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 September 30, 2006

or

 

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

 

For the transition period from to

 

Commission file number:  001-32628

 

STORM CAT ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 (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, 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):

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common shares, as of the latest practicable date:

As of October 31, 2006, there were 80,429,820 common shares outstanding.

Table of Contents

TABLE OF CONTENTS PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
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 1A. Risk Factors
Item 6. Exhibits
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

 

Table of Contents

PART I—FINANCIAL INFORMATION

 Item 1. Financial Statements

STORM CAT ENERGY CORPORATION

INDEX TO FINANCIAL STATEMENTS

Consolidated Balance Sheets as of September 30, 2006 (Unaudited) and December 31, 2005
Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2006 (Unaudited) and 2005
Consolidated Statements of Stockholders’ Equity and Comprehensive Loss for the Year Ended December 31, 2005 and the Nine Months Ended September 30, 2006 (Unaudited)
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2006 (Unaudited) and 2005
Condensed Notes to Consolidated Financial Statements (Unaudited)

 

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STORM CAT ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(stated in U.S. Dollars, in thousands)

		September 30,						December 31,
		2006						2005
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents:		$	20,139					$	29,502
Accounts Receivable:
Joint Interest Billing		442						703
Revenue Receivable		1,192						504
Fair Value of Derivative Instruments (Note 10)		2,039						—
Prepaid Costs and Other Current Assets		1,289						445
Total Current Assets		25,101						31,154
PROPERTY AND EQUIPMENT:
Oil and Gas Properties: (Note 2)
Undeveloped Properties		33,552						5,078
Developed Property		54,760						23,367
Impairments		(4,157				)		(2,125				)
Less: Accumulated Depreciation, Depletion and Amortization		(2,944				)		(1,502				)
Total Oil and Gas Properties, net		81,211						24,818
Fixed Assets		1,056						911
Accumulated Depreciation		(335				)		(106				)
Total Property and Equipment, net		81,932						25,623
Fair Value of Derivative Instruments - Long Term (Note 10)		909						—
Restricted Investments (Note 5)		435						176
TOTAL ASSETS		$	108,377					$	56,953
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts Payable				$	37					$	3,815
Revenue Payable				975						313
Accrued and Other Liabilities				13,680						7,850
Accrued Interest				417						—
Notes Payable (Note 9)				7,500						—
Total Current Liabilities				22,609						11,978
LONG-TERM LIABILITIES:
Asset Retirement Obligation (Note 6)				1,646						793
Notes Payable - Long-Term (Note 9)				20,000						—
Flow-through Shares Liability				1,219						731
Total Liabilities				45,474						13,502
STOCKHOLDERS’ EQUITY:
Common Stock, without par value unlimited common shares authorized, issued and outstanding: 80,403,570 at September 30, 2006 and 65,654,388 at December 31, 2005				70,341						50,858
Contributed Surplus				4,441						2,204
Accumulated Other Comprehensive Income				4,095						151
Accumulated Deficit				(15,974			)			(9,762			)
Total Stockholders’ Equity				62,903						43,451
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY				$	108,377					$	56,953

 

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 U.S. Dollars and in thousands, except per share amounts)

		Three Months Ended September 30,						Nine Months Ended September 30,
		2006			2005			2006			2005
OPERATING REVENUES:
Oil and Gas Revenue		$	2,181		$	1,241		$	5,060		$	2,853
EXPENSES:
Operating Costs
Gathering and Transportation		343			221			906			491
Operating Expenses		693			379			2,043			1,355
General and Administrative		1,690			720			3,047			2,037
Stock-based Compensation		786			—			2,237			—
(Gain) on Property Sales		—			—			(185		)	—
Accretion Expense		95			—			146			—
Depreciation, Depletion and Amortization		834			362			1,807			947
Impairment		1,912			—			2,000			1,957
Total Operating Expenses		6,353			1,682			12,001			6,787
Operating Loss		(4,172		)	(441		)	(6,941		)	(3,934		)
OTHER EXPENSE (INCOME):
Loss on Foreign Exchange		—			—			11			11
Interest (Income)		(93		)	—			(433		)	—
Interest Expense		417			—			(424		)	—
Total Other Expense Income		324			—			2			11
Recovery of Future Income Tax Asset		(731		)	—			(731		)	—
NET LOSS		$	(3,765	)	$	(441	)	$	(6,212	)	$	(3,945	)
Basic and diluted loss per share (Note 3)		$	(0.055	)	$	(0.009	)	$	(0.093	)	$	(0.092	)
Weighted average number of shares outstanding		68,581,241			46,832,470			67,060,208			43,011,713

 

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

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STORM CAT ENERGY CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE LOSS

(Unaudited)

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

 

		Common Stock						Share			Contributed			Other Comprehensive			Accumulated			Total Stockholders’
		Shares			Amount			Subscription			Surplus			Income			Deficit			Equity
BALANCE AT DECEMBER 31, 2004		32,560,714			$	5,917		$	22		$	289		$	229		$	(1,393	)	$	5,064
Issuance of shares for cash
-pursuant to a private placements		18,993,826			37,745			—			—			—			—			37,745
-pursuant to warrants exercised		13,453,180			10,661			—			—			—			—			10,661
-pursuant to a private placement of flow-through shares		646,668			287			—			—			—			—			287
Share issuance costs		—			(3,043		)	—			—			—			—			(3,043		)
Flow-through share liability		—			(731		)	—			—			—			—			(731		)
Non-cash compensation charge		—			—			—			1,915			—			—			1,915
Comprehensive loss (Note 4)
Net loss		—			—			—			—			—			(8,369		)	(8,369		)
Foreign currency translation		—			—			—			—			(78		)	—			(78		)
Total comprehensive loss		—			—			—			—									(8,447		)
BALANCE AT DECEMBER 31, 2005		65,654,388			$	50,836		$	22		$	2,204		$	151		$	(9,762	)	$	43,451
Issuance of shares for cash
-pursuant to warrants exercised		$	753,906		$	1,297		$	—		$	—		$	—		$	—		$	1,297
-pursuant to stock options exercised		227,500			139			—			—			—			—			139
-pursuant to a private placement of flow-through shares		6,172,839			9,933			—			—			—			—			9,933
-pursuant to a private placement in Sept.		7,594,937			10,727			—			—			—			—			10,727
Share issuance costs		—			(1,394		)	—			—			—			—			(1,394		)
Flow-through share liability		—			(1,219		)	—			—			—			—			(1,219		)
Non-cash compensation charge		—			—			—			2,237			—			—			2,237
Other		—			22			(22		)	—			—			—			—
Comprehensive loss (Note 4)
Net loss		—			—			—			—			—			(6,212		)	(6,212		)
Change in derivative instrument fair value		—			—			—			—			3,253			—			3,253
Reclassification to earnings		—			—			—			—			(305		)	—			(305		)
Foreign currency translation		—			—			—			—			996			—			996
Total comprehensive loss		—			—			—			—									(2,268		)
BALANCE AT SEPTEMBER 30, 2006		80,403,570			$	70,341		$	—		$	4,441		$	4,095		$	(15,974	)	$	62,903

