UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For The Fiscal Year Ended December 31, 2006

OR

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

For the transition period from          to          

Commission File No. 001-32628

STORM CAT ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

British Columbia, Canada

 

06-1762942

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer 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

Securities registered under Section 12(b) of the Act: Common Shares, without par value

Securities registered under to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  o    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  o    No  x

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

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.

Large accelerated filer  o

 

Accelerated filer  x

 

Non-accelerated filer  o

 

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

As of June 30, 2006, the aggregate market value of voting stock held by non-affiliates of the registrant was approximately $148,597,821, based on the closing price of the Common Shares on the American Stock Exchange of $2.23 per share. As of March 14, 2007, 80,479,820 shares of registrant’s Common Shares, without par value, were issued and outstanding.

 

 




STORM CAT ENERGY CORPORATION

DOCUMENTS INCORPORATED BY REFERENCE

Pursuant to Instruction G (3) to Form 10-K, Items 10, 11, 12, 13 and 14 are omitted because the Company will file a definitive proxy statement (the “Proxy Statement”) pursuant to Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days after the close of the fiscal year. The information required by such items will be included in the Proxy Statement to be so filed for the Company’s annual meeting of shareholders to be held on or about June 20, 2007 and is hereby incorporated by reference.

2




TABLE OF CONTENTS

ITEM

 

 

 

 

PART I

Item 1.

 

Business

 

 

General

 

 

History

 

 

Recent Developments

 

 

Business Strategy

 

 

Acquisition, Exploration and Development Activities

 

 

Capital Expenditures

 

 

Principal Products or Services and Markets

 

 

Competition and Regulation

 

 

Environmental Regulation

 

 

Employees

 

 

Available Information

Item 1A

 

Risk Factors

Item 1B.

 

Unresolved Staff Comments

Item 2

 

Properties

 

 

General

 

 

Natural Gas Properties

 

 

Accounting for Natural Gas Properties

 

 

2007 Capital Budget

 

 

Company Reserve Estimates

 

 

Volumes and Prices

 

 

Total Acreage

 

 

Productive Wells and Developed Acreage

 

 

Undeveloped Acreage

 

 

Drilling Activity

 

 

Insurance

 

 

Facilities

Item 3.

 

Legal Proceedings

Item 4.

 

Submission of Matters to a Vote of Security Holders

 

 

 

 

 

PART II

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Item 6.

 

Selected Financial Data

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

Item 8.

 

Financial Statements and Supplementary Data

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A.

 

Controls and Procedures

Item 9B.

 

Other Information

 

3




 

 

 

 

 

PART III

Item 10

 

Directors and Executive Officers of the Registrant

Item 11.

 

Executive Compensation

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13.

 

Certain Relationships and Related Transactions

Item 14.

 

Principal Accounting Fees and Services

 

 

 

 

 

PART IV

Item 15.

 

Exhibits and Financial Statement Schedules

 

 

Signatures

 

 

Consent of Independent Registered Public Accounting Firm (Hein)

 

 

Consent of Independent Registered Public Accounting Firm (Amisano)

 

 

Consent of Independent Reservoir Engineers (Sproule)

 

 

Consent of Independent Reservoir Engineers (Netherland-Sewell)

 

 

Certification by CEO Under Section 302

 

 

Certification by CFO Under Section 302

 

 

Certification by CEO and CFO Under Section 906

 

4




FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included in this Annual Report on Form 10-K, other than statements of historical facts, address matters that the Company reasonably expects, believes or anticipates will or may occur in the future. Forward-looking statements may relate to, among other things:

·                  the Company’s future financial position, including working capital and anticipated cash flow;

·                  amounts and nature of future capital expenditures;

·                  operating costs and other expenses;

·                  wells to be drilled or reworked;

·                  oil and natural gas prices and demand;

·                  existing fields, wells and prospects;

·                  diversification of exploration;

·                  estimates of proved oil and natural gas reserves;

·                  reserve potential;

·                  development and drilling potential;

·                  expansion and other development trends in the oil and natural gas industry;

·                  the Company’s business strategy;

·                  production of oil and natural gas;

·                  effects of federal, state and local regulation;

·                  insurance coverage;

·                  employee relations;

·                  investment strategy and risk; and

·                  expansion and growth of the Company’s business and operations.

Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Disclosure of important factors that could cause actual results to differ materially from the Company’s expectations, or cautionary statements, are included under “Risk Factors” and elsewhere in this Annual Report on 10-K, including, without limitation, in conjunction with the forward-looking statements. The following factors, among others that could cause actual results to differ materially from the Company’s expectations, include:

·                  unexpected changes in business or economic conditions;

·                  significant changes in natural gas and oil prices;

·                  timing and amount of production;

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

·                  changes in overhead costs; and

·                  material events resulting in changes in estimates.

All forward-looking statements speak only as of the date made. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on the Company’s behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of anticipated or unanticipated events or circumstances.

Note Regarding Reserves Data and Other Oil and Gas Information

National Instrument 51-101 (“NI 51-101”) of the Canadian Securities Administrators imposes oil and gas disclosure standards for Canadian public companies engaged in oil and gas activities. NI 51-101 and its companion policy specifically contemplate the granting of exemptions from some of the disclosure standards prescribed by NI 51-101 to companies that are active in the U.S. capital markets, to permit the substitution of the standards required by the United States Securities and Exchange Commission (“SEC”) in order to provide for comparability of oil and gas disclosure with that provided by U.S. and other international issuers.  Storm Cat has submitted an

5




application to the Canadian securities regulatory authorities for an exemption that would permit it to provide oil and gas disclosure in Canada in accordance with the relevant legal requirements of the SEC.  Storm Cat has provided the reserves data and other oil and gas information included in this Annual Report on Form 10-K in accordance with U.S. disclosure requirements and practices and has filed in Canada, and will continue to file in Canada until such time as an exemption is approved by Canadian securities regulatory authorities, a separate NI 51-101 report. The information disclosed in this Annual Report, as well as the information that Storm Cat discloses in the future in SEC filings, may differ from the corresponding information prepared in accordance with NI 51-101 standards.

The primary differences between the U.S. requirements and the NI 51-101 requirements are that (1) the U.S. standards require disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves, and (2) the U.S. standards require that the reserves and related future net revenue be estimated under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made, whereas NI 51-101 requires disclosure of proved reserves and the related future net revenue estimated using constant prices and costs as of the effective date of the estimation, and of proved and probable reserves and related future net revenue using forecast prices and costs. The definitions of proved reserves also differ, but according to the Canadian Oil and Gas Evaluation Handbook (the reference source for the definition of proved reserves under NI 51-101), differences in the estimated proved reserve quantities based on constant prices should not be material. Storm Cat concurs with this assessment.

Storm Cat has disclosed proved reserve quantities using the standards contained in SEC Regulation S-X, and the standardized measure of discounted future net cash flows relating to proved oil and gas reserves determined in accordance with United States Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities” (“SFAS 69”).

Under U.S. disclosure standards, reserves and production information is disclosed on a net basis (after royalties). The reserves and production information contained in this annual information form is shown on that basis.

Glossary of Natural Gas Terms

The following is a description of the meanings of some of the natural gas and oil industry terms used in this Annual Report on Form 10-K.

Bcf. Billion cubic feet of natural gas.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“CIG” Colorado Interstate Gas.  CIG is a major transporter of natural gas in the Rocky Mountain region. The Colorado Interstate Gas system is connected to nearly every major supply basin in the Rocky Mountains as well as production areas in the Texas Panhandle, western Oklahoma, western Kansas, and Wyoming.  Storm Cat’s PRB gas is priced off of CIG.

Completion. The installation of permanent equipment for the production of  natural gas  or oil.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production. Development well. A well drilled  within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dth. Decatherms.

Dth/D. Decatherms per day.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such

6




that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not  classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well.

Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease  assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage.  Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage.  The assignor usually retains a royalty or reversionary interest in the lease.  The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related  to the  same individual  geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Lead. A specific geographic area which, based on supporting geological, geophysical or other data, is deemed to have potential for the discovery of commercial hydrocarbons.

MBtu. Thousand British Thermal Units.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. One MMcf per day.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells, as the case may be.

Net feet of pay. The true vertical thickness of reservoir rock estimated to both contain hydrocarbons  and be capable of contributing to producing rates.

PRB. Powder River Basin.  The region covers Southeast Montana and Northern Wyoming and is approximately 120 miles East to West and 200 miles North to South.  Major cities in this area include Gillette and Sheridan, Wyoming.  Storm Cat operates only in Wyoming.

Present value of future net  revenues or present value or PV-10. The pre-tax present value of estimated  future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated  production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

7




Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities  such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A  specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved area. The part of a property to which proved reserves have been specifically attributed.

Proved developed oil and gas reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed  program has confirmed through production responses that increased recovery will be achieved.

Proved oil and gas reserves. The estimated quantities of crude oil, natural gas and natural gas liquids  which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions,  i.e., prices and costs as of the date the estimate is made.  Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test.  The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining  portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.  In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.  Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the  reservoir, provides support for the engineering analysis on which the project or program was based.  Estimates  of proved reserves do not include the following: (a) oil that may become  available from known reservoirs but is classified separately as “indicated additional reserves”;  (b) crude oil, natural gas and natural gas liquids, the  recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors;  (c) crude oil,  natural  gas and natural gas liquids that may occur in undrilled prospects; and (d) crude oil, natural gas and natural gas liquids  that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved properties. Properties with proved reserves.

Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.  Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled.  Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.  Proved undeveloped reserves may not include estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Service well. A well drilled or completed for the purpose of supporting production in an existing field.  Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

Spud.  The initial phase of drilling a well.

8




Unconventional resources/reserves. Reserves from fractured shales, coal beds and tight sand formations.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Unproved properties.  Properties with no proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

 

9




PART I

ITEM 1.         BUSINESS

We use the terms “Storm Cat”, “Company”, “we”, “us” and “our” to refer to Storm Cat Energy Corporation in this Annual Report on Form 10-K.

General

Storm Cat 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”), and non-operated producing wells in the Fayetteville Shale area of Arkansas.  Its primary exploration and development acreage is located in the United States and Canada.

History

The Company was incorporated under the laws of British Columbia, Canada on May 15, 2000 under the name “Toby Ventures Inc.”  It conducted an initial public offering in Canada and its shares began trading on the Canadian Venture Exchange (now the Toronto Stock Exchange) on November 15, 2001 under the symbol “SME.”   Since incorporation, the Company has been involved in the exploration of natural resource properties. It commenced active exploration and acquisition of mineral resource properties in 2000.  In late 2003, the Company decided to dispose, sell or abandon its mineral exploration interests and enter the oil and gas industry through the acquisition of interests in conventional, unconventional and coalbed methane gas projects.

Under a Special Resolution passed by its shareholders, the Company changed its name, effective January 30, 2004, to Storm Cat Energy Corporation. It adopted new Articles of Incorporation under the Business Corporations Act of British Columbia on May 21, 2004. In June 2004, the Company changed its authorized share capital to an unlimited number of common shares without par value. Prior to June 2004, the authorized share capital was 20,000,000 common shares without par value. Effective March 31, 2005, the Company undertook a two-for-one share split. All share and per share amounts included in this filing have been restated to give retroactive effect, as necessary, to the effect of the share split.

On October 3, 2005, Storm Cat also began trading its shares on American Stock Exchange (“AMEX”) under the symbol “SCU.”

Since the beginning of 2004, Storm Cat has concentrated its efforts on the oil and gas business. The Company’s business model consists of three strategies:  (1) acquiring producing properties with drilling prospects in focused basins in both the U.S. and Canada; (2) exploring areas of moderate risk; and (3) initiating higher risk projects.

Its primary source of financing for exploration and drilling programs has been through the net proceeds from private placements of common shares and warrants. Between 2004 and 2006, the Company raised a total of $71.0 million in connection with private equity offerings and the issuance of common shares pursuant to warrant exercises net of issuance costs.  Additionally, certain of its shares have “flow-through” rights which entitle the holders to tax deductions in Canada as a result of the Company’s exploration and development activities.

Recent Developments

On January 19, 2007, Storm Cat entered into a Series A Note Purchase Agreement for the private placement of Series A Subordinated Convertible Notes Due March 31, 2012 (the “Series A Notes”) in a total aggregate principal amount of $18.6 million, and a Series B Note Purchase Agreement for the private placement of Series B Subordinated Convertible Notes Due March 31, 2012 (the “Series B Notes”) in a total aggregate principal amount of $31.7 million.  The Series A Notes and the Series B Notes will be convertible into Storm Cat 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 Storm Cat may force 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.

