Section 1350

Certification of CFO Pursuant to 18 U.S.C. Section 1350

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

STORM CAT ENERGY CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007

Consolidated Statements of Operations for the three and six months ended June 30, 2008 and 2007

Consolidated Statements of Shareholders’ Equity and Comprehensive Loss for the six months ended June 30, 2008

Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2007

Notes to Consolidated Financial Statements

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STORM CAT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(stated in thousands of U.S. dollars, except share amounts)

	June 30,			December 31,
	2008			2007
	(Unaudited)			(Audited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,068		$	1,133
Accounts receivable:
Joint interest billing	3,053			1,701
Revenue receivable	3,792			2,444
Fair value of derivative instruments	—			1,760
Prepaid costs and other current assets	2,224			2,941
Total current assets	11,137			9,979
PROPERTY AND EQUIPMENT (full cost method), at cost:
Oil and gas properties:
Unproved properties	57,043			51,438
Proved properties	100,283			78,096
Less accumulated depreciation, depletion, and amortization	(17,038		)	(12,228		)
Oil and gas properties, net	140,288			117,306
Other property	1,149			1,180
Less accumulated depreciation	(926		)	(778		)
Total other property, net	223			402
Total property and equipment, net	140,511			117,708
OTHER NON-CURRENT ASSETS:
Restricted cash	168			685
Debt issuance costs, net of accumulated amortization of $2,686 and $1,988, respectively	2,963			3,435
Accounts receivable long-term	—			759
Total other non-current assets	3,131			4,879
Total assets	$	154,779		$	132,566

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	10,588		$	5,825
Revenue payable	3,191			1,678
Accrued and other liabilities	8,090			4,131
Interest payable	—			12
Share-based payments liability	609			394
Fair value of derivative instruments	11,708			—
Bank Debt	64,625			—
Total current liabilities	98,811			12,040
NON-CURRENT LIABILITIES:
Bank Debt				43,056
Ad valorem taxes payable	852			—
Asset retirement obligation	1,844			1,713
Fair value of derivative instruments	2,839			183
Convertible notes payable	50,195			50,195
Total non-current liabilities	55,730			95,147
Total liabilities	154,541			107,187

Commitments and Contingencies (Notes 2 and 11)

SHAREHOLDERS’ EQUITY:
Common shares, without par value, unlimited authorized, issued and outstanding: 81,278,549 at June 30, 2008 and 81,087,320 at December 31, 2007	69,834			69,834
Additional paid-in capital	6,028			5,640
Accumulated other comprehensive income (loss)	(9,709		)	7,483
Accumulated deficit	(65,915		)	(57,578		)
Total shareholders’ equity	238			25,379
Total liabilities and shareholders’ equity	$	154,779		$	132,566

The accompanying notes are an integral part of these financial statements.

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STORM CAT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(stated in thousands of U.S. dollars, except share and per share amounts)

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
NATURAL GAS REVENUE	$	6,550		$	3,668		$	12,567		$	7,580

OPERATING EXPENSES:
Gathering and transportation	1,340			398			2,143			958
Lease operating expenses	2,407			1,256			4,810			2,159
General and administrative	1,819			3,491			3,536			6,152
Depreciation, depletion, amortization and accretion of asset retirement obligation	2,856			1,879			5,018			3,513
Total operating expenses	8,422			7,024			15,507			12,782
Operating loss	(1,872		)	(3,356		)	(2,940		)	(5,202		)

OTHER INCOME (EXPENSE):
Interest expense	(2,462		)	(1,519		)	(4,731		)	(2,148		)
Interest and other miscellaneous income	52			101			32			133
Amortization of deferred financing costs	(411		)	—			(698		)	—
Total other income (expense)	(2,821		)	(1,418		)	(5,397		)	(2,015		)

Loss before taxes	(4,693		)	(4,774		)	(8,337		)	(7,217		)

Recovery of future income tax asset from flow-through shares	—			182			—			1,278

NET LOSS	$	(4,693	)	$	(4,592	)	$	(8,337	)	$	(5,939	)
Basic and diluted loss per share	$	(0.06	)	$	(0.06	)	$	(0.10	)	$	(0.07	)
Weighted average number of shares outstanding	81,214,884			81,045,122			81,151,150			80,816,505

The accompanying notes are an integral part of these financial statements.

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STORM CAT ENERGY CORPORATION

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE LOSS

FOR THE SIX MONTHS ENDED JUNE 30, 2008

(Unaudited)

(stated in thousands of U.S. dollars, except share amounts)

	Common Stock			Additional Paid-in		Other Comprehensive			Accumulated			Total Shareholders’
	Shares	Amount		Capital		Income (Loss)			Deficit			Equity
BALANCE AT DECEMBER 31, 2007	81,087,320	$	69,834	$	5,640	$	7,483		$	(57,578	)	$	25,379
Restricted Share Units vested	191,229	—		—		—			—			—
Share-based payments	—	—		388		—			—			388
Net loss	—	—		—		—			(8,337		)	(8,337		)
Net change in foreign currency translation and fair value of derivative instruments	—	—		—		(17,192		)	—			(17,192		)
Other comprehensive loss (Note 10)	—	—		—		—			—			(25,529		)
BALANCE AT JUNE 30, 2008	81,278,549	$	69,834	$	6,028	$	(9,709	)	$	(65,915	)	$	238

The accompanying notes are an integral part of these financial statements.

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STORM CAT ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(stated in thousands of U.S. dollars)

	Six Months Ended June 30,
	2008			2007
Cash flows from operating activities:
Net loss	$	(8,337	)	$	(5,939	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Recovery of future income tax asset from flow-through shares	—			(1,252		)
Share-based payments	625			1,161
Depreciation, depletion, amortization and accretion of asset retirement obligation	5,018			3,521
Amortization of debt issuance costs	698			—
Changes in operating assets and liabilities:
Accounts receivable	(2,694		)	(761		)
Other current assets	700			381
Accounts payable	257			(2,674		)
Accrued interest and other current liabilities	5,103			(1,461		)
Net cash provided by (used in) operating activities	1,370			(7,024		)
Cash flows from investing activities:
Restricted cash	1,264			(8		)
Capital expenditures - oil and gas properties	(22,801		)	(32,386		)
Capital expenditures - other assets	21			(23		)
Net cash used in investing activities	(21,516		)	(32,417		)
Cash flows from financing activities:
Issuance of common stock	—			914
Debt issuance costs	—			(3,556		)
Proceeds from (repayment of) bank debt	21,569			(13,278		)
Proceeds from convertible notes payable	—			50,194
Net cash provided by financing activities	21,569			34,274
Effect of exchange rate changes on cash	(488		)	883
Net decrease in cash and cash equivalents	935			(4,284		)
Cash and cash equivalents at beginning of period	1,133			5,299
Cash and cash equivalents at end of period	$	2,068		$	1,015

Supplemental disclosure of cash flow information:
Cash paid for interest	$	5,224		$	2,449
Supplemental disclosure of non-cash investing and financing activities:
Capital accruals and asset additions	$	13,566		$	6,700
Increase in asset retirement obligation	$	89		$	(284	)
Change in fair value derivatives	$	(16,123	)	$	(1,360	)

The accompanying notes are an integral part of these financial statements.

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STORM CAT ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Storm Cat Energy Corporation, together with its consolidated subsidiaries (“Storm Cat” or the “Company”), is an independent oil and gas company focused primarily on the pursuit, exploration and development of large unconventional gas reserves from fractured shales, coal beds and tight sand formations and, secondarily, from conventional formations. We have producing properties in Wyoming’s Powder River Basin (“PRB”) and in Arkansas’ Arkoma Basin (“Fayetteville Shale”). Our primary exploration and development acreage is located in the United States and Canada. Unless the context otherwise requires, the terms “Storm Cat,” we”, “us,” “our” and the “Company”, when used herein refer to Storm Cat Energy Corporation, together with its operating subsidiaries. When the context requires, we refer to these entities separately.