 

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

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STORM CAT ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited)

(stated in U.S. Dollars and in thousands)

 

		For the Nine Months Ended
		September 30,			September 30,
		2006			2005
Cash flows from operating activities:
Net Loss		$	(6,837	)	$	(3,945	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion, amortization and impairments		3,703			2,905
Asset retirement obligation		146			—
Gain on disposition of properties		185			—
Changes in operating working capital:
Changes in operating assets and liabilites:
Accounts receivable		(427		)	66
Other current assets		(844		)	(1,401		)
Accounts payable		(3,784		)	334
Other current liabilites		3,284			61
Net cash used in operating activities		(3,949		)	(1,980		)
Cash flows from investing activities:
Restricted investments		(259		)	(152		)
Capital expenditures - oil and gas properties		(56,446		)	(12,115		)
Other capital expenditures		(145		)	(523		)
Net cash used in investing activities		(56,850		)	(12,790		)
Cash flows from financing activities:
Issuance of shares of stock for cash		20,214			20,879
Contributed surplus		2,238			—
Flow-through shares		1,219			—
Bank debt		35,000			—
Repayment of bank debt		(7,500		)	—
Net cash provided by financing activities		50,440			20,879
Effect of exchange rate changes on cash		996			(367		)
Net increase (decrease) in cash and cash equivalents		(9,363		)	5,742
Cash and cash equivalents and beginning of period		29,502			2,665
Cash and cash equivalents at end of period		$	20,139		$	8,407

 

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)

Note 1.          Basis of Presentation

Storm Cat Energy Corporation, together with its consolidated subsidiaries, (“Storm Cat” or “the Company”) is an independent oil and gas company focused on exploration and development of unconventional gas reserves, which are reserves from fractured shales, coal beds and tight sand formations.  The Company has producing properties in Wyoming’s Powder River Basin (“PRB”).  Its primary exploration and development acreage is located in Canada and the United States.

The accompanying unaudited condensed consolidated financial statements include the accounts of Storm Cat, and have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”) for the preparation of interim financial information.  In the opinion of management, the accompanying unaudited condensed consolidated financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly the financial position of Storm Cat as of September 30, 2006, and results of operations for the three months ended September 30, 2006 and 2005 and cash flows for the nine months ended September 30, 2006 and 2005.  Interim results are not necessarily indicative of the results that may be expected for a full year because of the impact of fluctuations in prices received for oil and natural gas and other factors.

Financial information for periods prior to December 2005, previously accounted for in Canadian Dollars and under accounting principles and practices generally accepted in Canada (“Canadian GAAP”), has been restated in U.S. Dollars in order to conform to the current method of presentation.  The effects of such changes on the quarterly financial information previously presented for the first three quarters of 2005 is shown in Note 13 of the Company’s Annual Report on Form 20-F for the fiscal year ended December 31, 2005.  These reclassifications had no affect on the net loss.

Because a precise determination of many assets and liabilities is dependent upon future events, the timely preparation of consolidated financial statements for a period necessarily requires that management make estimates and assumptions and use judgment regarding the reported amounts of assets, liabilities, revenue and expenses and in the disclosure of commitments and contingencies.  Actual results will differ from these estimates as future confirming events occur, and such differences could be significant.

For a more complete understanding of Storm Cat’s operations, financial position and accounting policies, these condensed consolidated financial statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 20-F for the fiscal year ended December 31, 2005.

Certain reclassifications have been made to prior amounts to conform to the classifications used in the current period.

Note 2.          Oil and Gas Properties

The Company follows 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.  Such costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, drilling costs, overhead charges directly related to acquisition and exploration activities and the fair value of estimated future abandonment costs.

Costs capitalized, together with the costs of production equipment, are depleted using the units-of-production method whereby capitalized costs, as adjusted for future development costs, are amortized over the total estimated proved reserves.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations.  These unproved properties are assessed periodically to ascertain whether impairment has occurred.  When proved reserves are assigned, the cost of the property is added to costs subject to depletion.  When property is considered to be impaired, the costs are reported as a period expense.  As the Company has no proved reserves in Canada or Mongolia, the properties were expensed immediately through the recognition of an $88,000 impairment for costs related to Mongolia, and a $1.9 million impairment for Moose Mountain in Canada during the nine months ended September 30, 2006.  A $2.0 million impairment was also taken for Mongolia in the second quarter of 2005.  Proceeds from sales, if any, of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the estimated proved oil and gas reserves attributable to a cost center.

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Under the full cost method of accounting, capitalized oil and gas property costs, less accumulated depletion and net of related deferred income taxes, if any, may not exceed an amount referred to as the “ceiling”.  The ceiling is the sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the lower of cost or fair market value of unproved properties.  The present value of estimated future net revenues is computed by pricing estimated future production of proved reserves at current period end product prices, and then deducting future expenditures estimated to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.  If the amount of capitalized costs exceeds the ceiling, a write-down of the capitalized costs is required unless commodity prices increase subsequent to the end of the period such that the deficiency is reduced or eliminated.  Once a write-down has been recorded, it may not be reversed in a subsequent period.

At September 30, 2006, the ceiling value of the Company’s reserves was calculated based upon quoted market prices of $3.26 per Mcf for Colorado Interstate Gas (“CIG”) gas, plus a $0.15 per Mcf premium for gas delivered to the Cheyenne Hub.  Using this pricing, and Storm Cat’s cash flow hedges of gas production in place at September 30, 2006, the net book value of oil and gas properties would have exceeded the ceiling amount by $6.6 million.  The Company had approximately 3,684.5 MMBtu’s of future production hedged at September 30, 2006 (see Item 3 of this Form 10-Q for additional discussion of the Company’s hedging activities).

Subsequent to quarter end (on October 18, 2006), the market price for CIG gas increased to $4.94 per Mcf.  Utilizing this pricing plus the Company’s $0.15 per Mcf premium, and the cash flow hedges in place on September 30, 2006, the Company’s net book value of natural gas properties did not exceed the ceiling amount. As a result of the increase in the ceiling amount using the subsequent prices, the Company has not recorded a write down of its oil and gas property costs.  As of October 31, 2006, the price for CIG had increased to $5.98 per MBtu.

Decreases in market prices from October 18, 2006 levels, as well as changes in production rates, levels of reserves, the evaluation of costs excluded from amortization, future development costs, and service costs could result in future ceiling test impairments.