10




On January 30, 2007, Storm Cat closed the private placement of Series A Notes.  The Series A Notes will mature on March 31, 2012, unless earlier converted, redeemed or repurchased.  The Series A Notes bear interest at a rate of 9 ¼% 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.

The closing on the Series B Notes is contingent upon the successful vote of shareholders approving the underlying common shares should the Series B Note be converted.  The shareholder vote is schedule for March 29, 2007. The Series B Notes bear the same interest rate and interest payment schedule as the Series A Notes.

Effective March 9, 2007, President and Chief Executive Officer J. Scott Zimmerman went on administrative leave from the Company.  Keith Knapstad, the Company’s Chief Operating Officer has assumed the duties of President and CEO.

Business Strategy

Storm Cat’s strategy includes four key elements: conducting exploitation programs that provide organic growth, making strategic acquisitions, controlling costs, and remaining financially flexible.

Conduct Exploitation Programs

The acquisitions of producing and undeveloped acreage in the Powder River Basin for $30.7 million and the acquisition of acreage in the Fayetteville Shale in Arkansas provide Storm Cat with a significant asset base from which to conduct exploration and development activities.  In 2007, Storm Cat expects to generate organic growth from its planned exploitation activities, including exploration and development, workovers and stimulation treatments.

Make Strategic Acquisitions

The Company pursues strategic acquisitions that meet its criteria for investment returns and that are consistent with its operational focus.  This enables Storm Cat to leverage its technical expertise and existing land and infrastructure positions.  In general, the Company’s recent acquisition plan has focused on acquisitions of properties that have substantial development drilling opportunities and undeveloped acreage.

Continue to Focus on Cost Control

Maintaining capital spending discipline and a focus on cost control are keystones of Storm Cat’s business philosophy.  The Company establishes budgets that generate discretionary cash flow in the Powder River Basin and it also explores in areas that have a good risk/reward potential. Another critical area of the Company’s cost control efforts is lease operating expenses.   As Storm Cat acquires additional acreage in the Powder River Basin, it can leverage the work force currently in place in Wyoming and drive costs down on a per MCF basis.  Storm Cat was able to reduce its lease operating expense per MCF by 42.9% from 2005 to 2006.

Maintain Financial Flexibility

Storm Cat seeks to maintain financial flexibility and sufficient liquidity to capitalize on opportunities as they arise and to support its capital drilling opportunities.  Hedging is an important part of the Company’s strategy to mitigate exposure to commodity price volatility. Storm Cat has a board-approved policy related to commodity hedging activities. As of March 3, 2007 the Company has hedged, an estimated 75% of its current production. The majority of its current hedges were executed in order to support the economics of recent acquisitions and to support the Company’s credit facility.

Acquisition, Exploration and Development Activities

To date, Storm Cat has spent approximately $72.0 million on acquisition, exploration and development (excluding capitalized overhead, lease rental costs and asset retirement obligations) as follows:

Powder River Basin

Approximately $47.0 million has been spent in the Powder River Basin on acquisitions, maintenance and drilling and completion as follows:

Acquisitions.  $30.7 million has been spent to acquire 25,200 gross and 17,000 net acres, over 80% of which is undeveloped.  This acreage contains 10.2 Bcf of proved reserves, 4.2 Bcf of which are proved

11




developed.  Gas production from this acquisition is approximately 6.6 Mmcf/d gross and 3.1 Mmcf/d net.  The prospect contains 81 total wells (55 operated), 64 of which are producing (46 operated).

An additional $1.2 million was spent to acquire 6,232 gross and 5,125 net acres in the Ford Ranch / Sheridan area.

Maintenance.  Approximately $1.3 million has been spent on roads, water upgrades and well work.

Drilling and Completion.  $13.5 million has been spent to drill and complete 86 wells, $1.5 to $2.0 million of which was spent on for permitting, staking and water management plans for the 2007 drilling program.

Fayetteville Shale Area of Arkansas

The Company has spent approximately $3.6 million in the Fayetteville area (Van Buren, Pope and Searcy Counties, Arkansas), $3.3 million of which was spent on acquisition costs.  Of the $3.3 million in acquisition costs, $2.6 million related to the acquisition of 16,364 gross acres (12,296 net) and $0.7 million related to an additional 3,638 gross acres (1,386 net).  The remaining $0.3 million in expenditures related to associated well costs and preparation expenses.

British Columbia, Canada (Elk Valley)

Storm Cat has spent approximately $13.8 million in Elk Valley, $11.0 million of which was spent to drill and complete two wells in 2005 and another five wells in 2006.  Additionally, approximately $2.8 million was spent on operating expenses including line projects, well preparation and approximately $1.2 million of which was for annual upkeep.

Alberta, Canada (Western Canadian Sedimentary Basin)

The Company has spent approximately $3.0 million in Alberta, $1.2 million of which was spent to acquire 11,625 gross/net acres in Redwater, Wetaskiwin and Wainright.  Another $1.8 million was spent on the drilling and completion of three wells.  Additionally, Storm Cat farmed out the drilling to two wells on its Cessford acreage and retained an overriding royalty until payout.

Alaska

In Alaska, the Company has spent approximately $3.8 million on drilling and acreage acquisitions.  Only one well has been drilled to date, and Storm Cat has postponed further development in Alaska until 2008 so that capital can be focused on other plays that are currently generating cash flow.

Saskatchewan, Canada (Moose Mountain)

Storm Cat has spent approximately $0.6 million in Moose Mountain to drill and complete three wells.  This property was impaired for a total of $1.9 million in 2006.

Mongolia

As of December 31, 2006, the Company had fully impaired its Mongolia property for a total of $2.2 million.

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Capital Expenditures

The following table summarizes capital expenditures made by Storm Cat with respect to its oil and gas operations during the periods indicated (expenditures include areas that have been impaired):

 

 

Year Ended December 31, 2006

 

 

 

United

 

 

 

 

 

 

 

In Thousands

 

States

 

Canada

 

Mongolia

 

Total

 

Acquisitions:

 

 

 

 

 

 

 

 

 

Producing properties

 

$

11,403

 

$

0

 

$

0

 

$

11,403

 

Undeveloped acreage

 

22,538

 

 

 

22,538

 

Total acquisitions

 

33,941

 

 

 

33,941

 

Exploration and development:

 

 

 

 

 

 

 

 

 

Land and seismic

 

4,926

 

923

 

 

5,849

 

Drilling, facilities and equipment

 

17,450

 

16,680

 

117

 

34,247

 

Capitalized overhead

 

1,104

 

926

 

 

2,030

 

Total exploration and development

 

23,480

 

18,529

 

117

 

42,126

 

Asset retirement obligations

 

866

 

317

 

 

1,183

 

Other property and equipment

 

72

 

73

 

 

145

 

Total capital expenditures

 

58,359

 

18,919

 

117

 

77,395

 

Dispositions

 

(950

)

 

 

(950

)

Net capital expenditures

 

$

57,409

 

$

18,919

 

$

117

 

$

76,445

 

 

 

 

Year Ended December 31, 2005

 

 

 

United

 

 

 

 

 

 

 

In Thousands

 

States

 

Canada

 

Mongolia

 

Total

 

Acquisitions:

 

 

 

 

 

 

 

 

 

Producing properties

 

$

6,918

 

$

 

$

 

$

6,918

 

Undeveloped acreage

 

1,814

 

 

 

1,814

 

Total acquisitions

 

8,732

 

 

 

8,732

 

Exploration and development:

 

 

 

 

 

 

 

 

 

Land and seismic

 

471

 

1,933

 

 

2,404

 

Drilling, facilities and equipment

 

9,283

 

3,328

 

618

 

13,229

 

Capitalized overhead

 

312

 

254

 

 

566

 

Total exploration and development

 

10,066

 

5,515

 

618

 

16,199

 

Asset retirement obligations

 

714

 

 

 

714

 

Other property and equipment

 

628

 

245

 

(56

)

817

 

Total capital expenditures

 

20,140

 

5,760

 

562

 

26,462

 

Dispositions

 

 

 

 

 

Net capital expenditures

 

$

20,140

 

$

5,760

 

$

562

 

$

26,462

 

 

 

 

Year Ended December 31, 2004

 

 

 

United

 

 

 

 

 

 

 

In Thousands

 

States

 

Canada

 

Mongolia

 

Total

 

Acquisitions:

 

 

 

 

 

 

 

 

 

Producing properties

 

$

1,267

 

$

0

 

$

0

 

$

1,267

 

Undeveloped acreage

 

166

 

 

457

 

623

 

Total acquisitions

 

1,433

 

 

457

 

1,890

 

Exploration and development:

 

 

 

 

 

 

 

 

 

Drilling, facilities and equipment

 

13

 

 

819

 

832

 

Capitalized overhead

 

 

 

 

 

Total exploration and development

 

13

 

 

819

 

832

 

Asset retirement obligations

 

79

 

 

 

79

 

Other property and equipment

 

 

34

 

56

 

90

 

Total capital expenditures

 

1,525

 

34

 

1,332

 

2,891

 

Dispositions

 

 

 

 

 

Net capital expenditures

 

$

1,525

 

$

34

 

$

1,332

 

$

2,891

 

13




Ending balances in each of  the Company’s unproved properties at December 31 are as follows:

In Thousands

 

2006

 

2005

 

Unproved Properties:

 

 

 

 

 

Wyoming

 

$

22,336

 

$

1,934

 

Alaska

 

4,883

 

801

 

Canada

 

23,126

 

5,514

 

Arkansas

 

4,528

 

 

Total Unproved Properties

 

$

54,873

 

$

8,249

 

 

Principal Products or Services and Markets

Storm Cat focuses its exploration activities on locating natural gas resources.   The principal markets for these commodities are natural gas transmission pipeline companies, utilities, refining companies and private industry end-users. Historically, nearly all of the Company’s sales have been to a few customers.  However, Storm Cat is not confined to, nor dependent upon, any one purchaser or small group of purchasers.  Accordingly, the loss of a single purchaser would not materially affect the Company’s business because there are numerous other purchasers in the areas in which Storm Cat sells its production.  For the years ended  December 31, 2006,  2005 and 2004,  purchases by the following companies exceeded 10% of the total natural gas revenues of the Company:

 

Percent of Production Purchased

 

 

 

For the Years Ended December 31,

 

 

 

2006

 

2005

 

2004

 

BP Energy

 

0.0

%

0.0

%

100

%

Enserco

 

75.5

%

79.9

%

0.0

%

OGE

 

13.1

%

0.0

%

0.0

%

Oneok

 

11.4

%

0.0

%

0.0

%

Competition and Regulation

The oil and gas industry is highly competitive. As a small independent, the Company must compete against companies with substantially larger financial, human and other resources in all aspects of its business.

Oil and gas drilling and production operations are regulated by various federal, state and local agencies. These agencies issue binding rules and regulations which carry penalties, often substantial, for failure to comply. The Company anticipates its aggregate burden of federal, state and local regulation will continue to increase, particularly in the area of rapidly changing environmental laws and regulations. The Company also believes that its present operations substantially comply with applicable regulations. To date, such regulations have not had a material effect on the Company’s operations, or the costs thereof. There are no known environmental or other regulatory matters related to the Company’s operations that are reasonably expected to result in material liability to the Company. Storm Cat does not believe that capital expenditures related to environmental control facilities or other regulatory matters will be material in the coming year.

14




The Company cannot predict what subsequent legislation or regulations may be enacted or what effect they might have on its business.

Environmental Regulation

Storm Cat’s operations are subject to government laws and regulations concerning pollution, protection of the environment and the handling and transport of hazardous materials in both the United States and Canada. These laws and regulations generally require the Company to remove or remedy the effect of its activities on the environment at present and former operating sites, including dismantling production facilities and remediating damage caused by the use or release of specified substances. The Company believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. While Storm Cat believes that it is in substantial compliance with applicable environmental laws and regulations in effect at the present time and that continued compliance with existing requirements will not have a material adverse impact on the Company, it cannot give any assurance that it will not be adversely affected in the future.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.  Under CERCLA, these “responsible persons” may be subject to joint and several liability for the costs of cleaning up the hazardous  substances that have been released into the  environment,  for damages to natural resources,  and for the costs of certain health studies,  and it is not uncommon for  neighboring  landowners  and other third parties to file claims for personal injury and property damage  allegedly  caused by the release of hazardous substances into the environment.  The Company may also incur liability under the Resource Conservation and Recovery Act, also known as “RCRA”, which imposes requirements relating to the management and disposal of solid and hazardous wastes.  While there exists an exclusion from the definition of hazardous wastes for “drilling  fluids,  produced  waters,  and other wastes  associated with the exploration,  development, or production of crude oil, natural gas or geothermal energy,” in the course of its operations,  the Company may generate  ordinary  industrial wastes,  including paint wastes, waste solvents,  and waste compressor oils that may be regulated as hazardous waste.