NOTE 1. BASIS OF PRESENTATION

The accompanying Consolidated Financial Statements of Storm Cat, with the exception of the Consolidated Balance Sheet at December 31, 2007, have not been audited by independent public accountants and have been prepared in accordance with generally accepted accounting principals (“GAAP”) in the U.S. In the opinion of management, the accompanying financial statements reflect all adjustments necessary to present fairly our financial position at June 30, 2008, our loss for the three and six months ended June 30, 2008 and 2007 and cash flows for the six months ended June 30, 2008 and 2007. All such adjustments are of a normal recurring nature. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they should be read along with the Consolidated Financial Statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

NOTE 2. LIQUIDITY

At June 30, 2008, the Company was not in compliance with certain of the financial and minimum average daily production covenants set forth in the Amended Credit Agreement (as defined in Note 6 below). It is likely that we will not be in compliance with the covenants for the next twelve months. Accordingly, the $64.6 million outstanding under the Credit Facility (as defined in Note 6 below) at June 30, 2008 has been classified as a current liability in the accompanying Consolidated Balance Sheet.

The Company has a working capital deficit of $87.7 million at June 30, 2008. This compares to a deficit in working capital of $2.0 million at December 31, 2007 and $12.7 million at March 31, 2008. Reclassification of $64.6 million outstanding under our Credit Facility to current liabilities is the primary reason for the large increase in our working capital deficit.

The Company is considering various alternatives to remedy the noncompliance with the covenants set forth in the Amended Credit Agreement, the working capital deficit, and to provide funding for operations and future capital spending, including the possible sale of assets, amendment of the Amended Credit Agreement, or raising additional equity capital.

NOTE 3. SIGNIFICANT ACCOUNTING POLICIES

Please see our Annual Report on Form 10-K for the year ended December 31, 2007 for a comprehensive listing of our accounting policies.

Foreign Currency

We are exposed to fluctuations in foreign currencies, primarily through our operations in Canada. We monitor this exposure but have not entered into any hedging arrangements to protect from currency fluctuations. As of June 30, 2008, $2.07 million U.S. dollar equivalent, or 100% of our cash, was held in U.S. dollars.

For the six months ended June 30, 2008, balances in the Consolidated Statements of Operations were converted from Canadian to U.S. dollars at a weighted average exchange rate of $0.9932 CDN to $1.00 U.S., and Consolidated Balance Sheet balances were converted at a rate of $0.9900 CDN to $1.00 U.S. based on the exchange rate on June 30, 2008.

For the six months ended June 30, 2007, balances in the Consolidated Statements of Operations were converted from Canadian to U.S. dollars at a weighted average exchange rate of $0.8819 CDN to $1.00 U.S.

Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157 “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. On February 12, 2008, the FASB issued Staff Position No. FAS 157-2 (“FSP 157-2”) which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).

On January 1, 2008 we elected to implement SFAS 157 with the one-year deferral. Given the nature of our current financial instruments, the adoption of SFAS 157 did not have a material impact on our financial position, results of operations or cash flows.

The estimated fair values of derivatives included in the Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007 are summarized below. The increase in the net derivative liability from December 31, 2007 to June 30, 2008 is primarily attributable to the effect of higher natural gas prices.

Assets and liabilities recorded at fair value in the Consolidated Balance Sheets are categorized based upon the level of judgment associated with the inputs used to measure their fair value. Hierarchical levels—defined by SFAS 157 and directly related to the amount of subjectivity associated with the inputs to fair valuation of these assets and liabilities—are as follows:

Level I—Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

Level II—Inputs (other than quoted prices included in Level I) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

Level III—Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

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	Fair Value Measurements
	June 30, 2008			December 31, 2007
In Thousands	Significant Other Observable Inputs (Level II)			Significant Other Observable Inputs (Level II)
Derivative assets:
Fixed-price natural gas commodity swaps	$	—		$	1,760
Derivative liabilities:
Fixed-price natural gas commodity swaps	(14,547		)	(183		)

Net derivative asset (liability)	$	(14,547	)	$	1,577

NOTE 4. DERIVATIVE FINANCIAL INSTRUMENTS

Natural Gas Commodity Hedges

Realized gains or losses from the settlement of natural gas derivative contracts are reported as natural gas revenues in the Consolidated Statements of Operations. Changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in accumulated other comprehensive loss in the Consolidated Balance Sheets. Any change in fair value resulting from ineffectiveness is recognized currently in derivative loss in the Consolidated Statements of Operations.

As of June 30, 2008, all natural gas derivative instruments qualified as cash flow hedges for accounting purposes under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” We anticipate that all forecasted transactions will occur by the end of their originally specified periods. All contracts are entered into for other than trading purposes.

Our natural gas hedges are indexed to the first of the month CIG index. The CIG index is the same index that determines the actual natural gas revenue received by us for our PRB production. Therefore, the hedges are highly correlated to changes in cash flows from natural gas sales.

To mitigate a portion of the potential exposure to adverse market changes, we have entered into various derivative contracts. As of June 30, 2008, we had hedge contracts in place through December 2010 for a total of approximately 8,292,800 MMBtu of anticipated production from our PRB properties (see Item 3. “Quantitative and Qualitative Disclosures About Market Risk” for a detailed listing of our commodity swaps).

We recognized a $17.7 million loss on the fair value of our derivative contracts in the first six months of 2008, and $0.5 million gain for the same period in 2007. The table below summarizes derivative instrument gain (loss) activity:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
Derivative Instrument Gain (Loss) Activity	2008			2007		2008			2007
In Thousands
Derivative contract settlements reflected in natural gas revenue	$	(1,643	)	$	1,395	$	(1,527	)	$	1,820
Derivative contracts reflected in other comprehensive loss	$	(8,586	)	$	231	$	(16,123	)	$	(1,360	)
Total derivative instrument gain (loss)	$	(10,229	)	$	1,626	$	(17,650	)	$	460

NOTE 5. OIL AND GAS PROPERTIES

Accounting for Oil and Gas Properties

We follow the full cost method of accounting for oil and gas operations whereby all costs of exploring for and developing oil and gas reserves are initially capitalized on a country-by-country (cost center) basis. Capitalized costs, less estimated salvage value, are depleted using the units-of-production method whereby historical costs and future development costs are amortized over the total estimated proved reserves. Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. These costs are assessed periodically to ascertain whether impairment has occurred (i.e., “impairment tests”). Please refer

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to Regulation S-X Rule 4-10(c)(4) for full discussion regarding impairment tests. There were no impairment charges in either the first six months of 2008 or 2007.

In the first six months of 2008, we invested $1.8 million in lease rentals, geophysical and geological activities and capitalized interest. During this period, we also invested $25.8 million in various capital projects as follows:

·		in the PRB, we invested a total of $15.7 million for drilling, completion, compression, pipeline expenditures and acquisitions;

·		in Fayetteville, we invested $9.4 million in capital for drilling and completion; and

·		in Elk Valley, Canada, we invested $0.7 million.

Asset Retirement Obligation

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of natural gas properties is recorded when the assets are placed into service, generally through acquisition or completion of a well. The net estimated costs are discounted to present values using a risk-adjusted rate over the estimated economic life of the properties. Such costs are capitalized as part of the basis of the related asset and are depleted as part of the applicable full cost pool. The associated liability is recorded initially as a long-term liability. Subsequent adjustments to the initial asset and liability are recorded to reflect revisions to estimated future cash flow requirements. In addition, the liability is adjusted to reflect accretion expense as well as settlements during the period.

A reconciliation of the changes in the asset retirement obligation for the six months ended June 30, 2008 and 2007, respectively, is as follows:

	Six Months Ended
	June 30,
In Thousands	2008			2007
Asset retirement obligation at January 1	$	1,713		$	1,871
Adjustment for revision of estimated life and interest rate in the Powder River Basin	(1		)	(400		)
Additional liabilities incurred	90			118
Accretion expense	51			98
Foreign currency translation	(9		)	34
Asset retirement obligation at June 30	$	1,844		$	1,721

NOTE 6. BANK CREDIT FACILITY

On December 27, 2007, Storm Cat Energy (USA) Corporation (“Storm Cat (USA)”), a wholly owned subsidiary of Storm Cat, entered into that certain Credit Agreement, dated December 27, 2007, by and among Storm Cat (USA), Wells Fargo Foothill LLC (“Wells Fargo”), as Agent, and the additional lenders party thereto (the “Credit Agreement”), which provides for certain credit facilities (the “Credit Facility”). Additionally, Storm Cat agreed to guarantee the obligations of Storm Cat (USA) under the Credit Facility. On April 17, 2008, Storm Cat, Storm Cat (USA), and their subsidiaries entered into a First Amendment to Credit Agreement (the “Amendment” and the Credit Agreement as amended by the Amendment, the “Amended Credit Agreement”). The Credit Facility consists of a term loan facility and a revolving facility. The Amended Credit Agreement provides for a semi-annual evaluation of such amount, determined based on Storm Cat’s oil and natural gas reserves.