Note 3.          Basic and Diluted Loss per Share

Basic loss per share is computed by dividing the net loss by the weighted average number of common shares outstanding during the period.  Diluted loss per share is calculated giving effect to the potential dilution that would occur if vested stock options and stock purchase warrants were exercised.  The dilutive effect of options and warrants 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 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 three months ended September 30, 2006 and 2005.  Listed below is a table showing both the basic and diluted shares outstanding at September 30, 2006 and 2005, respectively.

 

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Note 4.          Comprehensive Loss

Comprehensive loss consists of net loss, the effects of currency translation, and the unrealized gain on hedges.  Comprehensive loss for the three and nine months ended September 30, 2006 and 2005, respectively, is as follows:

 

Note 5.          Restricted Investments

Storm Cat was required to post three performance bonds totaling $434,000 in connection with its operations in Wyoming.  The funds are held as insured interest bearing certificates of deposit at an interest rate of 2.5%, payable annually.

Note 6.          Asset Retirement Obligation

The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and 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.  The accretion expense is recorded as a component of depreciation, depletion and amortization expense in the accompanying condensed consolidated financial statements.

A reconciliation of the changes in the asset retirement obligation for the nine months ended September 30, 2006 is as follows:

 

Note 7.          Stock-based Compensation

Storm Cat grants stock options at exercise prices equal to the fair market value of the Company’s stock at the date of the grant, and accounts for its options using the fair value method.  The fair value is determined using a Black-Scholes option-pricing model that takes into account the stock price at the grant date, the exercise price, the expected life of the option, the volatility of the underlying shares and the expected dividends, and the risk-free interest rate over the expected life of the option.

The fair value of stock-based compensation is expensed, with a corresponding increase to capital surplus.  Upon exercise of stock options, the consideration paid upon exercise is recorded as additional value of common shares, and the amount previously recognized in capital surplus is reclassified to common shares.

The Company has reserved a total of 10,000,000 shares in the aggregate for issuance under the terms of the Storm Cat Energy Corporation Amended and Restated Share Option Plan (the “Amended Option Plan”) and the Storm Cat Energy Corporation Restricted Share Unit Plan, both approved by the shareholders on June 27, 2006.  All options granted prior to the approval of the Amended Option Plan are included in the number of options covered under the Amended Option Plan.

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A summary of the status of the options under the Amended Option Plan as of September 30, 2006 and changes during the nine months then ended, is presented below:

 

Note 8.          Non-cash Items

Non-cash items excluded from the cash flow are capital accrual related to oil and gas asset additions and the associated liability.  These amounts totaled $13,072,000 in September 2006 and $10,173,000 in December 2005.  An additional non-cash item excluded from the cash flow is the increase in the asset retirement obligation in 2006 of $705,000.

Note 9.          Bank Credit Facility

On July 28, 2006, Storm Cat entered into a $250 million Credit Agreement (the “Credit Agreement” or the “Agreement”) with JPMorgan Chase Bank, N.A. (“JPMorgan”).  Borrowings made under the Credit Agreement are guaranteed by the Company’s subsidiaries and secured by a pledge of the capital stock of its subsidiaries and mortgages on its Powder River Basin properties.  At September 30, 2006 there was $20 million outstanding on the Senior portion of the credit facility.  However, the Company subsequently paid down $651,000 in order to secure two letters of credit, the total of which is considered usage for purposes of calculating availability and commitment fees.  The Agreement also includes a $15 million short-term Bridge Facility (the “Bridge Facility”) which is discussed further below.

The initial aggregate commitment of the lenders under the Credit Agreement is $250 million, subject to a borrowing base which has initially been set at $20 million.  The aggregate borrowings and outstanding letters of credit under the Credit Agreement may not at any time exceed the borrowing base.  Interest on borrowings is payable quarterly and principal is due at maturity on July 28, 2010.

Interest on borrowings under the Credit Agreement accrues at variable interest rates at either, at the Company’s election, a Eurodollar rate or an alternate base rate.  The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies from 1.25% (for periods in which the Company has utilized less than 50% of the borrowing base) to 2.00% (for periods in which the Company has utilized greater than 90% of the borrowing base).  The alternate base rate is calculated as (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus 1/2%, plus (2) an applicable margin that varies from 0% (for periods in which the Company has utilized less than 50% of the borrowing base) to 0.50% (for periods in which the Company has utilized greater than 90% of the borrowing base).  Storm Cat elects the basis of the interest rate at the time of each borrowing.  In addition, the Company is obligated to pay a commitment fee under the Credit Agreement quarterly in arrears based on a percentage multiplied by the daily amount that the aggregate commitments exceed borrowings under the Agreement.  The commitment fee percentage varies from 0.30% to 0.50% based on the percentage of the borrowing base utilized.

The Credit Agreement requires the Company to comply with financial covenants as follows:  (1) a ratio of current assets to current liabilities (determined at the end of each quarter) of not less than 1:1; and (2) a ratio of total funded debt to EBITDA (as such terms are defined in the Credit Agreement) for the most recent quarter annualized not to be greater than 3.5:1 for the fiscal quarters annualized ending December 31, 2006 and March 31, 2007, and 3:1 for each subsequent quarter.  In addition, the Credit Agreement contains covenants that restrict the Company’s ability to incur other indebtedness, create liens or sell its assets, pay dividends on its common shares and make certain investments.

Current assets are defined according to the Agreement as current assets of the Parent and its Subsidiaries (as such terms are defined in the Credit Agreement), excluding amounts “due to or due from” Parent and its Subsidiaries, plus the unutilized commitment under the Credit Agreement minus current FASB 133 and FASB 143 assets.  Current liabilities are defined as the current obligations of the Parent and/or Subsidiaries, excluding the current portion of the Credit Agreement and current FASB 133 and FASB 144 liabilities.

The Credit Agreement is available to provide funds for the exploration, development and/or acquisition of oil and gas properties and for working capital and other general corporate purposes.  The Credit Agreement provides for semi-annual evaluation of the borrowing base, which will be determined as a percentage of the discounted present value of the Company’s oil and natural gas reserves.

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The Company had drawn down $15 million under the Bridge Facility since the time of the Agreement’s execution to help fund its recent PRB acquisition.  On September 27, 2006, the Company used proceeds from an equity financing transaction and paid down $7.5 million under the Bridge Facility leaving a balance of $7.5 million outstanding at the end of the quarter.  The Company paid $850,000 in fees to JPMorgan associated with the Bridge Facility ($800,000 for an up-front fee and $50,000 for a structuring fee).  The fees have been recorded as deferred financing costs in the accompanying financial statements and are being amortized though the first quarter of 2007, at which time the Company expects to have paid the Bridge Facility in full.