Storm Cat currently owns or leases, and has owned or leased in the past, properties that for a number of years have been used for the exploration and production of oil and gas.  Although the Company has utilized operating and disposal  practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the  properties  owned or leased by Storm Cat or on or under other  locations  where such wastes  have been taken for  disposal.  In addition, some of these properties may have been operated by third parties whose disposal or release of hydrocarbons or other wastes was not under the Company’s control.  These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws.  Under such laws, Storm Cat could be required to remove or remediate previously disposed wastes or property contamination or to perform remedial operations to prevent future contamination.

The Federal Water Pollution  Control Act of 1972, as amended,  also known as the “Clean  Water Act” and  analogous  state  laws  impose  restrictions  and strict controls  regarding the discharge of pollutants,  including  produced waters and other oil and gas  wastes,  into  state or  federal  waters.  The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the state.  The Clean Water Act provides civil and criminal penalties for any discharge of oil in harmful quantities and imposes liabilities for the costs of removing an oil spill.

The Clean Air Act, as amended (“CAA”), restricts the emission of air pollutants from many sources, including oil and gas operations.  New facilities may be required to obtain permits before work can begin,

and existing facilities may be required to incur capital costs in order to remain in compliance.  In addition, the EPA has promulgated more stringent regulations governing emissions of toxic air pollutants from sources in the oil and gas industry, and these regulations may increase the costs of compliance for some facilities.

Under the National  Environmental  Policy Act  (“NEPA”),  a federal  agency,  in conjunction  with a permit holder,  may be required to prepare an  environmental assessment or a detailed environmental impact statement, also known as an “EIS,” before  issuing  a permit  that may  significantly  affect  the  quality  of the environment.

15




Storm Cat expects to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed in the United States and Canada.  The Company accrues for its asset retirement obligation (“ARO”) liability according to SFAS 143 “Accounting for Asset Retirement Obligations”.  As of December 31, 2006 the Company’s total accrued ARO was $1,871,393.

Employees

At December 31, 2006, Storm Cat employed 27 people; 18 in its U.S. corporate office, six in its Canadian office, two in Wyoming and one in South Dakota.  The Company values its employees and offers competitive salaries and benefits in order to retain them.  As such, management believes that employee-employer relationships are good.

Available Information

Storm Cat’s corporate headquarters and executive offices are located at 1125 17th St., Suite 2310, Denver, Colorado 80202. Its telephone number is (303) 991-5070.  The Company’s Canadian registered office is located at 209 8th Avenue, Alberta, Canada, T2P 1B8. Its telephone number at the Canadian office is (403) 451-5070.

Shareholders can obtain official copies of material agreements and other documents at the Registered and Records Office of the Corporation at Storm Cat Energy Corporation, c/o Bull, Housser & Tupper, LLP, 3000 Royal Center, P. O. Box 11130, 1055 West Georgia Street, Vancouver, BC  Canada  V6E 3R3.  The telephone number of this location is (604) 687-6575.

The Company reports to the SEC information, including the Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are available free of charge on the Company’s website (www.stormcatenergy.com) as soon as reasonably practicable after the information is electronically filed with or furnished to the SEC. In addition, the Company’s Code of Ethics is available on its website. No content of the Company’s website is incorporated by reference herein. Copies of any materials the Company files with the SEC can be obtained at www.sec.gov or at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330.

Information and access to most public securities documents and information filed by public companies and investment funds with the Canadian Securities Administrators (CSA) can also be found at www.sedar.com. The statutory objective in making public this filed information is to enhance investor awareness of the business and affairs of public companies and investment funds and to promote confidence in the transparent operation of capital markets in Canada. Achieving this objective relies heavily on the provision of accurate information on market participants.

Additionally, in Canada, information concerning electronic disclosure of insider stock trades can be found at www.sedi.ca.  This website provides the equivalent to information filed on Form 4’s in the United States.

ITEM 1A.           RISK FACTORS

In evaluating the Company, careful consideration should be given to the following risk factors. These risks are not the only risks facing the Company.  Additional risks and uncertainties not currently known to Storm Cat or that it currently deems to be immaterial at present may become material in the future and affect its business, financial condition and/or operating results, as well as adversely affect the value of the Company’s common shares.

Risks Related to the Business

Price volatility may affect financial condition:  The prices of oil and natural gas are volatile and the Company’s operating results and future rate of growth depend heavily on prevailing market prices for these resources. A substantial or extended decline in prices for these resources would have a material adverse effect on the Company. These prices are affected by numerous factors beyond Storm Cat’s control, including international economic and political trends, the effects of inflation, currency exchange fluctuations, interest rates and global or regional consumption patterns, worldwide and domestic supplies of oil and gas, the ability of members of the Organization of Petroleum Exporting Countries (OPEC) to agree to and maintain oil price and production controls, actions of governmental authorities, the availability of transportation facilities, increased production due to new discoveries or improved recovery techniques and weather conditions.

Storm Cat operates in a highly competitive industry:  Storm Cat competes with other energy development companies for properties, equipment, materials and labor.  The industry is highly competitive in all aspects. Many of the Company’s competitors have larger operations and greater financial resources. Competition in Storm Cat’s business may adversely affect its ability to acquire properties, equipment and materials, attract

16




and retain qualified labor, and attract the necessary capital to sustain resource exploration and production in the future.

Oil and gas exploration is a speculative undertaking:  Oil and gas exploration is a speculative business. Storm Cat’s future success depends on our ability to economically locate oil and gas production and reserves in commercial quantities. The Company’s anticipated exploration and development activities are subject to reservoir and operational risks. Even when oil and gas is found in what are believed to be commercial quantities, reservoir risks, which may be heightened in new discoveries, may lead to higher costs and/or lower production than originally anticipated. These risks include the inability to sustain deliverability at commercially productive levels as a result of decreased reservoir pressures, large amounts of water, or other factors that might be encountered. The effects of these factors may result in Storm Cat not receiving an adequate return on investment capital.

Reserve quantities and values are subject to many variables and estimates and actual results may vary:  This Annual Report on Form 10-K contains estimates of the Company’s proved oil and natural gas reserves and the estimated future net revenues from those reserves. Any significant negative variance in these estimates could have a material adverse effect on the Company’s future performance.

Reserve estimates are based on various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data.

Reserve estimates are dependent on many variables, and therefore, as more information becomes available, it is reasonable to expect that there will be changes to the estimates. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by the Company. In addition, estimates of proved reserves will be adjusted in the future to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond the Company’s control.

As of December 31, 2006, approximately 46.6% of the Company’s estimated proved reserves are classified as proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is generally based on volumetric calculations rather than the performance data used to estimate reserves for producing properties. Recovery of proved undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Revenues from proved developed non-producing and proved undeveloped reserves will not be realized until some time in the future. The reserve estimate includes an estimate of the capital expenditures required to develop these reserves as well as the timing of such expenditures. Although the Company has prepared estimates of its proved undeveloped reserves and the associated development costs in accordance with industry standards, they are based on estimates, and actual results may vary.

The present value of estimated reserves, or PV-10, should not be interpreted as the current market value of reserves attributable to the Company’s properties. The 10% discount factor, which is required in calculating PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which the Company’s business or the oil and natural gas industry in general are subject. The Company has based the PV-10 on prices and costs as of the date of the reserve estimate, in accordance with applicable SEC regulations. Actual future prices and costs may be materially higher or lower. In addition to the price volatility factors discussed above, factors that will affect actual future net cash flows, include:

·      the amount and timing of actual production;

·      curtailments or increases in consumption by oil and natural gas purchasers; and

·      changes in governmental regulations or taxation.

As a result, the Company’s actual future net cash flows could be materially different from the estimates included in this Annual Report on Form 10-K.

The Company faces operating risks in its exploration and production activities:  Storm Cat’s business involves operating risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, leaks, fires, formations with abnormal pressures, pipeline ruptures or spills,

17




pollution, releases of toxic gas and other environmental hazards and risks, any one of which can cause personal injury, damage to property, equipment and the environment, as well as interruption of operations. Storm Cat maintains insurance against some, but not all, of these risks. If any of these events occurred, the Company could face substantial losses that could reduce or even eliminate funds available for operations.

The industry is highly regulated:  Storm Cat’s industry is heavily regulated by federal, state, and local authorities. These regulations control many aspects of its business including, among other things, land use, prospecting, the drilling and spacing of wells, protection of ground water, conservation of soil, safety standards, site reclamation, restoration, exports, labor standards, occupational health, waste disposal, toxic substances and other matters. The regulations and laws governing the industry are under constant review and may be amended or expanded. Regulation increases the cost of doing business and decreases profitability. If Storm Cat fails to comply with these laws and regulations, it may be subject to substantial penalties or suspension or termination of operations.

The Company’s operations are subject to complex environmental regulations:  Storm Cat’s current and anticipated future operations require permits from various federal, state and local governmental authorities and such operations are and will be regulated by laws and regulations governing various elements of the oil and gas industries.

The Company cannot predict what environmental legislation, regulation or policy will be enacted or adopted in the future or how in the future laws and regulations will be administered or interpreted. The recent trend in environmental legislation and regulation generally is toward stricter standards and this trend is likely to continue in the future. This recent trend includes, without limitation, laws and regulations relating to air and water quality, waste handling and disposal, the protection of certain species and the preservation of certain lands. These regulations may require permits or other authorizations for certain activities. These laws and regulations may also limit or prohibit activities on certain lands lying within wetland areas, areas providing for habitat for certain species or other protected areas. Compliance with more stringent laws and regulations, as well as potentially more vigorous enforcement policies or stricter interpretation of existing laws, may necessitate significant capital expenditures, may materially affect the results of operations and business, or may cause material changes or delays in the Company’s intended activities.

There can be no assurance that Storm Cat will be able to obtain all permits required for future exploration on reasonable terms or that such laws and regulations, or new legislation or modifications to existing legislation, will not have an adverse effect on any project that might undertaken. The Company’s failure to comply with applicable laws, regulations and permitting requirements may result in enforcement actions, including orders issued by regulatory or judicial authorities causing the Company’s operations to cease or be curtailed, and may include corrective measures requiring capital expenditures, installation of additional equipment or remedial actions.

Increases in taxes on energy sources may adversely affect the Company’s operations:  Federal, state and local governments which have jurisdiction in areas where the Company operates impose taxes on the oil and natural gas products sold. Historically, there has been on-going consideration by federal, state and local officials concerning a variety of energy tax proposals. Such matters are beyond the Company’s ability to accurately predict or control.

The Company does not have adequate cash flow to fund operations and additional debt or equity financing will be required:  The Company makes, and will continue to make, significant expenditures to find, acquire, develop and produce natural gas reserves. If natural gas prices decrease, or if operating difficulties are encountered that result in cash flow from operations being less than expected, the Company may have to reduce capital expenditures unless additional funds are raised through debt or equity financing. Debt or equity financing or cash generated by operations may not be available to the Company in sufficient amounts or on acceptable terms to meet these requirements.

Future cash flows and the availability of financing will be subject to a number of variables, such as:

·      the Company’s success in locating and producing new reserves;

·      the level of production from existing wells; and

·      prices of natural gas;

 

 

18




Issuing additional equity securities to satisfy the Company’s financing requirements could cause substantial dilution to existing shareholders. Additional debt financing could make the Company more vulnerable to competitive pressures and economic downturns.

Competition for materials and services is intense and could adversely affect the Company:  Major oil companies, independent producers, and institutional and individual investors are actively seeking oil and gas properties throughout the world, along with the equipment, labor and materials required to develop and operate properties. Shortages for equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. Many of the Company’s competitors have financial and technological resources which exceed those available to the Company.

The Company’s hedging arrangements involve credit risk and may limit future revenues from price increases:  To manage the Company’s exposure to price risks associated with the sale of natural gas, the Company periodically enters into hedging transactions for a portion of its estimated natural gas production. These transactions may limit the Company’s potential gains if natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose the Company to the risk of financial loss in certain circumstances, including instances in which:

·      the Company’s production is less than expected;

·      the contractual counterparties fail to perform under the contracts; or

·      a sudden, unexpected event, materially impacts natural gas prices.

The terms of the Company’s hedging agreements may also require that it furnish cash collateral, letters of credit or other forms of performance assurance in the event that mark-to-market calculations result in settlement obligations by the Company to the counterparties, which would encumber the Company’s liquidity and capital resources.

In addition, hedging transactions using derivative instruments involve basis risk. Basis risk in a hedging contract occurs when the index upon which the contract is based is more or less variable than the index upon which the hedged asset is based, thereby making the hedge less effective.