As of June 30, 2008, the Credit Facility consists of a term loan facility in an aggregate principal amount of $40.0 million and a revolving facility in an aggregate principal amount of $25.0 million. Storm Cat’s borrowing base under the Credit Facility was $65.0 million as of June 30, 2008. As of June 30, 2008, we had a total of $64.6 million outstanding pursuant to the Amended Credit Agreement, which consisted of $40.0 million on the term loan facility and $24.6 million on the revolving facility.

Storm Cat and the subsidiary guarantors have also executed and delivered certain other related agreements and documents pursuant to the Credit Facility, including a guaranty agreement, security and pledge agreement and mortgages. The obligations of Storm Cat, Storm Cat (USA), and their subsidiaries under the Credit Facility are secured by a first priority security interest in favor of Wells Fargo for the benefit of the lenders, in Storm Cat and its subsidiaries’ material tangible and intangible assets, and proved reserves, among other things.

Each loan under the Credit Facility bears interest at a base rate or Eurodollar rate, as requested by Storm Cat, plus an applicable percentage based on Storm Cat’s usage of the facility. The applicable margin above the base rate and the Eurodollar rate for the term loan is 6.75% and 8.00%, respectively. The applicable margin above the base rate and the Eurodollar rate for the revolving Credit Facility ranges from 0.75% to 1.25% and 2.00% and 2.50%, respectively, in each case depending on our usage under the borrowing base. Interest on funds drawn will be paid monthly, except that interest on loans based on the Eurodollar rate will be payable at the end of each Eurodollar interest period of one, two, three or six months, and in any event at least every three months. As a result of the defaults described below, the lenders may increase the interest rate accruing on the outstanding loans by 2.0% above the rate otherwise applicable as default interest.

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The Credit Facility matures on September 27, 2011, or December 27, 2012 in the event the Convertible Notes (defined below) are entirely converted into equity, with no remaining cash payment obligations, or are refinanced with a maturity date not earlier than June 27, 2013.

As of June 30, 2008, the Company was not in compliance with the financial and minimum average daily production covenants set forth in the Amended Credit Agreement. The Company is currently discussing a possible wavier or amendment to the Amended Credit Agreement with its lenders. However, absent a waiver or an amendment to the financial covenants or repayment or refinancing of the Credit Facility, it is likely that the Company will not be in compliance with the covenants for the next twelve months. Our lenders could accelerate our indebtedness under the Credit Facility and exercise any available rights and remedies. Our lenders could prevent us from paying interest to the holders of our Convertible Notes. The failure to make our scheduled interest payments or the acceleration of the indebtedness under the Amended Credit Agreement would result in a default of our Convertible Notes. Accordingly, the $64.6 million outstanding under the Credit Facility at June 30, 2008 is classified as a current liability in the accompanying Consolidated Balance Sheet at June 30, 2008.

NOTE 7. CONVERTIBLE NOTES

On January 19, 2007, we entered into a Series A Note Purchase Agreement for the private placement of Series A Notes in a total aggregate principal amount of $18.5 million and a Series B Note Purchase Agreement for the private placement the Series B Notes (together with the Series A Notes, the “Convertible Notes”) in a total aggregate principal amount of $31.7 million. The Convertible Notes were bifurcated into two series because a shareholder vote was required for issuance of any Convertible Notes above the amount issued under the Series A Notes. The Series A Notes and the Series B Notes are convertible into our common shares at a price of $1.17 per share, as may be adjusted in accordance with the terms of the Series A Notes or the Series B Notes (as applicable), and we may require the conversion of the Series A Notes or the Series B Notes (as applicable) at any time 18 months after the closing date of the applicable issuance that our common shares trade above $2.05, as may be adjusted, for 20 days within a period of 30 consecutive trading days. On the day of the Series A Note Purchase Agreement and the Series B Note Purchase Agreement, the $1.17 conversion price was at premium to our closing stock price of $1.00.

On January 30, 2007, we closed the private placement of the Series A Notes. The Series A Notes mature on March 31, 2012, unless earlier converted, redeemed or repurchased. The Series A Notes bear interest at a rate of 9.25% per annum, commencing on January 30, 2007. Interest on the Series A Notes is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year, beginning on June 30, 2007.

On March 29, 2007 our shareholders authorized the issuance of the underlying shares of the Series B Notes and on March 30, 2007, we closed the private placement of $31.7 million of Series B Notes. The Series B Notes mature on March 31, 2012, unless earlier converted, redeemed or repurchased. The Series B Notes bear interest at a rate of 9.25% per annum, commencing on March 30, 2007. Interest on the Series B Notes is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year, beginning on June 30, 2007.

As part of the private placements, we entered into a registration rights agreement (the “Registration Rights Agreement”) with the investors requiring us to file with the Securities and Exchange Commission (the “SEC”) registration statements covering the common shares issuable upon conversion of the Series A Notes and the Series B Notes. We have fulfilled our obligations under the Registration Rights Agreement to have an effective registration covering the shares that are issuable upon conversion of the Convertible Notes with respect to all of the shares underlying the Convertible Notes, with the exception of 123,932 common shares issuable upon conversion of Series B Notes held by certain of our officers and directors. The registration statements and the related prospectuses can be accessed via the SEC website at www.sec.gov.

NOTE 8. SHAREHOLDERS’ EQUITY

Outstanding Share Data

We have an unlimited number of authorized common shares, without par value, and an unlimited number of preferred shares which may be issued in series and with preferences as determined by our Board of Directors. As of the filing of this report no preferred shares had been issued.

At June 30, 2008, 81,278,549 common shares were issued and outstanding, 6,452,000 common share options outstanding and reserved for issuance under our Amended and Restated Share Option Plan (the “Amended Option Plan”) and 156,667 unvested restricted stock units (“RSUs”) outstanding under our Restricted Share Unit Plan. There were also 15,841,880 common shares reserved for issuance upon conversion of the Series A Notes and 27,059,829 common shares reserved for issuance upon conversion of the Series B Notes.

Basic and Diluted Loss per Share

Basic loss per share is computed by dividing the net loss available to common shareholders by the weighted average number of common shares outstanding during the period. The shares represented by vested RSUs issued to date are included in the calculation of the weighted average basic common shares outstanding. Diluted loss per share is calculated giving effect to the potential dilution that would occur if vested stock options, RSUs and stock purchase warrants were exercised and the Convertible Notes were converted to common shares. The dilutive effect of options, RSUs, warrants and the Convertible Notes is computed by application of the treasury stock method which assumes that proceeds from the exercise of in-the-money options and warrants would be used to repurchase common shares at average market prices during the period. Diluted amounts are not presented when the effects of the computations

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are anti-dilutive due to net losses incurred. Accordingly, there is no difference in the amounts presented for basic and diluted loss per share for the quarters ended June 30, 2008 and 2007. Listed below is a table showing the potentially dilutive shares outstanding as of June 30, 2008 and 2007 which have been excluded from the diluted earnings per share calculation.

	June 30,
	2008	2007
Potentially Dilutive Shares Outstanding
Options	6,452,000	4,760,000
Unvested RSUs	156,667	122,500
Series A Notes	15,841,880	15,841,880
Series B Notes	27,059,829	27,059,829
Warrants	—	4,649,569
Total potentially dilutive shares outstanding	49,510,376	52,433,778

Options and RSUs Issued and Outstanding

The Amended Option Plan and the Restricted Share Unit Plan (together, the “Plans”), both approved by our shareholders on June 21, 2007, authorizes the granting of incentive and nonqualified options to purchase up to 10,000,000 common shares in the aggregate. The Plans are administered by the Board of Directors which determines the terms pursuant to which any option is granted. The Plans provide that upon a change in control, options then outstanding will immediately vest and we will take such actions as are necessary to make all shares subject to options immediately salable and transferable.