The Company would be out of compliance if the EBITDA calculation was required for the quarter ended September 30, 2006. This is a result of the Company booking only one month of revenue from the recent PRB acquisition in accordance with purchase accounting requirements. Management does not anticipate being out of debt covenant requirements for the quarter ending December 31, 2006 as the Company will book a full quarter of operating results from the PRB acquisition. However, if the Company is unable to meet its debt covenants and/or is unable to renegotiate the covenant, it could result in liquidity problems and possible curtailment of future planned operational activities.

Note 10.        Derivative Financial Instruments

The Company recognized a gain of $300,000 from its derivative contracts in the third quarter of 2006.  No hedges were in place during 2005 as indicated in the table below, which summarizes derivative instrument gain (loss) activity:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2006			2005			2006			2005
		(In thousands)						(In thousands)
Derivative contract settlements realized in oil and gas hedge gain (loss)		$	305		$	0		$	305		$	0
Derivative contracts included in unrealized derivative gain		2,948			0			2,948			0
Total		$	3,253		$	0		$	3,253		$	0

 

Oil and Gas Commodity Hedges

To mitigate a portion of the potential exposure to adverse market changes, the Company has entered into various derivative contracts.  As of September 30, 2006, the Company has hedge contracts in place through 2011 for a total of approximately 3,684.5 MMBtu of anticipated production.  The Company anticipates that all forecasted transactions will occur by the end of their originally specified periods.  All contracts are entered into for other than trading purposes.

As of September 30, 2006, all natural gas derivative instruments qualified as cash flow hedges for accounting purposes.  The estimated fair value of natural gas derivative contracts designated and qualifying as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), was an unrealized gain of $2.948 million as of September 30, 2006.

Realized gains or losses from the settlement of gas derivative contracts are reported in the total operating revenues section on 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 other comprehensive income until the hedged item is recognized in earnings.  Any change in fair value resulting from ineffectiveness is recognized currently in derivative loss in the consolidated statement of operations.

The Company has minimized ineffectiveness by entering into gas derivative contracts indexed to CIG.   As the Company’s derivative contracts contain the same index as the Company’s sale contracts, this results in hedges that are highly correlated with the underlying hedged item.

Note 11.        Foreign Currency Risk

The Company is exposed to fluctuations in foreign currencies, primarily through its operations in Canada. The Company monitors this exposure but has not entered into any hedging arrangements to protect itself from currency fluctuations.  As of September 30, 2006, $12.1 million U.S. dollar equivalent, or approximately 60% of the Company’s cash, was held in Canadian dollars. Canadian dollars were converted to U.S. Dollars as of September 30, 2006 at $0.8979 as found on www.oanda.com/convert/fxhistory.

Note 12.        Sales and Transportation Commitments

a)      Forward Sales

As of September 30, 2006, Storm Cat is subject to the following delivery commitments under sales agreements.  The Company accounts for these as normal sales.

·              10,000/mo (333/day) sale for November 05 - October 06 at $8.31/MBtu for delivery at Cheyenne Hub.

·              30,000/mo (1000/day) sale for April 06 - October 06 at $9.10/MBtu for delivery at Cheyenne Hub.

b)      Firm Transportation Service Agreements

The Company has a firm transportation agreement in place through April 11, 2013 to transport gas from Cheyenne Plains to ANR PEPL (Oklahoma).  The agreement calls for the Company 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 gathering charges for volumes shipped on the Cheyenne Plains pipeline to the ANR PEPL (Oklahoma) delivery hub.  Storm Cat has sold its 2,000 Dth/D capacity commitment for a period of sixteen months (from November 2006 through February 2008) at the full rate and volume commitment.

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

Storm Cat entered into a gathering agreement with an unaffiliated third party which requires payment of gathering fees of $0.47 per Mcf on the following annual volumes: 2006 - 2,064,600; 2007 — 2,482,231; 2008 — 2,040,575.  In the event that Storm Cat is unable to meet these annual delivery levels they will be liable at a rate of $0.47 per undelivered Mcf.  Over delivered volumes will count toward the overall commitment through 2008.  The rate drops to $0.284 per Mcf for future volumes.

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Note 13.        Commitments and Contingencies

The Company leases 8,802 square feet of administrative office space in the United States and 5,495 square feet of administrative office space in Canada under operating lease arrangements through November 30, 2009 and March 31, 2010, respectively.  A summary of future minimum lease payments under the non cancelable operating leases as of September 30, 2006 is as follows:

United States
Year Ending December 31, 2006		$	38,142
Year Ending December 31, 2007		154,218
Year Ending December 31, 2008		156,419
Year Ending December 31, 2009		145,233
Total		$	494,012

 

Commitments relative to Canadian leases are stated in U.S. Dollars utilizing the current average exchange rate for the 273 days in 2006 as reported by Oanda.com historical currency exchange rates.  The rate used for conversion and applied to the future minimum lease payments is $0.88318)

Canada
Year Ending December 31, 2006		$	27,684
Year Ending December 31, 2007		110,736
Year Ending December 31, 2008		110,736
Year Ending December 31, 2009		110,736
Year Ending December 31, 2010		27,684
Total		$	387,576

 

Note 14.        Subsequent Events

Cessford Area, Alberta - Farm-out

Storm Cat farmed-out acres in the Cessford Area of Alberta.  The Assignee is to drill a 1,165 meter (3,822 feet) horizontal well to test the Mannville Coals.  Upon completion of the test well, the Assignee will earn 100% working interest in the spacing unit for the test well and Storm Cat will retain a 5% overriding royalty which is convertible to a 50% working interest after payout.  The Assignee has the option, 50 days from rig release of the test well, to elect to drill an option well.  If it elects to drill the option well, it is to spud the same within 90 days of election date.  Earning for the option well is to be the same as for the test well.  The Assignee has the option to drill additional option wells pursuant to the same terms and conditions until all of the farmout lands are earned.

Judy Creek Area, Alberta - Farm-in

On or before December 30, 2006 Storm Cat will drill a 1,460 meter (4,790 feet) test well to evaluate the Banff formation and the Mannville Coals.  Upon completion of the test well, Storm Cat will earn a 60% working interest in the farm-out lands.  Storm Cat has the option, for 60 days from rig release of the test well, to elect to drill an option well.  The option well must spud within 60 days of the election date.  Should Storm Cat choose to drill the option well, it would earn 60% working interest in the option lands.

Leasehold Purchase - Cleburne, Conway and Faulkner Counties, Arkansas

Effective October 12, 2006, Storm Cat signed a letter of intent to purchase one hundred percent of a third party’s right, title and interest in the oil and gas leases, wells and associated equipment and personal property in the counties of Cleburne, Conway and Faulker, Arkansas.  The purchase involves approximately 2,300 gross and 384 net mineral acres and a net revenue interest of 77.5%.  The acquisition also gives Storm Cat immediate participation in five wells at various stages of drilling and completion with working interests in the 1% to 2% range.