The Company has minimized ineffectiveness by entering into gas derivative contracts indexed to Colorado Interstate Gas (“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.

The marketability of the Company’s natural gas production is dependent upon infrastructure, such as gathering systems, pipelines and processing facilities, that the Company does not own or control:  The marketability of the Company’s natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities necessary to move the Company’s natural gas production to market. The Company does not own this infrastructure and is dependent on other companies to provide it.

Storm Cat has a history of net losses and a current working capital deficit:  Since Storm Cat’s incorporation in May of 2000, it has experienced annual net losses.  In the year ended December 31, 2006 the Company had a net loss of $6.9 million and its cumulative net loss from date of incorporation to December 31, 2005 is $16.6 million. There is no guarantee as to when, if ever, the Company will realize a net profit.  At December 31, 2006 the Company had a working capital deficit of $15.6 million as the result of a delay in its convertible notes financing.

Fluctuations in foreign currency exchange rates could adversely affect the business:  Storm Cat maintains accounts in U.S. and Canadian dollars. A material decrease in the value of the Canadian dollar relative to the U.S. dollar could negatively impact the Company’s income statement and share price.

Storm Cat depends on certain key personnel:  The Company depends heavily on the business and technical expertise of its management and key personnel.  There is little possibility that this dependence will decrease in the near term. The Company carries no “key man” life insurance on any of its executives. As operations expand, Storm Cat will require additional key personnel and related resources.

Some of Storm Cat’s directors serve as officers and directors of other companies:  Some of the Company’s directors are also officers or directors of other companies including those that are similarly engaged in the business of acquiring, developing and exploiting oil and gas producing properties. Such associations may give rise to conflicts of interest from time to time. The Company’s directors are required by law to act honestly, in good faith and in the best interest of Storm Cat and to disclose any interest that

19




they may have in any competing project or opportunity. Further, Storm Cat has an internal conflict policy (“Code of Business Conduct and Ethics”) which addresses directors’ conflicts of interest. Under the policy, if a conflict of interest arises at a meeting of the Board, any director with a conflict must disclose his interest and abstain from voting on such matters. In making the determination as to whether or not the Company will participate in any project or opportunity, the directors will primarily consider the degree of risk to it and Storm Cat’s financial position at that time.

Storm Cat focuses heavily on unconventional plays, which rely on technological advances that in the future may not be effective:  Unconventional resources are reserves from fractured shales, coal beds and tight sand formations and they are a central element of Storm Cat’s business model.  The development of typical unconventional plays may involve greater extraction and retrieval costs than are involved in development of typical conventional plays.  Often, the quality of gas and commercial viability is less known in a typical unconventional play.  Therefore, the process of developing an unconventional play involves significant expenditures before commercial viability can be ascertained and presents a risk of cost overruns and inadequate gas recovery.

Further, technological innovation is a key component to realizing the economic value of unconventional plays.  The Company continues to explore and rely on advances in technologies such as drilling, well completion and geophysical technologies that have helped the viability of the unconventional play.

Storm Cat may incur compression difficulties and expense:  As production increases, more compression is generally required to maximize the production flowing through the pipeline. Production costs increase as additional compression is required, primarily because the compression process requires more fuel.  In addition, the compression process is a mechanical process, and should a breakdown occur the Company will be unable to deliver gas until repairs to the machinery are completed.

Storm Cat does not obtain title insurance or other warranties of title with its leases and working interests:  Storm Cat does not obtain title insurance or other guaranty or warranty of good title with its gas leases and well working interests. Title insurance is not available for subsurface leases. Accordingly, third parties may assert claims against the Company’s legal entitlement to the gas leases and working interests being acquired, irrespective of the Company’s leases and working well interests. In order to alleviate this risk, Storm Cat requires a title search and title opinion on all leases prior to drilling. There is no assurance, however, that all title defects will be cured prior to drilling.

Risks Related to Storm Cat’s Common Shares

U.S. Investors may have difficulty effecting service of process against some of Storm Cat’s Canadian directors:  Storm Cat is incorporated under the laws of the Province of British Columbia, Canada. Consequently, it may be difficult for United States investors to effect service of process in the United States upon its directors or officers who are not residents of the United States, or to realize in the United States upon judgments of United States courts predicated upon civil liabilities under the Exchange Act. A judgment of a U.S. court predicated solely upon such civil liabilities would probably be enforceable in Canada by a Canadian court if the U.S. court in which the judgment was obtained had jurisdiction, as determined by the Canadian court, in the matter. There is substantial doubt whether an original action could be brought successfully in Canada against any of such persons or Storm Cat predicated solely upon such civil liabilities.

Storm Cat was previously a “Foreign Private Issuer” and exempt from the Section 16 and the Proxy Rules of Section 14 of the Securities Exchange Act of 1934:  On June 30, 2006, the Company became a U.S. issuer under the U.S. federal securities laws.  As such, it is subject to certain regulation under U.S. securities laws, such as Section 16 and the Proxy Rules of Section 14 of the Exchange Act. Prior to June 30, 2006, as a foreign private issuer, Storm Cat filed its Annual Report on Form 20-F and reported its current events, including the dissemination of proxy materials and information regarding its annual meeting of shareholders, on Form 6-K.

Storm Cat is subject to the Continued Listing Criteria of the American Stock Exchange (“AMEX”) and the Toronto Stock Exchange (“TSX”):  Storm Cat’s common shares are listed on AMEX and the TSX.

In order to maintain its listing on AMEX, Storm Cat must maintain certain share prices, financial and distribution targets, including maintaining a minimum amount of shareholders’ equity and a minimum number of public shareholders. In addition to objective standards, AMEX may delist the securities of any issuer if in its opinion, the issuer’s financial condition and/or operating results appear unsatisfactory; if it appears that the extent of public distribution or the aggregate market value of the security has become so

20




reduced as to make further dealings on AMEX inadvisable; if the issuer sells or disposes of principal operating assets or ceases to be an operating company; if an issuer fails to comply with AMEX’s listing requirements; if an issuer’s common shares sell at what AMEX considers a “low selling price” and the issuer fails to correct this via a reverse split of shares after notification by AMEX; or if any other event shall occur or any condition shall exist which makes further dealings with AMEX, in its opinion, unadvisable.

Similarly, if the Company fails to meet any of the continued listing criteria of the TSX or is not in compliance with all TSX requirements applicable to listed companies, including TSX rules, policies, rulings and procedural requirements and any additions or amendments which may be made thereto from time to time, the TSX may delist the Company’s securities.  Without limiting the generality of the foregoing, the TSX requires that Storm Cat: (i) not issue any securities without the prior consent of the TSX; (ii) not undergo a material change in its business or affairs without the prior consent of the TSX; (iii) file copies of all written correspondence sent to holders of its listed securities with the TSX; (iv) not change the provisions attaching to any warrants, rights or other  out standing  securities without the prior consent of the TSX; (v) pay all applicable TSX fees; and (vi)  file, at any time upon demand, such other information or documentation concerning the Company’s business and affairs as the TSX may reasonably require.

The TSX has the right, at any time, to halt or suspend trading in any of listed securities with or without notice and with or without giving any reason for such action, or to delist such securities, provided that the TSX will not delist the securities without providing the Company with an opportunity to be heard.

If AMEX or the TSX delists Storm Cat’s common shares, investors may face material adverse consequences, including, but not limited to, a lack of trading market for its securities, decreased analyst coverage of its securities, and an inability for the Company to obtain additional financing to fund operations.

Storm Cat’s common shares are traded on more than one market and this may result in price variations:  Storm Cat’s common shares are traded on AMEX and on the TSX. Trading in the Company’s common shares on these markets is effected in different currencies (U.S. dollars on AMEX and Canadian dollars on the TSX) and at different times, as the result of different time zones, different trading days and different public holidays in the United States and Canada. Consequently, the trading prices of Storm Cat’s common shares on these two markets often differ, resulting from the factors described herein as well as differences in exchange rates and from political events and economic conditions in the United States and Canada. Any decrease in the trading price of the Company’s common shares on one of these markets could cause a decrease in the trading price of its common shares on the other market.

Storm Cat’s share price has fluctuated and could continue to fluctuate significantly:  The market price for Storm Cat’s common shares, as well as the price of shares of other energy companies, has been volatile. Numerous factors, many of which are beyond the Company’s control, may cause the market price of its common shares to fluctuate significantly, such as:

·                                          Fluctuations in the Company’s quarterly revenues and earnings and those of its publicly held competitors;

·              Shortfalls in operating results from levels forecast by securities analysts;

·              Announcements concerning the Company or its competitors;

·              Changes in pricing policies by the Company or its competitors;

·              General market conditions and changes in market conditions in the industry; and

·              The general state of the securities market.

In addition, trading in shares of companies listed on AMEX and the TSX, generally, and trading in shares of energy companies, specifically, has experienced price and volume fluctuations that have often been unrelated or disproportionate to operating performance. These broad market and industry factors may depress the Company’s share price, regardless of actual operating results. In addition, if Storm Cat issues additional shares in financings or acquisitions, its shareholders will experience additional dilution and the existence of more shares could decrease the amount that purchasers are willing to pay for the Company’s common shares.

21




ITEM 1B.               UNRESOLVED STAFF COMMENTS

None.

ITEM 2.              PROPERTIES

General

Storm Cat 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.  Its primary exploration and development acreage is located in the United States and Canada. 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 to find, drill, complete and operated in unconventional reservoirs.

22




Natural Gas Properties

Powder River Basin

On May 5, 2006, Storm Cat closed a mineral leasehold transaction in the Powder River Basin, Campbell County, Wyoming, with two private companies.  The acquisition included an interest in 3,942 gross (3,548 net) undeveloped acres.  As consideration, 50% was paid in cash at closing and the private companies retained a carried interest as to capital costs covering their 10% working interest to be paid over a period of 18 months after closing.

On June 7, 2006, Storm Cat acquired six state tracts in Sheridan County, Wyoming totaling 1,521 gross (and net) acres at a Wyoming State Lease Sale for $0.7 million lease bonus (average of $458/acre).  Development preparation has begun on the acreage including permitting of locations and water management planning.  Development should consist of 19 multi-seam wells.

On August 29, 2006, but effective as of July 1, 2006, the Company acquired producing leases totaling 25,200 gross acres and 17,000 net acres for $30.7 million.  The production from this field represented 26.4% of 2006 production volumes and 22.9% of 2006 natural gas revenue, and the reserves attributable to this acquisition comprise approximately 44.6% of estimated proved reserves as of December 31, 2006.

On September 14, 2006, Storm Cat entered into a Joint Development Agreement with an unaffiliated third party to jointly develop certain lands for coalbed methane.  Under this agreement, Storm Cat and its partner will establish an area of mutual interest in which Storm Cat will act as operator.  The Company acquired an undivided 50% of its 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 its partner’s leasehold within the area of mutual interest through development.

At December 31, 2006, Storm Cat had operational control of approximately 41,730 gross acres and 31,905 net acres.  The Company was operating 277 wells and owned a working interest percentage in 41 additional non-operated wells.  For the full year 2006, 86 wells were spud.  Wells drilled during 2006 were concentrated in our Northeast Spotted Horse and Jamison/Twenty Mile operating areas.

At year-end 2006, the Powder River Basin exit-rate production was 15 MMcf/d gross and 8 MMcf/d net.  The Powder River Basin production currently comprises 100% of Storm Cat’s production.

23




Fayetteville Shale Area of Arkansas

On May 10, 2006, Storm Cat closed a $2.0 million transaction in the Fayetteville Shale play in Arkansas with two private operators.  The Company acquired an interest in approximately 16,364 gross undeveloped acres and 12,596 net acres in Van Buren, Pope and Searcy Counties, Arkansas at a cost per net mineral acre of $165.

In the Arkoma Basin’s Fayetteville Shale play in Arkansas, the Company owned or controlled 20,051 gross and 13,982 net acres at December 31, 2006.  This property consists of an 80% net revenue interest in 16,364 gross (12,596 net) acres and an 81% net revenue interest in 3,688 gross (1,386 net) acres in the Fayetteville Shale Prospect area of Arkansas (mostly in Van Buren County).  Storm Cat plans to commence drilling on the first of six net wells in the Fayetteville Shale beginning mid-year 2007.

At year-end 2006, Storm Cat was participating in 14 (non-operated) Fayetteville Shale wells where it owned between a 1% and 8% working interest.  These wells were at various stages of planning, drilling, completion or production.