Of the 10,000,000 shares authorized for issuance in the aggregate under the Plans, 9,945,620 shares have been granted and 1,506,974 shares have been forfeited, leaving a total of 1,561,354 shares available for issuance as of June 30, 2008. Below is a reconciliation of our remaining shares available to grant at the end of the second quarter 2008:

	June 30, 2008
Common Shares Available to Grant
Common shares in treasury available to grant	10,000,000
Options granted	(9,352,000	)
Options forfeited	1,445,000
RSUs granted	(593,620	)
RSUs forfeited	61,974
Common shares available to grant as of June 30, 2008	1,561,354

	Number of Shares		Weighted Average Exercise Price (1)
Option Activity
Options outstanding at December 31, 2007	4,550,000		$	1.91
Options granted	1,917,000		$	0.73
Options exercised	—		$	—
Options expired/cancelled	(15,000	)	$	—
Options outstanding at June 30, 2008	6,452,000		$	1.56

Options exercisable at June 30, 2008	4,316,659		$	1.29

(1)Exercise price is in Canadian dollars.

	Number of Shares
RSU Activity
RSUs unvested at December 31, 2007	95,000
RSUs granted	304,870
RSUs vested	(191,229	)
RSUs expired/cancelled	(51,974	)
RSUs unvested at June 30, 2008	156,667

Share Based Payments Expensed for the six months ended June 2008 and 2007

SFAS No. 123(R), paragraph B129, "Equity Instruments with Exercise Prices Denominated in a Foreign Currency" requires that all equity instruments with exercise prices denominated in a currency other than the currency of the market in which the underlying equity instrument primarily trades be accounted for as liabilities. Because we have granted options that are priced in Canadian dollars, and our stock is primarily traded on the American Stock Exchange ("AMEX"), the liability method is required relative to all U.S. employees. We employ the following methods in recording share-based payments.

• The liability method to account for options granted to U.S. employees in Canadian dollars. Under this method, we record a liability for vested options equal to the value of such vested options as calculated by the Black-Scholes model using the option exercise price and the fair value per share of the common stock underlying the option as of the measurement date.

• The equity method to account for options granted to Canadian employees and options granted to U.S. employees in U.S. dollars. We calculate the expense under this method based on the Black-Scholes value of the option at the date of the grant. This expense is recorded in equal amounts as the options vest; typically over two years.

The fair value of share-based payments are expensed, with a corresponding increase to additional paid-in capital for the equity method, or the share-based payment liability for the liability method. Upon exercise of stock options, the consideration paid upon exercise is recorded as additional value of common shares and the amount previously recognized in additional paid-in capital is reclassified to common shares.

Both of the aforementioned methods of calculating share-based payments require us to make several estimates including when stock options might be exercised, the stock price volatility, forfeiture rates, and the model used to calculate value. The timing for exercise of options is outside our control and depends upon a variety of factors including the market value our common shares and the financial objectives of the holders of the options, among other factors. We calculate volatility using historical data; however, future volatility is inherently uncertain.

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The following table summarizes our share-based payments expense under each method:

	Six Months Ended
	June 30,
In Thousands	2008		2007
Share-based payments expense under the liability method	$	205	$	—
Share-based payments expense under the equity method	412		1,189
Share-based payments expense	$	617	$	1,189

Stock Activity During the Quarter

304,870 restricted stock units and 115,000 stock options were issued to directors, employees and consultants. Grants to directors were in accordance with the Company’s Director Compensation Policy. Employee and consultant grants were for services rendered during the current year.

NOTE 9. INCOME TAXES

The income tax benefit realized in the first six months of 2007 was $1.3 million. This is a tax benefit that is passed on to our flow-through shareholders. In order to have this tax benefit, the flow-through shareholders pay a premium above market for their shares. This premium is reduced in equity and recorded as a liability. As the capital obligation is satisfied, the liability is reduced and an income tax benefit is recorded to the income statement. The liability no longer exists and no tax benefit was recognized in the first six months of 2008.

NOTE 10. OTHER COMPREHENSIVE LOSS

Comprehensive earnings (loss) is a term used to refer to net earnings plus other comprehensive income (loss). Other comprehensive income (loss) is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders’ equity instead of net earnings. Items included in other comprehensive loss for the three and six months ended June 30, 2008 and 2007 are foreign currency gains (losses) related to the translation of the assets and liabilities of our Canadian operations and unrealized gains (losses) related to the changes in the fair value of derivative instruments designated as cash flow hedges.

Comprehensive loss for the three months and six months ended June 30, 2008 and 2007, respectively, is reflected in the table below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Net loss	$	(4,694	)	$	(4,592	)	$	(8,337	)	$	(5,939	)
Effects of currency translation	413			2,654			(1,069		)	2,966
Change in fair value of derivatives	(8,586		)	231			(16,123		)	(1,360		)
Comprehensive loss	$	(12,867	)	$	(1,707	)	$	(25,529	)	$	(4,333	)

NOTE 11. SALES, TRANSPORTATION AND GATHERING COMMITMENTS

Sales Commitments

We had no forward sales contracts at June 30, 2008.

Firm Transportation Service Agreements

We have a firm transportation agreement in place through April 11, 2013 to transport gas from Cheyenne Plains to ANR PEPL (Oklahoma). The agreement obligates us to pay $0.34 per Dth on 2,000 Dth/D or approximately $20,000 per month. The firm commitment payment is offset by any charges for volumes shipped on the Cheyenne Plains pipeline to the ANR PEPL (Oklahoma) delivery hub. We released our 2,000 Dth/D capacity commitment for a period of eight months (from March 2008 through October 2008) at the full volume commitment for $0.14 per Dth.

We also have a firm transportation agreement with an unaffiliated third party that expires November 30, 2013. The agreement requires us to pay $0.15 per Dth on 100% load basis of 4,000 Dth/D. Gas is received at Glenrock, Wyoming and delivered to the Dullknife hub in Wyoming. We are currently meeting the volume commitment relative to this agreement.

Gathering Commitments

We have a fee-based gas gathering and compression services agreement with an unrelated third party for the provision of field

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gathering, treating, compression and high pressure transport of natural gas to be produced from our Fayetteville Shale project. We are obligated to deliver sufficient volumes to generate fees totaling $19.0 million over a four-year period which began in April 2008.

NOTE 12. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES ACCOUNTING PRINCIPLES

These financial statements have been prepared in accordance with U.S. GAAP which differ in certain respects with those principles and practices that we would have followed had our financial statements been prepared in accordance with Canadian GAAP.

Differences between U.S. GAAP and Canadian GAAP impact us as follows:

Oil and Gas Properties

Canadian GAAP requires recognition and measurement processes to assess impairment of oil and gas properties using estimates of future oil and gas prices and costs plus the cost of unproved properties that have been excluded from the depletion calculation. In the measurement of the impairment, the future net cash flows of a cost center’s proved and probable reserves are discounted using a risk-free interest rate. For U.S. GAAP purposes, future net cash flows from proved reserves using period-end, non-escalated prices and costs, are discounted to present value at 10% per annum and compared to the carrying value of oil and gas properties.

Comprehensive Loss

U.S. GAAP requires disclosure of comprehensive loss which includes net loss under U.S. GAAP plus the change in cumulative translation adjustment and the unrealized gain or loss on future volumes we have hedged. We have volumes hedged through December 2010 creating a current difference between U.S. and Canadian GAAP because the hedge gain or loss amounts are recognized on a current basis in the statement of operations under Canadian GAAP. The concept of comprehensive loss did not come into effect until fiscal years beginning on or after October 1, 2006 for Canadian GAAP.

Flow-Through Shares

U.S. GAAP requires the stated capital on flow-through share issuances to be equal to the estimated fair market value of the shares on the date of issue. The difference between the gross proceeds received on the issuance of the shares and the estimated fair market value of the shares is recorded as a liability (the “Premium”) until the renunciation of expenditures has occurred. The full renunciation has occurred as of June 30, 2008 and there is no flow-through share liability.

Under Canadian GAAP, the gross proceeds received on flow-through share issuances are initially recorded as share capital. When the expenditures are incurred and the tax deductions are renounced to subscribers, Canadian GAAP requires that the stated capital be reduced and that income tax benefits be recorded for the estimated future income taxes that were renounced. Under U.S. GAAP, the initial liability is adjusted to a deferred income tax liability and as a result of the recalculation of our deferred taxes, this amount is ultimately recorded as an income tax benefit.