Restricted Share Units Issued

On October 13, 2006, the Company issued an additional 26,250 fully vested restricted shares from its treasury to its directors for services pursuant to a Board-approved compensation plan. The Company’s compensation cost relative to the restricted share issuance is $44,076, which will be recognized in the fourth quarter.

Letters of Credit

Subsequent to the end of the third quarter, JPMorgan issued two letters of credit on behalf of Storm Cat; one on October 11, 2006 in the amount of $176,000, and another on October 23, 2006 in the amount of $475,000.  The Company paid down a portion of its Senior credit facility by this amount in order to fund the letters of credit.

Note 15.        Powder River Basin Acquisition

Properties from Storm Cat’s recent PRB acquisition are located in and around its core PRB operating area, allowing the Company to further capitalize on economies of scale and operating efficiencies. Storm Cat acquired approximately 10.2 Bcf of proved reserves. Gross production from the acquired properties is approximately 7.0 MMcf/d (3.0 MMcf/d net) of natural gas from 64 producing coalbed methane (“CBM”) wells, 46 of which are operated by Storm Cat.  Approximately 80% of the acreage of this acquisition is undeveloped.

The Company plans to file a Form 8-K/A with the SEC on or before November 15, 2006 which will reflect its pro forma financial statements associated with this acquisition.

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Note 16.        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 the Company would have followed had its financial statements been prepared in accordance with Canadian GAAP.

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

 a)     Mineral Properties and Deferred Exploration Costs

Under Canadian GAAP, resource property acquisition and exploration costs may be deferred and amortized to the extent they meet certain criteria.  The Company follows the full cost method of accounting for its oil and gas properties under U.S. GAAP, which follows the same convention as Canadian GAAP.  Under the successful efforts method, resource property acquisition and exploration costs related to unproved properties must be expensed as incurred.

b)      Stock-based Compensation

The Company grants stock options at exercise prices equal to the fair market value of the Company’s common shares at the date of the grant.  Under Statement of Financial Accounting Standards (SFAS) No. 123 the Company had accounted for its employee stock options under the fair value method.  The fair value is determined using an option pricing model that takes into account the share price at the grant date, the exercise price, the expected life of the option, the volatility of the underlying common shares and the expected dividends, and the risk-free interest rate over the expected life of the option.

As a result of the new recommendations of the Canadian Institute of Chartered Accountants regarding accounting for stock-based compensation, there is no difference between Canadian GAAP and U.S. GAAP for the three months and nine months ended September 30, 2006.

c)      Oil and Gas Properties

Prior to January 2004, there were certain differences between the full cost method of accounting for oil and gas properties as applied under Canadian GAAP and as applied under U.S. GAAP.  The principal difference was in the method of performing ceiling test evaluations under the full cost method of accounting rules.  Under Canadian GAAP prior to January 2004, impairment of oil and gas properties was based on the amount by which a cost center’s carrying value exceeded its undiscounted future net cash flows from proved reserves using period-end, non-escalated prices and costs, less an estimate for future general and administrative expenses, financing costs and income taxes. Effective January 2004, 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.  The Company performed a ceiling test in accordance with U.S. GAAP and determined that an impairment would not be required because gas prices had recovered since September 30, 2006 (see Note 2 for further details).

d)      Comprehensive Loss

U.S. GAAP requires disclosure of comprehensive loss which, for the Company, is net loss under U.S. GAAP plus the change in cumulative translation adjustment under U.S. GAAP.  Also included is the unrealized gain or loss on future volumes Storm Cat has hedged.  The Company has 3.5 MMBtu’s per day hedged through August 2009. This results in a current difference between U.S. and Canadian GAAP in that such amounts are recognized as income or loss on a current basis in the statement of operations under Canadian GAAP.

The concept of comprehensive loss does not come into effect until fiscal years beginning on or after October 1, 2006 for Canadian GAAP.  Management does not believe that any recently issued, but not yet effective, accounting standards if currently adopted could have a material effect on the accompanying financial statements.

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e)      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. Under Canadian GAAP, the gross proceeds received on flow-through share issuances are initially recorded as share capital. The Premium recorded as a current liability under U.S. GAAP at December 31, 2005 was $731,057.  As of September 30, 2006, this liability under U.S. GAAP has been reduced to $0 and the renunciation of expenditures has occurred.  The Company issued 6,172,839 flow-through share units on September 27, 2006.  The Premium on flow- through share liability related to these share units is $1,219,370.

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 payable that were renounced.  Under U.S. GAAP, the future tax liability is recorded through a charge to income tax expense less the reversal of the Premium previously reported, the initial liability is adjusted to a deferred income tax liability and as a result of the recalculation of the Company’s deferred taxes, this amount ultimately is recorded as an income tax benefit.

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

 

 

 

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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,”, “SCE”, “we,” “us,” “our” or “ours” when used herein this Item refer to Storm Cat Energy Corporation, together with its operating subsidiaries.  When the context requires, the Company refers to these entities separately.

CAUTION REGARDING FORWARD LOOKING STATEMENTS

This publication contains certain “forward-looking statements” as defined in the United States Private Securities Litigation Reform Act of 1995.  Such statements are based on the Company’s current expectations, estimates and projections about the industry, management’s beliefs and certain assumptions made by it; and involve a number of risks and uncertainties including but not limited to economic, competitive, governmental and geological factors effecting the Company’s operations, markets, products and prices and other risk factors.  Words such as “anticipates”, “expects”, “intends”, “plans”, “believes” or similar expressions are intended to identify forward-looking statements.  There can be no assurances that such statements will prove to be accurate and actual results and future events could differ materially from those anticipated in such statements.  Factors that could cause future results to differ materially from those anticipated in these forward-looking statements include the volatility of natural gas prices, the possibility that exploration efforts will not yield economically recoverable quantities of gas, accidents and other risks associated with gas exploration and development operations, the Company’s need for and availability of additional financing, and the other risk factors discussed in greater detail in the Company’s various filings with the Securities and Exchange Commission (“SEC”) and Canadian securities regulators, including the Company’s Annual Report on Form 20-F for the fiscal year ended December 31, 2005.

Overview

Storm Cat Energy is an independent oil and gas company focused on exploration and development of unconventional gas reserves, which are reserves from fractured shales, coal and tight sand formations.  The Company has producing properties in Wyoming’s Powder River Basin (“PRB”).  Its primary exploration and development acreage is located in Canada and the United States.  Storm Cat continues to execute on its long-term strategy of growth through continued development and the acquisition of prospective acreage that exploits the abilities of the Company’s technical team.

Operational Area Update

Since October 2004, Storm Cat has acquired a large and highly prospective group of assets, all targeting vast unconventional resources of natural gas.  Excluding the Joint Development Agreement (“JDA”) with an independent third party (explained in detail below), which has not yet closed, the Company has operating control of approximately 179,556 gross acres, or 163,964 net acres (excluding Moose Mountain in Saskatchewan, which was impaired in the amount of $1.9 million in the third quarter of 2006).