24




British Columbia, Canada (Elk Valley)

In Elk Valley, British Columbia, Storm Cat farmed-in on approximately 77,775 gross (77,775 net) acres on an unconventional natural gas prospect. On October 31, 2006, the Company assumed 100% operatorship of the Elk Valley land and the former operator retained a 2.5% overriding royalty interest.  During 2006, the Company drilled and completed five wells in Elk Valley.  These wells are currently on production and have begun the de-watering stage.  Storm Cat expects to have preliminary production results from these wells during the second half of 2007.

Alberta, Canada (Western Canadian Sedimentary Basin)

In the Western Canadian Sedimentary Basin of Alberta, Canada, Storm Cat owned or controlled approximately 19,693 gross acres and 17,453 net acres at December 31, 2006.  Efforts have been focused

25




on evaluating the potential of the Horseshoe Canyon and Mannville Coals.  Horseshoe Canyon has been established as a commercial production target in the Western Canadian Sedimentary Basin, while the Mannville Coals are still in the early stages of development.  During the course of 2006, Storm Cat experienced a greater than eight-fold increase in its undeveloped acreage position from a starting point of 2,080 acres (gross and net).  In 2006, five gross wells were drilled.  This total includes two wells drilled at no cost to the Company through a farm out of its interest in two sections of land.

The Alberta, Canada acreage is concentrated in five main areas.  From north to south these are Judy Creek, Redwater, Wetaskiwin, Wainwright and Cessford.  The Wetaskiwin area is prospective for gas from the Horseshoe Canyon and the Mannville Coals while the other areas are all prospective for gas from the Mannville Coals.

During 2006, Storm Cat participated in the drilling of three wells in the Cessford area on a drill-to-earn farm-out deal.  Two of the wells were drilled at no cost to the Company.  The first well drilled was a vertical test which targeted a Lower Mannville Channel sand as well as the Mid Mannville Coal.  The channel sand was wet, and the well was completed uphole in the Mannville Coal section.  A core was cut through the coals.  Subsequent analysis showed significant quantities of gas in place, which led to the decision to begin horizontal development drilling.  The remaining four earning wells have been farmed out to a third party.  Two of the wells have been drilled, and the remaining two earning wells are scheduled to be drilled in the first and second quarters of 2007.

During the fourth quarter of 2006, Storm Cat drilled a 1,450 meter vertical test in the Judy Creek area to evaluate the potential of the Mannville coals as well as unconventional targets in the Colorado Shale.  The coals encountered were deemed to be too thin to follow up with horizontal wells.

Storm Cat drilled a 760 meter vertical well in the Wetaskiwin area that was designed to test the gas potential of the Horseshoe Canyon Coal as well as conventional targets in the Belly River and Edmonton Sand.  The well encountered gas pay in both the Upper Belly River Sand and the Horseshoe Canyon.  Based on these results, the Company has entered into a drill-to-earn deal to earn a 100% working interest in four sections of land subject to a non-convertible overriding royalty.  Storm Cat will earn an interest in one section with each well drilled.  Tie-in options are currently being evaluated.

Alaska

The Company has an 89.5% net revenue interest in 11,782 gross (11,782 net) acres and an 87.5% net revenue interest in 12,723 gross (12,723 net) acres in the Cook Inlet region of Alaska.  Storm Cat drilled one well in this area in 2006.  The Company is in the process of evaluating the completion potential and costs based upon equipment availability.

26




Saskatchewan, Canada (Moose Mountain)

Storm Cat previously owned a 30% working interest in the Moose Mountain exploration project in Saskatchewan, covering 235,830 gross acres of unconventional natural gas exploration.  Storm Cat 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.  The Company sold its working interest in this property to avoid plugging and abandonment costs, but retained a 1% overriding royalty interest.

Mongolia

As of December 31, 2006, Storm Cat had fully impaired our Mongolia property for a total of $2.2 million.

Accounting for Natural Gas Properties

Storm Cat follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves.  Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost, or estimated fair value if lower, of unproved properties.  Should capitalized costs exceed this ceiling, an impairment would be recognized.

Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company’s overall value.  These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company’s proved properties.

Estimating accumulations of gas is complex and is not exact because of the numerous uncertainties inherent in the process.  The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data.  The accuracy of the decline analysis method generally increases with the length of the production history. Since most of the Company’s wells have been producing less than five years, their production history is relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company’s estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company’s wells are produced over time and more data is available, the estimated proved reserves will be re-determined on an annual basis and may be adjusted based on that data.

Actual  future  production, gas prices,  revenues,  taxes,  development expenditures,  operating  expenses and  quantities  of  recoverable  gas reserves most likely will vary from the  Company’s  estimates.  Any significant variance could materially affect the quantities and present value of the Company’s reserves. For example, a decrease in price of 10% per Mcf for natural gas would  result in a  decrease  in the Company’s December  31, 2006  present  value of future  net cash  flows of  approximately $2.0 million.  In addition, the Company may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of exploration  and  development  and prevailing gas prices.  The Company’s reserves may also be susceptible to drainage by operators on adjacent properties.

2007 Capital Budget

Storm Cat intends to announce its 2007 capital expenditure program in first quarter 2007.  The Company continues to grow production and leasehold in its core Powder River Basin operating area.  The Powder River Basin continues to provide opportunity for increased production as Storm Cat continues to successfully apply multi-seam completion technology to its drilling operations, resulting in increasing cash

27




flow for the Company and its shareholders. Storm Cat has successfully drilled five wells in Elk Valley which continues to be a focused area to the Company for future growth. The Fayetteville Shale acquisition and Cessford project are especially important, allowing the Company to have access to data as a working interest partner in the wells with limited financial exposure. Storm Cat will use this data to help refine its 2007 program in these areas.

For additional information regarding current year activities, including gas production, refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Company Reserve Estimates

Netherland, Sewell & Associates, Inc. of Houston, Texas, an independent petroleum engineering firm, estimated proved reserves for the Company’s properties.  At December 31, 2006, natural gas from the Powder River Basin represented 100% of total reserves.

The following table sets forth information regarding the Company’s proved reserves at the end of each year for 2004 through 2006.  Reserve estimates are based on the assumptions set forth in Note 17 to the Consolidated Financial Statements and additional reserve information is provided. The year-end price used to calculate estimated future net revenues was $4.46, $7.72, and $5.90 per Mcf of gas at December 31, 2006, 2005 and 2004, respectively. Prices are based on Rocky Mountain CIG on the last sales day of each year.  Amounts do not include estimates of future Federal and state income taxes.

 

 

 

 

 

Estimated Future

 

 

 

 

 

Estimated

 

Net Revenues

 

 

 

Gas

 

Net Revenues

 

Discounted at 10%

 

Year

 

(MMcf)

 

(In Thousands)

 

(In Thousands)

 

 

 

 

 

 

 

 

 

2006

 

25,015.3

 

$

41,944.7

 

$

32,036.4

 

2005

 

10,010.0

 

37,461.0

 

29,017.2

 

2004

 

458.2

 

1,011.3

 

807.0

 

 

The percentage of total reserves classified as proved developed was approximately 53.4% in 2006, 38.7% in 2005 and 47.9% in 2004.

Volumes and Prices

The Company’s net production quantities and average price realizations per unit for the indicated years are set forth below. Price realizations are net of any hedging gains or losses.

 

2006

 

2005

 

2004

 

Product

 

Volume

 

Price

 

Volume

 

Price

 

Volume

 

Price

 

Gas (Mmcf)

 

1,606.2

 

$

5.88

 

693.5

 

$

6.08

 

17.3

 

$

6.01

 

 

Average production costs, including production taxes, per equivalent Mcf of were $3.34, $4.70, and $2.49 per Mcf in 2006, 2005, and 2004, respectively.

 

28




Total Acreage

Storm Cat Energy Corporation Acreage as of December 31, 2006

Area

 

Gross Acres

 

Net Acres

 

Powder River Basin, WY

 

 

 

 

 

Northeast Spotted Horse

 

6,320

 

5,950

 

Jamison

 

723

 

651

 

20 Mile

 

760

 

684

 

Ford Ranch (Focus + Ellbogen/Westbrook Leases)

 

4,711

 

3,604

 

Sheridan (State Lease Sale)

 

1,521

 

1,521

 

Recluse

 

25,200

 

17,000

 

North Recluse

 

2,495

 

2,495

 

Total

 

41,730

 

31,905

 

 

 

 

 

 

 

Fayetteville Shale, AR

 

 

 

 

 

Jordan Acquisition

 

16,364

 

12,596

 

Subsequent Lease Purchases

 

3,688

 

1,386

 

Total

 

20,052

 

13,982

 

 

 

 

 

 

 

Cook Inlet, AK

 

 

 

 

 

Mental Health Trust Leases

 

11,782

 

11,782

 

State Lease Sale Tracts

 

12,723

 

12,723

 

Total

 

24,505

 

24,505

 

 

 

 

 

 

 

Canada

 

 

 

 

 

Elk Valley (BC) - EnCana Drill to Earn

 

77,775

 

77,775

 

Alberta (AB) - Crown Lease Sale (Wetaskiwin) 12/14/05

 

2,068

 

2,068

 

Alberta (AB) - Cessford Farm-In (1)

 

3,200

 

2,240

 

Alberta (AB) - Crown Lease Sale (Redwater) 3/8/06

 

2,529

 

2,529

 

Alberta (AB) - Crown Lease Sale (Wainwright) 4/19/06

 

3,794

 

3,794

 

Alberta (AB) - Crown Lease Sale (Wainwright) 5/3/06

 

3,795

 

3,795

 

Alberta (AB) - Crown Lease Sale (Wetaskiwin) 5/31/06

 

1,107

 

1,107

 

Judy Creek

 

3,200

 

1,920

 

Total

 

97,468

 

95,228

 

 

 

 

 

 

 

Total Acres (1)

 

183,755

 

165,620

 


(1) Net acres may be earned pursuant to the farm-in arrangement

Productive Wells and Developed Acreage

Developed acreage at December 31, 2006 totaled 11,270 net and 13,183 gross acres. At December 31, 2006, the Company owned working interests in 282.5 net (349 gross) wells, which were primarily natural gas wells. In 2006, the Company sold or abandoned 3.5 net (5 gross) wells. In the same period, the Company drilled and acquired interests in 130.9 net (193 gross) wells in which it did not previously own an interest.

The following summarizes the Company’s productive and shut-in gas wells as of December, 31, 2006. Productive wells are capable of production and are currently producing. Shut-in wells are wells that are capable of production, but are not currently producing. Gross wells are the total number of wells in which the Company has an interest. Net wells are the sum of the Company’s fractional interests owned in the gross wells.

29




 

As of December 31, 2006:

 

Gross

 

Net

 

Producing wells

 

318.0

 

254.5

 

Shut-in wells

 

31.0

 

28.0

 

Total wells

 

349.0

 

282.5

 

 

The Company operates 277 of the above producing gas wells and 31 of the shut-in wells.

Undeveloped Acreage

The following table sets forth the number of undeveloped acres (primarily located in the Powder River Basin) which will expire during the next five years (and thereafter) unless production is established in the interim. Undeveloped acres “held-by-production” represents the undeveloped portions of producing leases which will not expire until commercial production ceases.

Expiration

 

 

 

 

 

Year Ending

 

Working

 

December 31,

 

Interest Acreage

 

 

 

Gross

 

Net

 

2007

 

639

 

40

 

2008

 

12,812

 

11,605

 

2009

 

80,849

 

80,453

 

2010

 

28,838

 

25,934

 

2011

 

7,964

 

6,879

 

Thereafter

 

32,639

 

26,679

 

Held-By-Production

 

6,831

 

2,760

 

Total

 

170,572

 

154,350

 

 

In general, “royalty” interests are non-operated interests which are not burdened by costs of exploration or lease operations, while “working interests” have operating rights and participate in such costs.   As of December 31, 2006 the Company had no royalty interests.

Drilling Activity

The following tables set forth the number of gross and net gas wells in which the Company has participated and the results thereof for the periods indicated. In the tables below, “gross” refers to the total wells in which the Company has a working interest, and “net” refers to gross wells multiplied by the Company working interest.