Share-Based Payments

U.S. GAAP, under SFAS No. 123(R), paragraph B129, “Equity Instruments with Exercise Prices Denominated in a Foreign Currency,” requires that all equity instruments with exercise prices denominated in a currency other than the currency of the market in which the underlying equity instrument primarily trades be accounted for as liabilities. This is not applicable under Canadian GAAP.

The impact of the above differences on the financial statements is as follows:

	Six Months Ended June 30,
Statement of Operations	2008			2007
dollars in thousands, except per share
Net loss for the year per U.S. GAAP	$	(8,337	)	$	(5,939	)
Adjustment for depletion	(1,096		)	—
Adjustments for foreign exchange gain (loss)	(488		)	883
Difference in recovery of future income tax asset	—			1,278
Net loss for the year per Canadian GAAP	$	(9,921	)	$	(3,778	)
Basic and diluted loss per share per Canadian GAAP	$	(0.12	)	$	(0.05	)
Weighted average number of shares outstanding per U.S. GAAP	81,151,150			80,816,505

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	June 30,			December 31,
Balance Sheet	2008			2007
dollars in thousands
Total assets per U.S. GAAP	$	154,778		$	132,566
Adjustment to asset for depletion	(1,602		)	(506		)
Adjustment to asset for impairment	25,000			25,000
Total assets per Canadian GAAP	$	178,176		$	157,060

Total liabilities per U.S. GAAP	$	154,541		$	107,187
Total liabilities per Canadian GAAP	$	154,541		$	107,187

	June 30,			December 31,
Statement of Shareholders’ Equity	2008			2007
dollars in thousands
Cumulative deficit, end of the year, per U.S. GAAP	$	(65,915	)	$	(57,578	)
Adjustment for depletion	(1,602		)	(506		)
Adjustment for impairment	25,000			25,000
Difference in recovery of future income tax asset	(2,874		)	(2,874		)
Adjustment for tax effects of flow-through share liability	6,275			6,275
Cumulative foreign exchange adjustment	4,838			5,907
Deficit, end of the year, per Canadian GAAP	(34,278		)	(23,776		)

Recovery of future income tax asset	2,874			2,874
Adjustment for flow-through share liability	—			—
Cumulative unrealized gain on hedges	(14,547		)	1,576
Adjustment for tax effects of flow-through share liability	(6,275		)	(6,275		)
Share capital, share subscriptions and contributed surplus, other comprehensive income per Canadian and U.S. GAAP	75,862			75,474
Stockholders’ equity per Canadian GAAP	$	23,636		$	49,873
Stockholders’ equity per U.S. GAAP	$	238		$	25,379

	Six Months Ended June 30,
Statement of Cash Flows	2008			2007
dollars in thousands
Cash flows from operating activities per U.S. GAAP	$	1,370		$	(7,024	)
Difference in recovery of future income tax asset	—			(1,278		)
Cash flows from operating activities per Canadian GAAP	1,370			(8,302		)

Cash flows from financing activities per U.S. GAAP	21,569			34,274
Difference in recovery of future income tax asset	—			1,278
Cash flows from financing activities per Canadian GAAP	21,569			35,552

Cash flows from investing activities per U.S. GAAP	(21,516		)	(32,417		)
Cash flows from investing activities per Canadian GAAP	(21,516		)	(32,417		)

Effect of foreign exchange on cash flows	(488		)	883
Increase (decrease) in cash per U.S. GAAP and Canadian GAAP	$	935		$	(4,284	)

NOTE 13. RELATED PARTY TRANSACTIONS

We paid $75,563 in the first six months of 2008 for legal fees to a law firm of which one of our directors is a partner. At June 30, 2008 $32,377 was outstanding and payable to this law firm.

All past and future and ongoing transactions with affiliates are and will be on terms which management believes are no less favorable than could be obtained from non-affiliated parties.

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

Unless the context otherwise requires, the terms “Storm Cat,” we”, “us,” “our” and the “Company”, when used herein refer to Storm Cat Energy Corporation, together with its operating subsidiaries. When the context requires, we refer to these entities separately. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Company should be read in conjunction with the Consolidated Financial Statements and notes related thereto included in this Quarterly Report on Form 10-Q.

Results of Operations

Comparative Results of Operations for the three and six months ended June 30, 2008 and 2007, respectively.

The following table sets forth selected operating data for the three months ended June 30, 2008 (the “Q2 2008 Period”), and the three months ended June 30, 2007 (the “Q2 2007 Period”):

	Three Months Ended June 30,
Selected Operating Data:	2008			2007		Change			% Change
Wells drilled in period	17			18		(1		)	(5.6	)%
Producing wells at end of period	464			355		109			30.7	%

Net natural gas sales volume (MMcf)	1,151.4			745.8		405.6			54.4	%

Natural gas revenue (In Thousands)
Natural gas sales	$	8,193		$	2,273	$	5,920		260.4	%
Natural gas derivatives — realized gains (losses)	$	(1,643	)	$	1,395	$	(3,038	)	(217.8	)%
Total natural gas sales	$	6,550		$	3,668	$	2,882		78.6	%

Average sales price (per Mcf) including hedging	$	5.69		$	4.92	$	0.77		15.7	%
Average sales price (per Mcf) excluding hedging	$	7.12		$	3.05	$	4.07		133.5	%

Additional expense data (per Mcf):
Gathering and transportation	$	1.16		$	0.53	$	0.63		118.9	%
Lease operating expenses	$	1.83		$	1.31	$	0.52		39.7	%
Production and ad valorem taxes	$	0.78		$	0.38	$	0.40		106.7	%
Depreciation, depletion, amortization and accretion expense	$	2.47		$	2.52	$	(0.05	)	(2.0	)%
General and administrative expense, before share-based payments	$	1.27		$	3.70	$	(2.43	)	(65.7	)%

The following table sets forth selected operating data for the six months ended June 30, 2008 (the “Fiscal 2008 Period”), and the six months ended June 30, 2007 (the “Fiscal 2007 Period”):

	Six Months Ended June 30,
Selected Operating Data:	2008			2007		Change			% Change
Wells drilled in period	33			39		(6		)	(15.4	)%
Producing wells at end of period	464			355		109			30.7	%

Net natural gas sales volume (MMcf)	2,124.6			1,408.4		716.2			50.9	%

Natural gas revenue (In Thousands)
Natural gas sales	$	14,094		$	5,760	$	8,334		144.7%
Natural gas derivatives — realized gains (losses)	$	(1,527	)	$	1,820	$	(3,347	)	(183.9	)%
Total natural gas sales	$	12,567		$	7,580	$	4,987		65.8	%

Average sales price (per Mcf) including hedging	$	5.91		$	5.38	$	0.53		9.9	%
Average sales price (per Mcf) excluding hedging	$	6.63		$	4.09	$	2.54		62.1	%

Additional expense data (per Mcf):
Gathering and transportation	$	1.01		$	0.68	$	0.33		48.5	%
Lease operating expenses	$	1.49		$	1.10	$	0.39		35.5	%
Production and ad valorem taxes	$	0.77		$	0.43	$	0.34		79.1	%
Depreciation, depletion, amortization and accretion expense	$	2.38		$	2.49	$	(0.11	)	(4.4	)%
General and administrative expense, before share-based payments	$	1.37		$	3.52	$	(2.15	)	(61.1	)%

Natural gas revenue. Natural gas sales volume for the Q2 2008 Period increased 54.4% over the Q2 2007 Period. Natural gas sales volume for the Fiscal 2008 Period increased 50.9% over the Fiscal 2007 Period. The increase in the natural gas sales volume for the Q2 2008 Period and Fiscal 2008 Period is a direct result of increased production from our successful drilling activities over the past year and from the increase in production as a result of the dewatering process associated with new wells. Increased sales volumes more than offset the natural decline in production in existing wells. Natural gas revenue for the Q2 2008 Period increased 78.6% over the Q2 2007 Period. Natural gas revenue is reported inclusive of hedging gains or losses. However, natural gas sales excluding hedging losses for the Q2 2008 Period increased 260.4% over the Q2 2007 Period. The substantial increase in natural gas sales excluding hedging losses for the Q2 2008 Period is a result of the 133.5% increase in the average sales price without hedging during the Q2 2008 Period over the Q2 2007 Period. Natural gas revenue for the Fiscal 2008 Period increased 65.8% over the Fiscal 2007 Period and natural gas revenue excluding hedging losses for the Fiscal 2008 Period increased 144.7% over the Fiscal 2007 Period. The increases in natural gas revenues for the Q2 2008 Period and Fiscal 2008 Period is also related to the increase in the natural gas sales volume and an increase in the average well head price received compared to the Q2 2007 Period and the Fiscal 2007 Period.