In 2006, Storm Cat has drilled 66 operated wells.  An additional 35 wells are anticipated to be drilled by year-end.

The Company closed on the $30.7 million PRB acreage purchase from a third party effective July 1, 2006.  It has received approval for a Federal Plan of Development (“POD”) for 38 wells on this acreage with 25 of these wells to be drilled in 2006.  To further develop the acreage, application is being made on two Federal PODs for 2007.  A total of 145 locations are anticipated to be drilled to develop the acquired acreage.  With the new acreage acquisition, Storm Cat now controls 39,235 gross (29,410 net) acres in the Powder River Basin (excluding the Joint Development Agreement as discussed below).

Current Operations

Powder River Basin (Wyoming):

Production from the Storm Cat’s PRB properties approximates 13,200 gross and 7,050 net Mcf per day.

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The Company had 238 operated and 29 non-operated gas wells in Campbell County, Wyoming producing as of September 30, 2006.  Additionally, it had nine operated and one non-operated gas well(s) outside the Campbell County, Wyoming area; for a total well count of 247 operated and 30 non-operated as of September 30, 2006.

·      Powder River Basin Acquisition – Properties from the recent acquisition are located in and around Storm Cat’s core PRB operating area, allowing the Company to further capitalize on economies of scale and operating efficiencies.  Storm Cat acquired approximately 10.2 Bcf of proved reserves. Storm Cat’s reserve quantity estimations were evaluated by Netherland Sewell & Associates (“NSAI”). Gross production from the acquired properties is approximately 7.0 MMcf/d (approximately 3.0 MMcf/d net) of natural gas from 64 producing coalbed methane (“CBM”) wells, 46 of which are operated by Storm Cat.  Approximately 80% of the acreage of this acquisition is undeveloped.

·      Joint Development Agreement (“JDA”) – On September 14, 2006, Storm Cat entered into JDA with an unaffiliated third party to jointly develop certain lands for CBM in the PRB.  Under the JDA, Storm Cat and its JDA partner will establish an Area of Mutual Interest (“AMI”) in which Storm Cat will act as Operator.  Storm Cat acquired an undivided 50% of its JDA partner’s working interest and production in existing wells, leasehold and infrastructure.  The Company will have the option to earn an undivided 50% interest in the JDA partner’s leasehold within the AMI through development.

·      Drilling Operations – Thirty-five wells were drilled in the first half of 2006, and an additional twenty-one wells were spud in the third quarter.  Storm Cat has drilled 56 wells year-to-date of an anticipated/budgeted 66 wells at Northeast Spotted Horse (“NESH”) and Jamison/Twenty Mile.  One rig currently operates in this area.   Twenty-five additional wells are anticipated to be drilled in connection with the recent PRB acquisition.

·     Permitting

o      A POD for Jamison/Twenty Mile, comprised of 20 predominantly Cook/Wall multi-seam wells, has been approved.

o      The Federal POD for Pee Gee Ranch (part of the recent PRB acquisition), comprised of 38 Cook/Wall multi-seam wells, has been approved.

o      A Federal POD for Ford Ranch, comprised of 33 multi-seam wells, has been completed and submitted to the BLM.  Approval is anticipated in December 2006 or January 2007.

o      Fee wells at Ford Ranch have been permitted for 2007.

o      State wells in Sheridan County are being permitted for 2007.

o      Federal PODs are being prepared for Bitter Creek and Highline (part of the recent PRB acquisition).

·      Gas and Water Gathering System Construction – Gas and water system construction is on-going for the current phases of drilling.

Alaska:

The Northern Dancer #1 well, spud February 14, 2006, reached a total depth of 6,243 feet in mid-March.  Open hole logs were run and production casing was set to total depth.  The well encountered a significant amount of total coal (274 feet between 1,000 feet and total depth), as well as inter-bedded conventional sandstones.

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The Company is currently evaluating the well’s logs, gas shows and cuttings as well as researching offsetting/analogous well information relative to a planned completion attempt in 2007.  Cost and availability of completion rigs and services has prohibited completion activity for the remainder of 2006.

Elk Valley (British Columbia):

Storm Cat has five wells in Elk Valley on production as of September 30, 2006; three West pilot wells previously drilled, reactivated and remediated; and two new wells drilled, completed and put on production in 2006.  Total current gas production is approximately 250 Mcf/d. None of the gas produced from this area is being sold during the present evaluation period.  Recent production has been as high as 400 Mcf/d.  Production was at 220 Mcf/d when the West pilot well was deactivated.

·      Drilling Operations – Five wells were drilled in the third quarter of 2006 with the following results:

o      d-73-L well:  Drilled in 11 days, finding 283 feet of net coal

o      a-83-L well:  Drilled in 14 days, finding 203 feet of net coal

o      b-74-L well:  Drilled in 11 days, finding 255 feet of net coal

o      a-94-L well:  Drilled in 17 days, finding 202 feet of net coal

o      c-53-L well:  Drilled in 9 days, finding 258 feet of net coal

·      Completion Operations – Completions for the five 2006 drilled wells are scheduled to start in November 2006.

·      Compression – Storm Cat is currently evaluating/engineering gas plant (treatment and compression) and gas sales line options.

·      Permitting – One of six locations that were selected for 2006 was not drilled but has an active license.  Storm Cat has also selected six additional locations and has begun the licensing process.

·      Gas and Water Gathering System Construction – Facility and pipeline construction to tie the west and central (east) facilities is complete.  This created additional water handling capacity needed for the 2006 drilling program and tied-in all gas gathering systems at the planned central gas treatment and compression facility.  Construction for the gas and water pipeline routes for the wells drilled in 2006 is also complete.

Storm Cat assumed 100% operatorship of the 77,775 gross/net acre Elk Valley Project, effective October 31, 2006.  The former operator retains a 2.5% overriding royalty interest.

Moose Mountain (Saskatchewan):

The Company drilled, cased and completion tested three Moose Mountain wells in 2006.  This property was impaired in the amount of $1.9 million in the third quarter of 2006.  Storm Cat subsequently sold its working interest in this property to avoid plugging and abandonment costs, but has retained a 1% overriding royalty interest.

Alberta:

In Alberta, the Cessford 2-19-26-15W4 well was drilled vertically to total depth in the second quarter of 2006.  The Basal Quartz Channel sand was encountered, but was wet.  The Mid-Mannville Coal was cored in order to obtain gas content and rank data.  The Mannville Coal was completed in the third quarter of 2006.

·      Permitting - A number of surface locations have been surveyed and Storm Cat is in the process of submitting applications to permit drilling locations.