Developed Wells (Gross)

 

Year Ended

 

Total Gross

 

 

 

 

 

December 31,

 

Wells

 

Gas

 

Dry

 

2006

 

86.0

 

86.0

 

 

2005

 

43.0

 

43.0

 

 

2004

 

 

 

 

Total

 

129.0

 

129.0

 

 

 

Exploratory Wells (Gross)

 

Year Ended

 

Total Gross

 

 

 

 

 

December 31,

 

Wells

 

Gas

 

Dry

 

2006

 

14.0

 

11.0

 

3.0

 

2005

 

3.0

 

2.0

 

1.0

 

2004

 

 

 

 

Total

 

17.0

 

13.0

 

4.0

 

 

30




Developed Wells (Net)

 

Year Ended

 

Total Net

 

 

 

 

 

December 31,

 

Wells

 

Gas

 

Dry

 

2006

 

73.0

 

73.0

 

 

2005

 

43.0

 

43.0

 

 

2004

 

 

 

 

Total

 

116.0

 

116.0

 

 

 

Exploratory Wells (Net)

 

Year Ended

 

Total Net

 

 

 

 

 

December 31,

 

Wells

 

Gas

 

Dry

 

2006

 

10.2

 

8.8

 

1.4

 

2005

 

2.4

 

2.0

 

0.4

 

2004

 

 

 

 

Total

 

12.6

 

10.8

 

1.8

 

 

Insurance

The Company believes that its existing insurance coverage is adequate to protect it from the risks associated with the ongoing operation of its business. This coverage includes commercial property, general liability and auto, workers compensation, inland marine and excess liability.

Facilities

The Company leases 9,264 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 December 31, 2006 is as follows:

United States

 

 

 

2007

 

$159,168

 

2008

 

156,419

 

2009

 

145,233

 

Total

 

$460,820

 

 

Commitments relative to Canadian leases are stated in U.S. Dollars utilizing the current average exchange rate for the 365 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 $0.88206).

Canada

 

 

 

2007

 

$110,736

 

2008

 

110,736

 

2009

 

110,736

 

2010

 

27,684

 

Total

 

$359,892

 

 

ITEM 3.         LEGAL PROCEEDINGS

From time to time, the Company may be involved in litigation relating to claims arising out of its operations in the normal course of business. As of the date of this Annual Report on Form 10-K, the Company is not a party to any material pending legal proceedings. No such proceedings have been threatened and none are contemplated by the Company.

ITEM 4.         SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

31




PART II

ITEM 5.                         MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common shares are traded on the American Stock Exchange under the symbol “SCU” and the Toronto Stock Exchange under the symbol “SME.”  The following tables set forth, for each of the quarterly periods indicated, the range of high and low sales prices on the American Stock Exchange and the Toronto Stock Exchange.

Quarterly High and Low Market Price for the Two Most Recent Fiscal Years on the
Toronto Stock Exchange(CDN$)†

Quarter Ended

 

High

 

Low

 

December 31, 2006

 

$

2.04

 

$

1.35

 

September 30, 2006

 

$

2.60

 

$

1.50

 

June 30, 2006

 

$

3.41

 

$

2.11

 

March 31, 2006

 

$

3.86

 

$

2.85

 

December 31, 2005

 

$

4.36

 

$

2.40

 

September 30, 2005

 

$

3.35

 

$

1.50

 

June 30, 2005

 

$

3.88

 

$

1.78

 

March 31, 2005

 

$

3.25

 

$

2.25

 

Quarterly High and Low Market Price for the Two Most Recent Fiscal Years on the
American Stock Exchange ($ U.S.)†*

Quarter Ended

 

High

 

Low

 

December 31, 2006

 

$

1.82

 

$

1.16

 

September 30, 2006

 

$

2.50

 

$

1.34

 

June 30, 2006

 

$

3.00

 

$

1.85

 

March 31, 2006

 

$

3.37

 

$

2.38

 

December 31, 2005

 

$

3.75

 

$

2.01

 


We completed a two-for-one forward share split on March 31, 2005.  All share prices have been adjusted for the share split effective March 31, 2005.

* Our common shares began trading on the American Stock Exchange on October 3, 2005.

On March 15, 2007, the last sale price of our common shares as reported on the American Stock Exchange was $1.04 per share and the last sale price of our common shares as reported on the Toronto Stock Exchange was CDN$1.20 per share. On February 28, 2007, the number of our common shareholders of record was 45.

Issuer Purchases of Equity Securities

The Company did not repurchase any of its common shares during the fiscal quarter ended December 31, 2006.

Unregistered Sales of Equity Securities and Use of Proceeds

The Company’s securities transactions during the year ended December 31, 2006 that were not registered under the Securities Act of 1933, and not previously included in a Quarterly Report on Form 10-Q or in a Current Report on Form 8-K, are described as follows:

·                  30,636 warrants were exercised at C$2.40 per share

·                  42,500 warrants were exercised at C$3.00 per share

·                  350,706 warrants were exercised at C$2.60 per share

The common shares were issued upon exercise of the warrants in reliance upon Section 4(2) of the Securities Act of 1933, as amended.

32




Stock Price Performance

The following stock price performance graph is intended to allow review of shareholder returns, expressed in terms of the appreciation of the Company’s common shares relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total shareholder return on the Company’s common shares with the cumulative total return of the Standard & Poor’s Composite 500 Stock Index and of the Dow Jones U.S. Exploration and Production Index (formerly Dow Jones Secondary Oils Stock Index) from December 31, 2001 through December 31, 2006.

Comparison of Five Year Cumulative Total Return
For the Year Ended December 31, 2006

 

 

2001

 

2002

 

2003

 

2004

 

2005

 

2006

 

 Storm Cat Energy Corporation (“SCU”)

 

100.0

 

-7.70

 

225.60

 

808.30

 

600.20

 

-33.70

 

S & P’s Composite 500 Stock

 

100.0

 

77.9

 

100.25

 

111.15

 

116.61

 

135.03

 

DJ U.S. Exploration & Production Index*

 

100.0

 

102.17

 

133.9

 

189.97

 

314.06

 

330.93

 


*     formerly DJ Secondary Oil Stock Index

The information in this Annual Report on Form 10-K appearing under the heading “Stock Price Performance” is being “furnished” pursuant to Item 2-01(e) of Regulation S-K under the Securities Act of 1933, as amended, and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

33




ITEM 6.                              SELECTED FINANCIAL DATA

The following table sets forth certain financial information with respect to the Company and is qualified in its entirety by reference to the historical financial statements and notes thereto included in Item 8, “Financial Statements and Supplementary Data.” The statement of operations and balance sheet data included in this table for each of the four years in the period ended December 31, 2006 were derived from the audited financial statements and the accompanying notes to those financial statements.

 

 

Years Ended December 31,

 

In Thousands, except share amounts

 

2006

 

2005

 

2004

 

2003

 

Audited Financial Information

 

 

 

 

 

 

 

 

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

REVENUE:

 

 

 

 

 

 

 

 

 

Gas sales

 

$

9,444

 

$

4,214

 

$

104

 

$

 

EXPENSES:

 

 

 

 

 

 

 

 

 

Gathering and transportation costs

 

1,921

 

906

 

39

 

 

Operating expenses

 

3,443

 

2,354

 

4

 

 

Gain on disposition of property

 

(185

)

56

 

 

 

Depreciation, depletion, amortization and accretion

 

3,916

 

1,648

 

19

 

 

Impairment

 

2,027

 

2,125

 

 

 

Stock-based compensation

 

2,783

 

1,914

 

 

 

General and administrative expense

 

4,097

 

3,606

 

951

 

173

 

Loss (gain) on foreign exchange

 

11

 

98

 

 

 

Interest and other misc. (income) expense

 

(184

)

(125

)

 

 

Income tax expense (income)

 

(1,524

)

 

 

 

Income (loss) before income taxes and cumulative effect of change in accounting principle

 

$

(6,861

)

$

(8,368

)

$

(909

)

$

(173

)

Net loss

 

$

(6,861

)

(8,368

)

$

(909

)

$

(173

)

Net loss per share (1) :

 

 

 

 

 

 

 

 

 

Basic

 

$

(0.10

)

$

(0.18

)

$

(0.04

)

$

(0.02

)

Diluted

 

$

(0.10

)

$

(0.18

)

$

(0.04

)

$

(0.02

)

Weighted-average shares outstanding (1) :

 

 

 

 

 

 

 

 

 

Basic

 

70,429,219

 

47,321,481

 

21,455,630

 

11,236,892

 

Diluted

 

70,429,219

 

47,321,481

 

21,455,630

 

11,236,892

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

Working capital

 

$

(15,594

)

$

18,445

 

$

2,257

 

$

566

 

Total assets

 

111,964

 

56,953

 

5,743

 

488

 

Short-term liabilities

 

29,061

 

12,709

 

601

 

30

 

Long-term liabilities

 

21,221

 

793

 

79

 

 

Shareholders’ equity

 

61,682

 

43,451

 

5,063

 

458

 

Cash dividends declared per common share

 

$

 

$

 

$

 

$

 

 

 

 

 

 

 

 

 

 

 

Unaudited Operating Data

 

 

 

 

 

 

 

 

 

Production Volumes:

 

 

 

 

 

 

 

 

 

Gas (Mcf)

 

1,606.2

 

693.5

 

17.3

 

 

Average sales price before hedging:

 

 

 

 

 

 

 

 

 

Per Mcf

 

$

5.19

 

$

6.08

 

$

6.01

 

$

 

Average sales price after hedging:

 

 

 

 

 

 

 

 

 

Per Mcf

 

$

5.88

 

$

6.08

 

$

6.01

 

$

 

Total Proved Reserves:

 

 

 

 

 

 

 

 

 

Gas (Mcf)

 

25,015.3

 

10,009.9

 

458.2

 

 

Estimated future net revenues

 

$

41,945

 

$

37,461

 

$

1,011

 

$

 

Estimated future net revenues discounted at 10%

 

$

32,036

 

$

29,017

 

$

807

 

$

 


(1)   The effect of the two for one reverse stock split on March 31, 2005 is reflected in all historical share and per share data.

 

 

34




ITEM 7.                              MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unless the context otherwise requires, the terms “Storm Cat” and “the Company”, when used herein refer to Storm Cat Energy Corporation, together with its operating subsidiaries. When the context requires, the Company refers 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 Annual Report on Form 10-K.

Forward Looking Statements

Please refer to the section entitled “Caution Regarding Forward Looking Statements” and “Risk Factors” for a discussion of factors which could affect the outcome of forward looking statements used by the Company.

THE BUSINESS

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”). Our business model consists of three strategies: (1) acquiring producing properties with drilling prospects in focused basins in both the United States and Canada; (2) exploring areas of moderate risk; and (3) initiating higher risk projects with the potential for higher reward. 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.

Storm Cat achieved the operational goals that it targeted for 2006. Net proved reserves increased from 10.0 Bcf at year-end 2005 to 25.0 Bcf for year-end 2006. Net production increased from 2.6 Mmcf/d year-end 2005 to 8.0 Mmcf/d at year-end 2006. Storm Cat was also able to finance and close on a significant acquisition in the PRB that doubled production and added significant drilling opportunities in and around its core area in Northeast Spotted Horse. The Company added a forth core area by acquiring acreage in the Fayetteville Shale in Arkansas which the exploration activities are scheduled to begin in the summer of 2007.

The technical team was expanded in Canada with the addition of a senior geologist and landman. Canada has a host of unconventional drilling opportunities. Storm Cat acquired and drilled on its acreage in Alberta for both the Mannville and Horseshoe Canyon coals as further describe below in the regional summaries. The Company’s Elk Valley play is still a significant exploration prospect. Storm Cat drilled two wells in 2005 but the completions in January 2006 were not properly implemented.   The technical team evaluated several completion techniques and service companies, and five new wells were drilled in 2006 and properly completed as further outlined below in the Elk Valley summary.

Storm Cat produced 1.6 Bcf in 2006 compared with 0.7 Bcf in 2005. The Company drilled 100 gross wells in 2006 of which 86 were drilled in the PRB. Finding and development costs in the PRB total approximately $1.20 per Mcf to date. Total capital expenditures for 2006 were $72.0 million. Acquisition and acreage purchases totaled $37.0 million leaving a balance of $35.0 million which was spent on drilling and other capitalized expenditures. The Company has over 350 drilling locations remaining in the PRB alone. The other three focus areas, if successful, will double the number of drilling locations providing Storm Cat ample room to grow through drilling.

The Company funded its 2006 $72.0 million capital budget with cash on hand, equity and debt. Storm Cat had $29.5 million in cash on January 1, 2005. On September 28, 2006, Storm Cat raised approximately $20 million through the sale of it shares (see “Liquidity and Capital Resources” for further information). Another $1.4 million was raised through the exercise of warrants and options. Also in September, the Company entered into a $250 million senior credit facility with JPMorgan, subject to a borrowing base. Based on the Company’s proven reserves, Storm Cat was able to draw down $20 million in senior debt and an additional $15 million in bridge financing used for the PRB acquisition. The $15 million bridge loan was subsequently repaid in full.