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Gathering and transportation expenses. Gathering and transportation expenses for the Q2 2008 Period increased 118.9% over the Q2 2007 Period. Gathering and transportation expenses for the Fiscal 2008 Period increased 48.5% over the Fiscal 2007 Period. The increase in gathering and transportation expenses for the Q2 2008 Period and the Fiscal 2008 Period is primarily related to start up transportation fees associated with our Fayetteville acreage. On April 12, 2008, the pipeline system connecting our Fayetteville acreage to the Ozark interstate pipeline became fully operational.

Lease operating expenses. On a per Mcf basis, lease operating expenses for the Q2 2008 Period increased 39.7% over the Q2 2007 Period. On a per Mcf basis, lease operating expenses for the Fiscal 2008 Period increased 35.5% over the Fiscal 2007 Period. The higher costs are attributable to the following items: 1) newly drilled wells are charged full monthly lease operating fees but have initially low production rates until they dewater in the initial three to six months of production, 2) temporary higher per well lease operating costs resulting from fuel and generator rental costs associated with new wells in our PRB development areas where the electrical infrastructure has yet to be installed, 3) temporary higher per well lease operating costs on our Sheridan and Ford Ranch areas in the PRB resulting from higher water production.

Production and ad valorem taxes. On a per Mcf basis, production and ad valorem taxes for the Q2 2008 Period increased 106.7% from the Q2 2007 Period. This increase is attributable to higher pricing in the Q2 Period as reflected in the higher average sales price per Mcf. On a per Mcf basis, production and ad valorem taxes for the Fiscal 2008 Period increased 79.1% from the Fiscal 2007 Period. This increase is attributable to higher pricing in the Fiscal 2008 Period as reflected in the higher average sales price per Mcf.

Depreciation, depletion, amortization and accretion expense. On a per Mcf basis, depreciation, depletion, amortization and accretion expense for the Q2 2008 Period decreased 2.0% from the Q2 2007 Period and decreased 4.4% for the Fiscal 2008 Period compared to the Fiscal 2007 Period. This decrease resulted from revisions to the full cost pool from changes in projected reserves as a result of pricing and reserve adds from drilling activities. The full cost pool was also reduce by the asset impairment taken in the third quarter of 2007 which reduced depletion.

General and administrative expense. We report general and administrative expense inclusive of share-based payments. On a per Mcf basis, general and administrative expense, before share-based payments, for the Q2 2008 Period decreased 65.8% from the Q2 2007 Period and decreased 61.0% for the Fiscal 2008 Period compared to the Fiscal 2007 Period. This large decrease is attributable to 1) reduction in general and administrative expenses of $1.3 million for the Q2 2008 Period compared to the Q2 2007 Period and $2.0 million for the Fiscal 2008 Period compared with the Fiscal 2007 Period and 2) increases in sales volume.

Interest expense. Interest expense increased from $1.9 million for the Q2 2007 Period to $2.5 million for the Q2 2008 Period and increased from $2.1 million for the Fiscal 2007 Period to $4.7 million for the Fiscal 2008 Period. The increased interest expense relates to additional borrowings on our Credit Facility and Convertible Notes.

Fayetteville Pipeline

On April 12, 2008, the pipeline system connecting our Fayetteville acreage to the Ozark interstate pipeline became fully operational and first sales of natural gas commenced.

PRB Acquisition

On April 15, 2008, we acquired approximately 14,000 undeveloped net acres in Sheridan County, Wyoming for approximately $5.6 million. The acquisition acreage is located in and around our current operations in the PRB. The acquisition adds an additional three years of drilling inventory in the PRB, increasing our total drilling inventory to five years (based on current development plans). The transaction was funded through the amendment to the Credit Facility.

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Subsequent Events

On August 5, 2008, we liquidated a portion of our natural gas hedges to bring our percent of production hedged into compliance with our internal hedging policy and with the covenants of the Amended Credit Agreement. 70% of our projected, developed production as of June 30, 2008 remains hedged at and average price (indexed at Colorado Interstate Gas, “CIG”) of $6.79 per Mmbtu through the end of 2008 and at an average price of $7.17 (indexed at CIG) through June 2009. We also have hedges in place from July 2009 through December 2010 at an average price of approximately $6.85 (indexed at CIG) for approximately 29% of projected production. The unwinding of the hedges netted us approximately $1.7 million of cash.

Liquidity and Capital Resources

Our primary sources of liquidity are cash provided by operating activities, borrowings under our Credit Facility (the “Amended Credit Agreement”) and Convertible Notes and sales of equity. Exploration and development activities in 2008 have been funded through cash flow from producing activities and borrowings under the Credit Facility which has a balance of $64.6 million at June 30, 2008. We have borrowed the maximum amount allowed under the Credit Facility borrowing base at June 30, 2008.

The following table summarizes our cash flows from operating, investing and financing activities for the six months ended June 30, 2008 and 2007:

	Six Months Ended
	June 30,
In Thousands	2008			2007
Net cash provided by (used in) operations	$	1,370		$	(7,024	)
Net cash used in investing activities	(21,516		)	(32,417		)
Net cash provided by financing activities	21,569			34,274
Effect of exchange rate changes on cash	(488		)	883
Net cash flow	$	935		$	(4,284	)

The increase in cash provided by operations is primarily due to an increase in our outstanding payables and liabilities since December 31, 2007. The $21.5 million of cash used in investing activities is directly related to our development and exploration programs undertaken in the first half of 2008 primarily in the Fayetteville and Powder River Basin areas. The change in cash provided by financing activities is all related to borrowing from our credit facility.

Working Capital Deficit

The Company has a working capital deficit of $87.7 million at June 30, 2008. This compares to a deficit in working capital of $2.0 million at December 31, 2007 and $12.7 million at March 31, 2008. The primary reason for the large increase in our working capital deficit is the reclassification of the $64.6 million outstanding pursuant to the Credit Facility to a current liability.

Credit Facility

As of June 30, 2008, the Credit Facility consists of a term loan facility in an aggregate principal amount of $40.0 million and a revolving facility in an aggregate principal amount of $25.0 million. Our borrowing base under the Credit Facility was $65.0 million as of June 30, 2008. The Credit Agreement provides for a semi-annual evaluation of such amount, determined based on our oil and natural gas reserves. As of June 30, 2008, we had a total of $64.6 million outstanding on the Credit Facility, which consisted of $40.0 million on the term loan facility and $24.6 million on the revolving facility.

Storm Cat and each of our subsidiaries executed and delivered certain other related agreements and documents pursuant to the Credit Facility, including a guaranty agreement, security and pledge agreement and mortgages. The obligations of Storm Cat, Storm Cat (USA), and their subsidiaries under the Credit Facility are secured by a first priority security interest in favor of Wells Fargo for the benefit of the lenders, in our and our subsidiaries’ material tangible and intangible assets, and proved reserves, among other things.

Each loan under the Credit Facility bears interest at a base rate or Eurodollar rate, as we request, plus an applicable percentage based on our usage of the facility. The applicable margin above the base rate and the Eurodollar rate for the term loan is 6.75% and 8.00%, respectively. The applicable margin above the base rate and the Eurodollar rate for the revolving Credit Facility ranges from 0.75% to 1.25% and 2.00% and 2.50%, respectively, in each case depending on our usage under the borrowing base. Interest on funds drawn will be paid monthly, except that interest on loans based on the Eurodollar rate will be payable at the end of each Eurodollar interest period of one, two, three or six months, and in any event at least every three months. As a result of the defaults described below, our lenders may increase the interest rate accruing on the outstanding loans by 2.0% above the rate otherwise applicable as default interest.