Storm Cat’s technical team is evaluating the drilling and completion test results, as well as core data retrieved from the Cessford 2-19 well, toward testing the potential of the Mannville Coal.  The Company’s core analysis indicates that the coal’s thickness and gas content quantity provide sufficient petrophysical evidence to support Storm Cat’s decision to move rapidly into an exploration/exploitation phase, including horizontal wells and application of a variety of completion techniques, all with the goal of deriving the highest and best gas quantities from the project.

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Arkansas/Fayetteville:

On May 10, 2006, Storm Cat closed a transaction in the Fayetteville Shale play in Arkansas.  Storm Cat acquired a 100% working interest in approximately 16,166 gross and 12,044 net acres in Van Buren, Pope and Searcy Counties, Arkansas.  Storm Cat owns a 100% working interest and an 80% net revenue interest in the leasehold.  Storm Cat has continued to lease in the area in order to consolidate and enhance the existing acreage block which now has 17,797 gross and 12,999 net acres.  The Company’s detailed geologic and engineering model has targeted as many as six initial locations to be drilled on its leasehold sometime during the second or third quarter of 2007.

Recent Developments

Joint Development Agreement

As previously disclosed, on September 14, 2006, Storm Cat entered into a JDA with an unaffiliated third party to jointly develop certain lands for CBM exploitation in the PRB.  Under the JDA, Storm Cat and its JDA partner will establish an AMI in which Storm Cat will act as Operator.  Storm Cat acquired an undivided 50% of its JDA partner’s working interest in existing wells, leasehold and infrastructure.  The Company will have the option to earn an undivided 50% interest in the JDA partner’s leasehold within the AMI through future development.

The JDA is an opportunity for the Company to acquire additional PRB leasehold interests adjacent or contiguous to the Company’s existing CBM development project in its core Northeast Spotted Horse operating area in Campbell County, Wyoming.  The proximity affords the Company the ability to increase its critical mass here and provides the opportunity to leverage its technical knowledge in multi-seam completion techniques while providing economies of scale associated with a larger project area.  The JDA is an extension of the Company’s current asset base and provides a foundation for future reserve and production growth in the area.  Storm Cat’s technical team has experience in developing CBM in the PRB and will use its expertise to efficiently exploit the leasehold while continuing to drive down exploration and development costs.

Subsequent to the signing of the JDA, Storm Cat has 60 days to evaluate and submit a plan of development to its JDA partner and will begin developing the properties upon the agreement of both parties.

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Results of Operations

Comparative Results of Operations for the Nine Months Ended September 30, 2006 and 2005

		Nine Months Ended September 30,
Selected Operating Data:		2006			2005
Net Sales Volume:
Natural Gas (MMcf)		828.9			480.5
Oil and Gas Sales (in thousands)
Natural Gas		$	5,060		$	2,853
Average Sales Prices:
Natural Gas (per Mcf)		$	6.10		$	5.94
Additional Data (per Mcf):
Gathering and Transportation		$	1.09		$	1.02
Lease Operating Expenses		$	1.80		$	2.53
Ad Valorem and Property Taxes		$	0.66		$	0.29
Depreciation, Depletion and Amortization Expense		$	2.18		$	1.97
General and Administrative, net of capitalization		$	3.68		$	4.24
Stock-based Compensation		$	2.70		$	—

 

Natural Gas Sales.  Natural gas sales revenue increased approximately 77.4% from $2.853 million in the first nine months of 2005 to $5.060 million for the same period in 2006.  Sales revenue is a function of sales volumes and average sales prices. Sales volumes increased 72.5% between periods.  The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year that produced new sales volumes that more than offset the natural decline in production.  The Company’s average price for natural gas increased 2.7% between periods.

Lease Operating Expenses.  Lease operating expenses increased approximately $0.279 million to $1.495 million in the first nine months of 2006 compared to $1.216 million the first nine months of 2005.  The increase resulted primarily from costs associated with new property acquisitions and drilling in the current year.  Lease operating expenses as a percentage of oil and gas sales decreased from 42.6% during the first nine months of 2005 to 29.5% during the first nine months of 2006 as lease operating cost increases did not keep pace with volume and sales price increases.  Lease operating expenses per Mcf decreased 28.7% from $2.53 during the first nine months of 2005 to $1.80 during the same period in 2006.

Ad Valorem and Property Taxes. Ad valorem and property taxes increased approximately $0.408 million to $0.548 million in the first nine months of 2006 compared to $0.139 million the first nine months of 2005.  The increase resulted primarily from gas volume increases over the past year.  Ad valorem and property taxes as a percentage of oil and gas sales increased from 4.9% during the first nine months of 2005 to 10.8% during the first nine months of 2006.  This increase is attributable to the Company’s decision in the current year to collect ad valorem tax in advance of payment.  Ad valorem and property tax per Mcf increased 128.5% from $0.29 during the first nine months of 2005 to $0.66 during the same period in 2006.

Depreciation, Depletion and Amortization. DD&A increased by $0.860 million to $1.807 million during the first nine months of 2006 compared to $0.947 million for the same period in 2005.  This increase resulted from increased production from recent acquisitions and an increase in the DD&A rate.  The per Mcf rate increased $0.21 from $1.97 in the first nine months of 2005 to $2.18 for the same period in 2006.  The components of DD&A expense were as follows (in thousands):

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		Nine Months Ended September 30,
		2006			2005
Depreciation		$	229		$	155
Depletion		1,578			792
Amortization		—			—
Depreciation, Depletion and Amortization		$	1,807		$	947

 

General and Administrative Expenses. The Company reports general and administrative expense net of capitalized overhead.  The components of general and administrative expense were as follows (in thousands):

		Nine Months Ended September 30,
		2006			2005
General and Administrative Expenses		$	4,621		$	2,370
Capitalized Overhead		(1,574		)	(333		)
General and Administrative Expense, net		$	3,047		$	2,037

 

General and administrative expense before capitalized overhead increased $2.251 million to $4.621 million during the initial nine months of 2006 compared to $2.370 million during the same period in 2005.  One of the largest components of the increase is attributed to salaries and related benefits and taxes which totaled $0.918 million in the nine months of 2006.  The increase in salaries was attributable to an increase in the employee base resulting from the Company’s continued growth.  Additionally, consulting fees increased by $0.244 million, public company and filing fees increased by $0.33 million, and bank fees increased by $0.575 million (primarily related to the amortized portion of up-front fees associated with the Company’s debt financing with JPMorgan, all of which were the result of growth and fund-raising activities in 2006).  The increase in capitalized overhead was caused by a combination of increases in the number of operated properties, new acquisitions, stepped-up drilling activity and the associated increased employee costs during the first nine months of 2006.