Storm Cat is in the process of setting its targets for 2007. It has already drilled and completed 21 wells in the PRB during the first quarter of 2007. The Company plans on maintaining focus on its four key areas:

35




the PRB, Fayetteville Shale, Elk Valley, and Alberta. Management expects production and proved reserves in the PRB to continue to grow throughout the year. The Company plans to establish reserves in the Fayetteville Shale in 2007 through the drilling of wells on its acreage. The production results from the five Elk Valley wells should provide management with data to determine the success of the drilling and completion program by summer of 2007. Storm Cat’s technical team will continue to monitor the progress being made on the Company’s Mannville and Horseshoe Canyon plays in Alberta.

To finance its activity in 2007, Storm Cat closed on a its Series A Subordinated Convertible Notes due March 31, 2012 (the “Series A Notes”) and expects to close on its Series B Subordinated Convertible Notes due March 31, 2012 (the “Series B Notes”) in March 2007. The Series A Notes provided the Company with $18.5 million in the first quarter of 2007. Part of the proceeds was used to repay the remaining $7.5 million bridge financing to JPMorgan. The Series B Notes will make available $31.6 million of additional capital provided shareholders approve the underlying shares needed to close the transaction. The shareholder vote is expected to be held on March 29, 2007. The Company also has hedged approximately 75% of its current net daily production to protect cash flow from and adverse decline in commodity prices. Please see Item 7A “Quantitative and Qualitative Analysis” for further discussion about the Company’s cash flow hedges.

BASIN SUMMARY

2006 Activity in the Powder River Basin

On May 5, 2006, Storm Cat closed a mineral leasehold transaction in the Powder River Basin, Campbell County, Wyoming, with two private companies. The acquisition included an interest in 3,942 gross (3,548 net) undeveloped acres. As consideration, 50% was paid in cash at closing and the private companies retained a carried interest as to capital costs covering their 10% working interest to be paid over a period of 18 months after closing.

On June 7, 2006, Storm Cat acquired six state tracts in Sheridan County, Wyoming totaling 1,521 gross (and net) acres at a Wyoming State Lease Sale for $0.7 million lease bonus (average of $458/acre). Development preparation has begun on the acreage including permitting of locations and water management planning. Development should consist of 19 multi-seam wells.

On August 29, 2006, but effective as of July 1, 2006, the Company acquired producing leases totaling 25,200 gross acres and 17,000 net acres in Wyoming’s Powder River Basin for $30.7 million. In accordance with U.S. GAAP, all revenues and expenses prior to the closing date were an adjustment to the purchase price. After the closing date, operations related to these properties are recorded to revenue and expenses in the normal course of business. The production from this field represented 26.4% of 2006 production volumes and 22.9% of 2006 natural gas revenue, and the reserves attributable to this acquisition comprise approximately 44.6% of estimated proved reserves as of December 31, 2006.

On September 14, 2006, Storm Cat entered into a Joint Development Agreement with an unaffiliated third party to jointly develop certain lands for coalbed methane in the Powder River Basin. Under this agreement, Storm Cat and its partner will establish an area of mutual interest in which Storm Cat will act as operator. The Company acquired an undivided 50% of its 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 its partner’s leasehold within the area of mutual interest through development.

At December 31, 2006, Storm Cat had operational control of approximately 41,730 gross acres and 31,905 net acres. At year-end the Company was operating 277 wells and owned a working interest percentage in 41 additional non-operated wells. For the full year of 2006, 86 wells were spud. Wells drilled during 2006 were concentrated in our Northeast Spotted Horse and Jamison/Twenty Mile operating areas.

At year-end 2006, the Powder River Basin exit-rate production was 15 MMcf/d gross and 8 MMcf/d net. The Powder River Basin production currently comprises 100% of Storm Cat’s production.

2006 Activity in the Fayetteville Shale Area of Arkansas

On May 10, 2006, Storm Cat closed a $2.0 million transaction in the Fayetteville Shale play in Arkansas with two private operators. The Company acquired an interest in approximately 16,364 gross undeveloped acres and 12,596 net mineral acres in Van Buren, Pope and Searcy Counties, Arkansas at a cost per net acre of $165.

In the Arkoma Basin’s Fayetteville Shale play in Arkansas, the Company owned or controlled 20,051 gross and 13,982 net acres at December 31, 2006. This property consists of an 80% net revenue interest in

36




16,364 gross (12,596 net) acres and an 81% net revenue interest in 3,688 gross (1,386 net) acres in the Fayetteville Shale Prospect area of Arkansas (mostly in Van Buren County). Storm Cat plans to commence drilling on the first of six net wells in the Fayetteville Shale beginning mid-year 2007.

At year-end 2006, Storm Cat was participating in 14 (non-operated) Fayetteville Shale wells where it owned between a 1% and 8% working interest. These wells were at various stages of planning, drilling, completion or production.

2006 Activity in British Columbia, Canada (Elk Valley)

In Elk Valley, British Columbia, Storm Cat farmed-in on approximately 77,775 gross (77,775 net) acres on an unconventional natural gas prospect. On October 31, 2006, the Company assumed 100% operatorship of the Elk Valley land and the former operator retained a 2.5% overriding royalty interest. During 2006, the Company drilled and completed five wells in Elk Valley. These wells are currently on production and have begun the de-watering stage. Storm Cat expects to have preliminary production results from these wells during the second half of 2007.

2006 Activity in Alberta, Canada (Western Canadian Sedimentary Basin)

In the Western Canadian Sedimentary Basin of Alberta, Canada, Storm Cat owned or controlled approximately 19,693 gross acres and 17,453 net acres at December 31, 2006. Efforts have been focused on evaluating the potential of the Horseshoe Canyon and Mannville Coals. Horseshoe Canyon has been established as a commercial production target in the Western Canadian Sedimentary Basin, while the Mannville Coals are still in the early stages of development. During the course of 2006, Storm Cat experienced a greater than eight-fold increase in its undeveloped acreage position from a starting point of 2,080 acres (gross and net). In 2006, five gross wells were drilled. This total includes two wells drilled at no cost to the Company through a farm out of its interest in two sections of land.

The Alberta, Canada acreage is concentrated in five main areas. From north to south these are Judy Creek, Redwater, Wetaskiwin, Wainwright and Cessford. The Wetaskiwin area is prospective for gas from the Horseshoe Canyon and the Mannville Coals while the other areas are all prospective for gas from the Mannville Coals.

During 2006, Storm Cat participated in the drilling of three wells in the Cessford area on a drill-to-earn farm-out deal. Two of the wells were drilled at no cost to the Company. The first well drilled was a vertical test which targeted a Lower Mannville Channel sand as well as the Mid Mannville Coal. The channel sand was wet, and the well was completed uphole in the Mannville Coal section. A core was cut through the coals. Subsequent analysis showed significant quantities of gas in place, which led to the decision to begin horizontal development drilling. The remaining four earning wells have been farmed out to a third party. Two of the wells have been drilled, and the remaining two earning wells are scheduled to be drilled in the first and second quarters of 2007.

During the fourth quarter of 2006, Storm Cat drilled a 1,450 meter vertical test in the Judy Creek area to evaluate the potential of the Mannville coals as well as unconventional targets in the Colorado Shale. The coals encountered were deemed to be too thin to follow up with horizontal wells.

Storm Cat drilled a 760 meter vertical well in the Wetaskiwin area that was designed to test the gas potential of the Horseshoe Canyon Coal as well as conventional targets in the Belly River and Edmonton Sand. The well encountered gas pay in both the Upper Belly River Sand and the Horseshoe Canyon. Based on these results, the Company has entered into a drill-to-earn deal to earn a 100% working interest in four sections of land subject to a non-convertible overriding royalty. We will earn an interest in one section with each well drilled. Tie-in options are currently being evaluated.

2006 Activity in Alaska

The Company has an 89.5% net revenue interest in 11,782 gross (11,782 net) acres and an 87.5% net revenue interest in 12,723 gross (12,723 net) acres in the Cook Inlet region of Alaska. Storm Cat drilled one well in this area in 2006. The Company is in the process of evaluating the completion potential and costs based upon equipment availability.

37




2006 Activity in Saskatchewan, Canada (Moose Mountain)

Storm Cat previously owned a 30% working interest in the Moose Mountain exploration project in Saskatchewan, covering 235,830 gross acres of unconventional natural gas exploration. Storm Cat 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. The Company sold its working interest in this property to avoid plugging and abandonment costs, but retained a 1% overriding royalty interest.

2006 Activity in Mongolia

As of December 31, 2006, Storm Cat had fully impaired its Mongolia property for a total of $2.2 million.

Business Risks

The exploration for and the acquisition, development, production, and sale of natural gas is highly competitive and capital intensive. As in any commodity business, the market price of the commodity produced and the costs associated with finding, acquiring, extracting, and financing the operation are critical to profitability and long-term value creation for shareholders. Generating reserve and production growth while containing costs represents an ongoing focus for management, and is made particularly important in the Company’s business by the natural production and reserve decline associated with oil and gas properties. In addition to developing new reserves, Storm Cat competes to acquire additional reserves, which involves judgments regarding recoverable reserves, future gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. During periods of historically high gas prices, third party contractor and material cost increases are more prevalent due to increased competition for goods and services. Other challenges the Company faces include attracting and retaining qualified personnel, gaining access to equipment and supplies and maintaining access to capital on sufficiently favorable terms.

Please see “Risk Factors” under Item 1A for more information about these risks and others.

Storm Cat has taken the following steps to mitigate the challenges it faces:

·                  The Company actively manages its exposure to commodity price fluctuations by hedging meaningful portions of expected production through the use of derivatives. Detailed hedging policy and procedures are outlined in the Company’s Hedging Policy.

·                  Storm Cat has a multi-year inventory of attractive drilling locations and a diverse balance of CBM properties, allowing it the opportunity to grow reserves and replace and expand production organically.

·                  The Company has put in place a Delegation of Authority policy outlining the hierarchy of authorization for expenditures and commitments and to provide checks and balances.

·                  A comprehensive Authorization for Expenditure (“AFE”) policy allows for the tracking of all significant capital expenditures so that budget to actual integrity can be monitored and maintained.

·                  Storm Cat uses third party engineering to evaluate acquisitions and year-end reserves. This provides an unbiased check against the Company’s internal evaluations.

·                  Employees and Directors sign a Code of Business Conduct and Ethics which contains a Whistle Blower Policy with an anonymous hotline to the Audit Committee Chair so that fraud or violation of the Company’s policies can be reported immediately and appropriate action taken.

·                  The Board of Directors for the Company includes a majority of independent Board Members. The Audit and Compensation Committees are exclusively independent directors. The Board and the Audit Committee meet a minimum of once each quarter. The Audit Committee meets regularly with the auditors in sessions where management is not present.

2007 Capital Budget

Storm Cat intends to announce its 2007 capital expenditure program in first quarter 2007. The budget will be funded primarily from the issuance of the Series A and B Notes, additional senior debt borrowings and cash flow from operations. If the Company cannot close on the Series B Notes because the underlying shares are not approved by shareholders, Storm Cat will have to seek alternative financing options or consider scaling back it proposed capital expenditure plans for 2007.   The Company may consider several options for raising additional funds such as selling securities, selling assets or farm-outs or

38




similar type arrangements. Financing obtained through the sale of Storm Cat equity will likely result in dilution to the Company’s shareholders.

The Company continues to grow production and leasehold in its core PRB operating area. The PRB provides opportunity for increased production as Storm Cat continues to successfully apply multi-seam completion technology to its drilling operations, resulting in increasing cash flow for the Company and its shareholders. Storm Cat has successfully drilled five wells in Elk Valley which is a focused area to the Company for future growth. The Fayetteville Shale acquisition and Cessford project are especially important, allowing the Company to have access to data as a working interest partner in the wells with limited financial exposure. Storm Cat will use this data to help refine its 2007 drilling program in these areas.

Contractual Obligations

The following table summarizes the Company’s obligations and commitments to make future payments under its convertible notes, notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of December 31, 2006.

In Thousands

 

Total

 

< 1 Yr.

 

1-3 Yrs.

 

3-5 Yrs.

 

> 5 Yrs.

 

Series A Convertible Notes: (1)

 

 

 

 

 

 

 

 

 

 

 

Principal

 

$

18,535

 

$

 

$

 

$

18,535

 

$

 

Interest

 

8,858

 

1,572

 

5,143

 

2,143

 

 

JPMorgan Chase Senior Credit Facility:

 

 

 

 

 

 

 

 

 

 

 

Principal (2)

 

20,000

 

 

20,000

 

 

 

Interest (3)

 

6,092

 

1,700

 

4,392

 

 

 

Operating Leases

 

849

 

291

 

558

 

 

 

Employment Contracts

 

 

 

 

 

 

Consulting Agreements (4)

 

90

 

90

 

 

 

 

Total Contractual Obligations

 

$

54,424

 

$

3,653

 

$

30,093

 

$

20,678

 

$

 


(1)       The Series B Convertible Notes have not yet closed and, therefore, are not included in this calculation.