The Credit Facility matures on September 27, 2011, or December 27, 2012 in the event the Convertible Notes are entirely converted into equity, with no remaining cash payment obligations, or are refinanced with a maturity date not earlier than June 27, 2013.

As of June 30, 2008, we were not in compliance with the financial and minimum average daily production covenants set forth in the Amended Credit Agreement. We are currently discussing a possible waiver or amendment to the Amended Credit Agreement with our lenders. However, absent a waiver or an amendment to the financial covenants or repayment or refinancing of the Credit Facility, it is likely that we will not be in compliance with the covenants for the next twelve months. Accordingly, the $64.6 million outstanding under the Credit Facility at June 30, 2008 is classified as a current liability in the accompanying Consolidated Balance Sheet at June 30, 2008.

We are considering various alternatives to remedy the noncompliance with the covenants in the Amended Credit Agreement, the working capital deficit, and to provide funding for operations and future capital spending, including the possible sale of assets, amendment of the Amended Credit Agreement, refinancing the Credit Facility, or raising additional equity capital.

Accounting Pronouncements

In September 2006, the FASB issued SFAS 157, “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. On February 12, 2008, the FASB issued FSP 157-2 which proposed a one year deferral for the implementation of SFAS 157 for non-financial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually).

On January 1, 2008, we elected to implement SFAS 157 with the one-year deferral. Given the nature of our current financial instruments, the adoption of SFAS 157 did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. We are in the process of evaluating this standard with respect to the effect on our nonfinancial assets and liabilities and have not yet determined the impact that it will have on our financial statements upon full adoption in 2009.

On February 15, 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159” ). SFAS 159 establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 is effective for our financial statements issued in 2008. The adoption of SFAS 159 will have no effect on our financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”), which requires the acquiring entity in a business combination to recognize and measure all assets and liabilities assumed in the transaction and any non-controlling interest in the acquiree at fair value as of the acquisition date. SFAS 141(R) also establishes guidance for the measurement of the acquirer shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting treatment for pre-acquisition gain and loss contingencies, the treatment of acquisition related transaction costs, and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. SFAS 141(R) is effective for fiscal years beginning after

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December 15, 2008, and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. Early adoption is not permitted. SFAS 141(R) will be effective for us beginning with the 2009 fiscal year. The nature and magnitude of the specific effects of SFAS 141(R) will depend upon the nature, terms, and size of the acquisitions we consummate after the effective date.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (“SFAS 161”) which requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. Entities are required to provide enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008.

Business Risks

Please see “Risk Factors” under Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2007 and under Item 1A of Part II hereof.

Glossary of Natural Gas Terms

Please see “Glossary” under Items 1 and 2 of our Annual Report on Form 10-K for the year ended December 31, 2007.

CAUTION REGARDING FORWARD LOOKING STATEMENTS

Statements included in this Quarterly Report on Form 10-Q that are not historical facts are forward-looking statements. We use words such as “could,” “may,” “will,” “should,” “expect,” “plan,” “project,” “anticipate,” “believe,” “estimate,” “intend” and similar expressions to identify forward-looking statements.

These forward-looking statements are made based upon management’s expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

Important factors that could cause our actual results of operations or our actual financial condition to differ include, but are not necessarily limited to:

· our current non-compliance with the Amended Credit Agreement and the ability of our lenders to accelerate all of our borrowings under the Credit Facility;

· our ability to raise sufficient capital to execute our business plan through borrowing or issuing equity;

· our working capital deficit and liquidity position;

· our substantial debt and other financial obligations and our ability to comply with the terms of such debt;

· significant changes in natural gas and oil prices;

· the competitive nature of our industry;

· the speculative nature of oil and gas exploration;

· timing and amount of production;

· unanticipated down-hole mechanical problems in wells or problems related to producing reservoirs or infrastructure;

· material events resulting in changes in estimates;

· operational hazards and availability and cost of insurance on our assets and operations;

· the impact of current and future laws and government regulations;

· liability for environmental claims;

· increases in taxes on energy sources;

· effectiveness of our hedging activities;

· our dependence on third parties to provide infrastructure required for our operations;

· fluctuations in foreign currency exchange rates;

· the impact of the departure of any key employees or if we are unable to recruit and retain highly skilled administrative and operational staff;

· changes in general economic, market or business conditions in regions;

· expenditures and technological innovations required to develop unconventional plays;

· compression difficulties and expense;

· any title defects in our interests; and

· changes in overhead costs.

This list is not necessarily complete. Other unknown or unpredictable factors could also have material adverse effects on future results. We do not update publicly any forward-looking statement with new information or future events. Investors are cautioned not to put undue reliance on forward-looking statements as many of these factors are beyond our ability to control or predict. Additional information concerning these and other factors is contained in our filings with the SEC, including but not limited to, our Annual Report on Form 10-K for the year ended December 31, 2007 and under Item 1A of Part II hereof.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2007 Annual Report on Form 10-K, as well as with the Consolidated Financial Statements and notes thereto included in this Quarterly Report on Form 10-Q.

Hypothetical changes in prices chosen for the following estimated sensitivity effects are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations. However, since it is not possible to accurately predict future changes in commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Commodity Price Risk

We hedge a portion of our price risks associated with our natural gas sales. As of June 30, 2008, our outstanding futures contracts and swap agreements had an associated net fair value loss of $14.5 million. As of June 30, 2008, a 10% change in the CIG futures strip would result in a change of approximately $7.4 million in the value of unrealized derivatives. The following table reflects our commodity swaps executed and in place as of June 30, 2008, by quarter:

Quarter Ended	Qtrly. Vol. (MMBtu)	Weighted Average CIG Fixed Price per MMBtu
09/30/08	1,162,400	$	7.01
12/31/08	1,232,400	$	7.04
Total 2008	2,394,800	$	7.03
03/31/09	1,237,000	$	7.24
06/30/09	1,200,500	$	7.22
09/30/09	1,122,500	$	7.22
12/31/09	1,043,000	$	7.22
Total 2009	4,603,000	$	7.22
03/31/10	427,000	$	7.75
06/30/10	341,000	$	6.83
09/30/10	282,000	$	6.27
12/31/10	245,000	$	6.27
Total 2010	1,295,000	$	6.90
Total All	8,292,800	$	7.12

Commodity Swaps

On April 3, 2008, we entered into a natural gas commodity swap cash settlement transaction for 1,138,000 MMBtu from May 1, 2008 through December 31, 2009. May through December 2008 volumes under such swap agreement totals 364,000 MMBtu’s at a fixed price of $8.08 (CIG pricing) and January through December 2009 volumes total 774,000 MMBtu’s at a fixed price of $7.32 per MMBtu (CIG pricing).

On August 5, 2008, we liquidated a portion of our natural gas hedges to bring our percent of production hedged into compliance with our internal hedging policy and with the covenants of our the Amended Credit Agreement. 70% of our projected, developed production as of June 30, 2008 remains hedged at and average price (indexed at Colorado Interstate Gas, “CIG”) of $6.79 per Mmbtu through the end of 2008 and at an average price of $7.17 (indexed at CIG) through June 2009. We also have hedges in place from July 2009 through December 2010 at an average price of approximately $6.85 (indexed at CIG) for approximately 29% of projected production. The unwinding of the hedgets netted us approximately $1.7 million of cash.

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Item 4. Controls and Procedures

Evaluation of disclosure controls and procedures. In accordance with Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), management evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of June 30, 2008. Based upon their evaluation of these disclosures controls and procedures, the Chief Executive Officer and the Chief Financial Officer concluded that the disclosure controls and procedures were effective as of June 30, 2008.

Changes in internal control over financial reporting. There were no changes in internal controls over financial reporting that occurred during the quarter ended June 30, 2008 which have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

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PART II-OTHER INFORMATION

Item 1. Legal Proceedings

No legal proceedings are pending against the Company as of the filing date of this Quarterly Report on Form 10-Q.

Item 1A. Risk Factors

Set forth below are material changes to the risk factors that we previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007.