Comparative Results of Operations for the Three Months Ended September 30, 2006 and 2005

		Three Months Ended September 30,
Selected Operating Data:		2006			2005
Net Sales Volume:
Natural Gas (MMcf)		371.5			203.8
Oil and Gas Sales (in thousands)
Natural Gas		$	2,181		$	1,241
Average Sales Prices:
Natural Gas (per Mcf)		$	5.87		$	6.09
Additional Data (per Mcf):
Gathering & Transportation		$	0.92		$	1.08
Lease Operating Expenses		$	1.40		$	1.54
Production and Ad Valorem Taxes		$	0.47		$	0.32
Depreciation, Depletion and Amortization Expense		$	2.24		$	1.78
General and Administrative, net of capitalization		$	4.55		$	3.53
Stock-based Compensation		$	2.09		$	—

 

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Natural Gas Sales.  Natural gas sales revenue increased approximately $0.940 million to $2.181 million in the third quarter of 2006 compared to $1.241 million for the same quarter of 2005.  Sales revenue is a function of sales volumes and average sales prices.  Sales volumes increased 82.3% between periods.  The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year that produced new sales volumes that more than offset the natural decline in production.  The Company’s average price for natural gas decreased 3.6% between periods.

Lease Operating Expenses.  Lease operating expenses increased approximately $0.207 million to $0.520 million in the third quarter of 2006 compared to $0.313 million the third quarter of 2005.  The increase resulted primarily from costs associated with new property acquisitions and drilling in the current year.  Lease operating expenses as a percentage of oil and gas sales stayed relatively flat at 25.2% during the third quarter of 2005 compared to 23.8% for the same period in 2006.  On a per Mcf basis, lease operating expenses decreased slightly from $1.54 during third quarter of 2005 to $1.40 during the same period in 2006.

Ad Valorem and Property Taxes.  Ad valorem and property taxes increased approximately $0.107 million to $0.173 million in the third quarter of 2006 compared to $0.066 million the third quarter of 2005.  The increase resulted primarily from gas volume increases over the past year.  Ad valorem and property taxes as a percentage of oil and gas sales increased from 5.3% during the third quarter of 2005 to 7.9% for the same period in 2006.  This increase is attributable to the Company’s decision in the current year to collect ad valorem tax in advance of payment.  Ad valorem and property tax per Mcf increased 43.8% from $0.32 during third quarter of 2005 to $0.47 during the same period in 2006.

Depreciation, Depletion and Amortization. DD&A increased $0.472 million to $.834 million during the third quarter 2006 compared to $0.362 million for the same period in 2005.  This increase resulted from increased production from recent acquisitions and an increase in the DD&A rate.  The per Mcf rate increased $0.46 from $1.78 in the third quarter of 2005 to $2.24 for the same period in 2006. The Company revisited its DD&A calculation and increased the rate in the fourth quarter of 2005. The components of DD&A expense were as follows (in thousands):

Depreciation, Depletion and Amortization. DD&A increased $0.472 million to $.834 million during the third quarter 2006 compared to $0.362 million for the same period in 2005. This increase resulted from increased production from recent acquisitions and an increase in the DD&A rate. The Company revisited its DD&A calculation and increased the rate it was using in the fourth quarter of 2005. The per Mcf rate increased $0.46 from $1.78 in the third quarter of 2005 to $2.24 for the same period in 2006. The components of DD&A expense were as follows (in thousands):

		Three Months Ended September 30,
		2006			2005
Depreciation		$	168		$	69
Depletion		666			293
Amortization		—			—
Depreciation, Depletion and Amortization		$	834		$	362

 

General and Administrative Expenses.  The Company reports general and administrative expense net of capitalized overhead.  The components of general and administrative expense were as follows (in thousands):

		Three Months Ended September 30,
		2006			2005
General and Administrative Expenses		$	2,150		$	910
Capitalized Overhead		(460		)	(190		)
General and Administrative Expense, net		$	1,690		$	720

 

General and administrative expense before capitalized overhead increased $1.240 million to $2.150 million in the third quarter 2006 compared to $0.910 million the same period in 2005.  Salaries increased by $0.362 million between quarters, which is primarily attributable to an increase in the employee base due to continued growth.  Consulting increased $0.481 million and public company and filing fees increased $0.147 million between quarters.  The $.270 million increase in capitalized overhead between periods is attributable to a combination of increases in the number of operated properties, new acquisitions, stepped-up drilling activity and the associated increased employee costs during the current quarter.

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Forward Sales

The Company has entered into contracts to deliver and sell gas at the following prices.  The Company accounts for these as normal sales.

·      1,000/day sale for 1 yr for April 05 - March 06 at $6.95/MBtu for delivery at Cheyenne Hub. *

·      20,000/mo (666/day) sale for June 05 - March 06 at $6.34/MBtu for delivery at Cheyenne Hub. *

·      10,000/mo (333/day) sale for September 05 - March 06 at $9.10/MBtu for delivery at Cheyenne Hub. *

·      10,000/mo (333/day) sale for November 05 - October 06 at $8.31/MBtu for delivery at Cheyenne Hub.

·      30,000/mo (1,000/day) sale for April 06 - October 06 at $9.10/MBtu for delivery at Cheyenne Hub.

*  The forward sales asterisked above expired in the first quarter 2006

Firm Transportation Commitments

The Company has a firm transportation agreement in place through April 11, 2013 to transport gas from Cheyenne Plains to ANR PEPL (Oklahoma).  The agreement calls for the Company 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 gathering charges for volumes shipped on the Cheyenne Plains pipeline to the ANR PEPL (Oklahoma) delivery hub.  Storm Cat has sold its 2,000 Dth/D capacity commitment for a period of sixteen months (from November 2006 through February 2008) at the full rate and volume commitment.

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

Commodity Swaps

On July 21, 2006, Storm Cat entered into a commodity swap cash settlement transaction.  The outstanding quantity committed to the swap as of September 30, 2006 is 1.5 MMBtu’s per day beginning October 1, 2006 through July 9, 2009.  The total quantity is 1,552.5 MMBtu’s.  The fixed price in the agreement is $7.16 per MBtu (CIG pricing).

On August 29, 2006, Storm Cat entered into a second commodity swap cash settlement transaction.  The outstanding quantity committed to the second swap as of September 30, 2006 is 2.0 MMBtu’s per day beginning October 1, 2006 through August 31, 2009.  The total quantity is 2,132.0 MMBtu’s.  The fixed price in the agreement is $7.27 per MBtu which is CIG pricing.

Outstanding Share Data

As of September 30, 2006, the Company had 80,403,570 shares issued and outstanding. There are 8,923,368 share purchase, finder fee and agent warrants outstanding.  There are currently 5,205,000 common share options outstanding under the Company’s Amended and Restated Share Option Plan and Restricted Share Unit Plan.  The total amount of common shares reserved for issuance under the plans as of September 30, 2006 is 10,000,000 common shares.

During the nine months ended September 30, 2006, the following warrants and options were exercised (in U.S. Dollars):

·              753,906 warrants for gross proceeds of $1,297,034

·              227,500 options for gross proceeds of $139,321

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