Risks Related to the Business

Storm Cat defaulted on its Amended Credit Agreement and does not have a forbearance agreement in place: We finance our operations through borrowings under the Credit Facility and also through cash generated by operating activities. The Amended Credit Agreement contains certain operational and financial covenants regarding our ability to create liens, incur indebtedness, make certain investments or acquisitions, enter into certain transactions with affiliates, incur capital expenditures beyond prescribed limits, deliver certain reports and information, and meet certain financial ratios. As of June 30, 2008, we were not in compliance with certain covenants under the Amended Credit Agreement. We are actively engaged in discussions with our lenders to amend certain terms of its credit arrangements to allow for greater operating flexibility. We are still in discussions with our lenders and currently do not have a forbearance agreement in place. We can provide no assurance that current discussions will result in a forbearance agreement or any amendments to the Amended Credit Agreement. Our lenders could accelerate our indebtedness under the Credit Facility and exercise any available rights and remedies. Our lenders could prevent us from paying interest to the holders of our Convertible Notes. The failure to make our scheduled interest payments or the acceleration of the indebtedness under the Amended Credit Agreement would result in a default of our Convertible Notes. If we were able to successfully negotiate a forbearance agreement, we may be required to pay significant amounts to our lenders to obtain their agreement to forbear exercising their rights and remedies. In addition, any forbearance agreement would have a limited duration and any future failures to comply with the covenants under the Amended Credit Agreement could result in further events of default which, if not cured or waived, could trigger prepayment obligations.

Storm Cat has a substantial working capital deficit: As a result of the reclassification of the $64.6 million outstanding under the Credit Facility, our working capital deficit increased to $87.7 million at June 30, 2008. This compares to a deficit in working capital of $2.0 million at December 31, 2007 and $12.7 million at March 31, 2008.

Storm Cat does not have adequate cash flow to fund its planned operations and capital projects and additional debt or equity financing will be required: Our planned operations require additional liquidity that may not be available. We make, and will continue to make, significant capital expenditures to find, acquire, develop and produce oil and gas reserves. There are currently no amounts available to be drawn on our Credit Facility. If our lenders accelerate our obligations, we would be unable to repay our obligations under the Credit Facility. If we are unable to obtain favorable amendments to the Amended Credit Agreement, we will seek to refinance the Credit Facility but we cannot give any assurance that we will be successful in obtaining such financing or obtaining it on acceptable terms. If our debt cannot be refinanced or restructured, our lenders could pursue remedies, including: (1) penalty rates of interest; (2) demand for immediate repayment of the debt; and/or (3) the foreclosure on any of the assets securing the debt. If this were to happen and we were liquidated or reorganized after payment to our creditors, there may not be sufficient assets remaining for any distribution to our shareholders.

We may engage in equity financings to reduce our leverage. If we raise additional funds through further issuances of equity or other securities evidencing the right to acquire equity, our existing security holders could suffer significant dilution, and any new equity securities we issue could have rights, preferences and privileges superior to those of holders of our common shares. Due to restrictive covenants in the Amended Credit Agreements and the seniority of the security interests granted to the lenders, we may not be able to obtain additional financing on acceptable terms, if at all. If we are unable to obtain adequate financing or financing on terms satisfactory to us, when we require it, our ability to continue to support our business growth and to respond to business challenges could be significantly limited. Any debt financing secured by us in the future could involve additional restrictive covenants relating to our capital raising activities and other financial and operational matters, which may make it more difficult for us to obtain additional capital and to pursue business opportunities.

Storm Cat’s liquidity position imposes significant risks to its operations: The Company’s liquidity position may adversely affect its relationships with its creditors, suppliers, customers and employees. Because of the public disclosure of the Company’s liquidity constraints, its ability to maintain normal credit terms with its suppliers may become impaired. Customers’ perception of the Company’s financial position may adversely affect their business dealings with the Company. The Company may also have difficulty maintaining its ability to attract, motivate and retain management and other key employees. Failure to maintain any of these important relationships could adversely affect the Company’s business, financial condition and results of operations.

Item 3. Defaults Upon Senior Securities

As of June 30, 2008, we were not in compliance with the Financial and minimum average daily production covenants set forth in the Amended Credit Agreement. We are currently discussing a possible waiver or amendment to the Amended Credit Agreement with our lenders. However, absent an amendment to the financial covenants or repayment or refinancing of the Credit Facility, it is likely that we will not be in compliance with the covenants for the next twelve months. Accordingly, the $64.6 outstanding under the Credit Facility at June 30, 2008 is classified as a current liability in the accompanying Consolidated Balance Sheet at June 30, 2008. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources”. There can be no assurance when, or if, a new credit facility, amendment, or waiver will be obtained. If our debt cannot be refinanced or restructured, our lenders could pursue remedies, including: (1) penalty rates of interest; (2) demand for immediate repayment of the debt; and/or (3) the foreclosure on any of the assets securing the debt.

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

The Annual General Meeting of Shareholders of Storm Cat was held on June 18, 2008. The following matters were voted on at the meeting:

(i) the election of seven (7) directors

(ii) the ratification of the appointment of Hein & Associates, LLP to serve as the independent registered public accounting firm for Storm Cat for fiscal year 2008.

(i) The entire nominated board of directors was elected and the Inspector of Election certified that the votes cast for or withheld with respect to the election of each director were as follows:

Name	Number of Votes Cast For	Number of Votes Withheld
Joseph M. Brooker	46,131,392	201,625

Robert J. Clark	46,132,092	200,925

Michael J. O’Byrne	46,132,842	200,175

Robert D. Penner	46,132,182	200,835

Jon R. Whitney	46,123,492	209,525

David G. Wight	46,127,632	205,385

Michael J. Wozniak	46,118,287	45,404

(ii) The Inspector of Election certified that the votes cast for, against or abstentions with respect to the ratification of the appointment of Hein & Associates, LLP to serve as the independent registered public accounting firm for Storm Cat for fiscal year 2008 were as follows:

For:		Against:		Withhold/Abstention:
46,145,673		45,404		141,941

Item 6. Exhibits

The exhibits listed in the accompanying exhibit index are filed as part of this Quarterly Report on Form 10-Q.

10.1		Storm Cat Energy Corporation Annual Incentive Plan dated April 23, 2008 (incorporated by reference to Exhibit 10.1 to Storm Cat Energy Corporation’s Current Report on Form 8-K filed on April 29, 2008 (Commission File No. 001-32628))

10.2		First Amendment to Credit Agreement, dated as of April 17, 2008, by and among Storm Cat Energy (USA) Corporation, Storm Cat Energy Corporation, Storm Cat Energy (Alaska) LLC, Storm Cat Energy (Powder River) LLC, Storm Cat Energy (Fayetteville) LLC, Triple Crown Gathering Corporation, Storm Cat Energy (USA) Operating Corporation, the lenders party thereto and Wells Fargo Foothill, LLC, as Agent (incorporated by reference to Exhibit 10.1 to Storm Cat Energy Corporation’s Current Report on Form 8-K filed on April 22, 2008 (Commission File No. 001-32628))

31.1		Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

31.2		Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

32.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

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SIGNATURES

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

	STORM CAT ENERGY CORPORATION

Date: August 11, 2008	By	/s/ Joseph M. Brooker
		Joseph M. Brooker
		Chief Executive Officer
		(Principal Executive Officer)

Date: August 11, 2008	By	/s/ Paul Wiesner
		Paul Wiesner
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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Exhibits

The exhibits listed in the accompanying exhibit index are filed as part of this Quarterly Report on Form 10-Q.

10.1		Storm Cat Energy Corporation Annual Incentive Plan dated April 23, 2008 (incorporated by reference to Exhibit 10.1 to Storm Cat Energy Corporation’s Current Report on Form 8-K filed on April 29, 2008 (Commission File No. 001-32628))

10.2		First Amendment to Credit Agreement, dated as of April 17, 2008, by and among Storm Cat Energy (USA) Corporation, Storm Cat Energy Corporation, Storm Cat Energy (Alaska) LLC, Storm Cat Energy (Powder River) LLC, Storm Cat Energy (Fayetteville) LLC, Triple Crown Gathering Corporation, Storm Cat Energy (USA) Operating Corporation, the lenders party thereto and Wells Fargo Foothill, LLC, as Agent (incorporated by reference to Exhibit 10.1 to Storm Cat Energy Corporation’s Current Report on Form 8-K filed on April 22, 2008 (Commission File No. 001-32628))

31.1		Certification by the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

31.2		Certification by the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

32.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350.

32.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350.

Storm Cat Energy CORP 10-Q