(2)       Assumes an unchanged JPMorgan principal balance over what existed at December 31, 2006, including letters of credit.

(3)       Interest calculated on the JPMorgan credit facility is through the maturity date of the Note.

(4)       Reflects an agreement with the law firm of a related party which expires in September 2007 for a minimum of $10,000 per month in legal fees plus actual reasonable expenses relative to the representation of Storm Cat (none assumed)..

 

The above table does not include asset retirement obligations as discussed in “Note 1: Summary of Significant Accounting Policies” of the accompanying Consolidated Financial Statements, as the Company cannot determine with accuracy the timing of such payments.

Forward Sales

The Company has no forward sales contracts as of December 31, 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.

39




Storm Cat entered into a gathering agreement with an unaffiliated third party which requires payment of gathering fees of $0.47 per Mcf on annual volumes of 2,064,600, 2,482,231 and 2,040,575, respectively in 2006, 2007 and 2008.  In the event that Storm Cat is unable to meet these annual delivery levels, it will be liable at a rate of $0.47 per undelivered Mcf.  At year-end Storm Cat accrued for a net volume shortfall of $256,510, which was paid in February 2007, relative to undelivered volumes in 2006.  Over-delivered volumes will count toward the overall commitment through 2008.  The rate drops to $0.284 per Mcf for future volume shortfalls.

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 December 31, 2006 is 1,500 MMBtu’s per day from January 1, 2007 through July 9, 2009.  The total quantity is 1,414,500 MMBtu’s.  The fixed price in the agreement is $7.16 per MMBtu (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 December 31, 2006 is 2,000 MMBtu’s per day from January 1, 2007 through August 31, 2009.  The total quantity is 1,948,000 MMBtu’s.  The fixed price in the agreement is $7.27 per MMBtu (CIG pricing).

On December 31, 2006, Storm Cat entered into two additional commodity swap cash settlement transactions.  The outstanding quantity committed to the third swap as of December 31, 2006 is 2,400.00 MMBtu’s per day from January 1, 2007 through December 31, 2007.  The total quantity is 876,000 MMBtu’s.  The fixed price in the agreement is $5.12 per MMBtu (CIG pricing).

The outstanding quantity committed to the fourth swap as of December 31, 2006 is 1,200 MMBtu’s per day from January 1, 2008 through December 31, 2008.  The total quantity is 439,200 MMBtu’s.  The fixed price in the agreement is $6.61 per MMBtu (CIG pricing).

Outstanding Share Data

As of December 31, 2006, the Company had 80,429,820 shares issued and outstanding. There are 8,923,368 share purchase, finders fee and agent warrants outstanding.  However, 3,228,020 of these warrants expired on February 27, 2007 without being exercised.  There are currently 5,470,000 common share options outstanding under the Company’s Amended and Restated Share Option Plan and Restricted Share Unit Plans combined.  The total amount of common shares reserved for issuance under the plans as of December 31, 2006 is 10,000,000 common shares.

During year ended December 31, 2006, the following warrants and options were exercised (in U.S. dollars):

·              753,906 warrants for gross proceeds of $1.3 million.

·              227,500 options for gross proceeds of $0.1 million.

On January 30, 2007, the Company issued $18.6 million in Series A Notes.  The Series A Notes are convertible into Storm Cat common shares at a price of $1.17 per share, as may be adjusted in accordance with the terms of the Series A Notes (as applicable).  If fully converted, the Company’s earnings per share would be diluted by an additional 15,841,880 shares.

40




Liquidity and Capital Resources

The following table summarizes the Company’s sources and uses of cash for each of the three years ended December 31, 2006, 2005 and 2004.

 

 

Years Ended December 31,

 

In Thousands

 

2006

 

2005

 

2004

 

Net cash provided by (used in) operations

 

$

(2,687

)

$

(2,272

)

$

(135

)

Net cash used in investing activities

 

(70,738

)

(15,733

)

(2,893

)

Net cash provided by financing activities

 

48,947

 

44,920

 

5,056

 

Effect of exchange rate changes on cash

 

275

 

(78

)

184

 

Net cash flow

 

$

(24,203

)

$

26,837

 

$

2,212

 

 

The decrease in cash used in operations from 2005 to 2006 is primarily due to changes in operating working capital.  Also additional G&A costs were incurred to support increased operating and drilling activities.

The Company’s investing activities during the three years ended December 31, 2006 related primarily to the Company’s development and exploration activities. During 2006, the Company also completed several acquisitions of acreage and additional working interests in producing wells.  The largest single acquisition in 2006 was for $30.7 million in the Powder River Basin.  In this acquisition the Company acquired producing leases totaling 25,200 gross acres and 17,000 net acres.

Historically, the Company has relied on the sale of equity capital and farm-outs and other similar types of transactions to fund working capital, the acquisition of its prospects and its drilling and development activities.  The financing activities in each of the years presented is primarily comprised of the net proceeds from the sale of equity in the Company, as further described below.  On September 18, 2006, Storm Cat closed a public offering of 7,594,937 common shares at a price to the public of C$1.58 per share.  The Company also issued 6,172,839 flow-through shares on September 18, 2006 at a price of C$1.80 per share.

During 2006, 227,500 options to purchase Storm Cat common shares were exercised for proceeds of $0.1 million, and 753,906 warrants were exercised for proceeds of $1.3 million.

Working Capital (Deficit)

At December 31, 2006 Storm Cat’s current liabilities of approximately $29.1 million exceeded its current assets of $13.5 million resulting in a working capital deficit of $15.6 million.  This compares to a working capital surplus of $18.4 million as of December 31, 2005.  Current liabilities as of December 31, 2006 consisted of trade payables of $7.3 million, revenues due third parties $2.1 million, accrued capital and other liabilities of $10.0 million, a flow-through share liability of $1.2 million, short-term notes payable of $7.5 million and accrued interest of $1.0 million.

Private Placement

On September 28, 2006 the Company closed a private placement consisting of the sale to a single investment group based in Ontario, Canada, acting as portfolio manager for fully-managed accounts, of 7,594,937 units (C$12,000,000) and 6,172,839 flow-through common shares (C$11,111,110) (the “Offering”). Each unit, priced at C$1.58, was comprised of one common share and approximately 0.28 of a common share purchase warrant (2,126,582 warrants).  Each whole common share purchase warrant is exercisable into one common share at a price of C$1.90 per share for a period of 18 months from closing.  Each flow-through common share was priced at C$1.80 per share.  In connection with the Offering, the Company paid a cash commission equal to 6% of the aggregate gross proceeds of the Offering.

The securities issued under the Offering have not been registered under the United States Securities Act of 1933 or any state securities laws, and unless so registered may not be offered or sold in the United States, except pursuant to an exemption from, or in a transaction subject to, the registration requirements of the Securities Act of 1933 and applicable state securities laws.

41




Bank Credit Facility

Senior Credit Facility

On July 28, 2006, Storm Cat entered into a Credit Agreement, with JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the Lenders party thereto (the “U.S. Credit Agreement”).   Additionally, on July 28, 2006, Storm Cat entered into a Credit Agreement, with JPMorgan Chase Bank, N.A., Toronto Branch as Canadian Administrative Agent, JPMorgan Chase Bank, N.A., as Global Administrative Agent, and the Lenders party thereto (the “Canadian Credit Agreement” and together with the U.S. Credit Agreement, the “Credit Agreements”).  Pursuant to these Credit Agreements, the Company is permitted to borrow up to an aggregate principal amount of $250 million, to be allocated between them depending on the respective borrowing base under each such agreement.  The Credit Agreements were amended on January 30, 2007 pursuant to the First Amendment to Combined Credit Agreements (the “Amendment” and together with the Credit Agreements, the “Amended Credit Agreements”) to allow for subordinated debt and to amend the current ratio requirement.  A subsequent Letter Agreement was entered into on February 16, 2007 which established the borrowing base at $20 million and adjusted the applicable interest rates until a re-determination on the Company’s reserves and borrowing base was conducted.

Interest on borrowings under the Amended Credit Agreements and under the Letter Agreement accrues at variable interest rates at either a Eurodollar rate or an alternate base rate, at the Company’s election.  On loans made under the U.S. Credit Agreement, the Eurodollar rate is calculated at LIBOR plus an applicable margin 2.75%.  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 of 1.25%.  For loans made under the Canadian Credit Agreement, the Eurodollar rate is calculated at LIBOR plus an applicable margin of 2.75%.  Canadian Prime loans are the Canadian Prime Rate plus 1.25%. USBR Loans Rates are USBR plus 1.25% and the Bankers Acceptance Stamping Fee is 2.75%.  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 Amended Credit Agreements quarterly in arrears based on a percentage multiplied by the daily amount that the aggregate commitments exceed borrowings under the Amended Credit Agreements.  The commitment fee percentage is 0.50%.  Loans made under the Amended Credit Agreements are secured by mortgages on the Company’s natural gas properties and guaranteed by Storm Cat’s PRB assets.

The Amended Credit Agreements require 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 beginning March 31, 2007;  and (2) a ratio of total funded debt to EBITDA (as such terms are defined in the Amended Credit Agreement) for the most recent quarter, annualized, not to be greater than 5:1 for the fiscal quarter ending December 31, 2006, 3.5:1 fiscal quarter ending March 31, 2007, and 3:1 for each subsequent quarter.  Quarterly compliance is calculated using a four quarter rolling methodology and measured against certain targets.  The current assets to current liabilities ratio goes into effect March 31, 2007.  The Company was in non-compliance of the EBITDA covenant as of December 31, 2006.  A temporary waiver was obtained from JPMorgan for the quarter ended December 31, 2006 and, JPMorgan agreed not to test the fiscal quarter ended March 31, 2007.  Pursuant to the provisions of the Emerging Issues Task Force (“EITF”) No. 86-30, Classifications of Obligations When a Violation is Waived by the Creditor, the Company projected future compliance with existing covenants and concluded that compliance with the same covenants at the next quarterly measurement date was probable.  The temporary waiver required the Company to complete the Amendment.

The Amendment allowed the Company to move forward with its offering of subordinated convertible debt and permitted the issuance of (a) the Series A Notes, and (b) the Series B Notes, in an aggregate principal amount not to exceed $50.2 million, a portion of the proceeds of which shall be used to repay in full the  indebtedness evidenced by the Bridge Facility (as defined below), and which indebtedness (i) has a coupon rate of not greater than 9.25%, (ii) has a due date not earlier than March 31, 2012, (iii) is not subject to negative covenants, financial covenants or events of default (or other provisions which have the same effect as negative covenants, financial covenants or events of default) which have not been approved by the Global Administrative Agent, and (iv) is subordinated to the obligations on terms acceptable to the Global Administrative Agent, including, without limitation, pursuant to the terms of the Subordination Agreement.

Bridge Credit Facility

On August 29, 2006, Storm Cat entered into an amendment (the “First Amendment”) to the U.S. Credit Agreement to obtain a secured bridge note of U.S. $15.0 million (the “Bridge Facility”) to help fund the 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

42




outstanding at the end of the third quarter.  The Company paid $0.9 million in fees to JPMorgan associated with the Bridge Facility ($0.8 million for an up-front fee and $0.1 million for a structuring fee).  The fees have been recorded as deferred financing costs in the accompanying financial statements and were amortized through January 31, 2007, at which time the Company paid down the Bridge Facility in full.

Convertible Notes

On January 19, 2007, Storm Cat entered into a Series A Note Purchase Agreement for the private placement of the 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 in a total aggregate principal amount of $31.7 million.  The Series A Notes and the Series B Notes will be convertible into Storm Cat 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 the Company may force 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 its common shares trade above $2.05, as may be adjusted, for 20 days within a period of 30 consecutive trading days.

On January 30, 2007, Storm Cat closed the private placement of Series A Notes.  The Series A Notes will mature on March 31, 2012, unless earlier converted, redeemed or repurchased.  The Series A Notes bear interest at a rate of 9 ¼% 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.

The closing on the Series B Notes is contingent upon the successful vote of shareholders approving the underlying common shares should the Series B Note be converted.  The shareholder vote is schedule for March 29, 2007. The Series B Notes bear the same interest rate and interest payment schedule as the Series A Notes.

As part of the private placements, the Company entered into a registration rights agreement with the investors requiring the Company to file with the SEC a registration statement covering the common shares issuable upon conversion of the Series A Notes and the Series B Notes.  The Company filed a Form S-1 registration statement with the SEC on March 1, 2007 for the common shares underlying the Series A Notes.  A similar S-1 registration statement will be filed soon after the closing of the Series B Notes.

In Canada, any shares issued on conversion of the Series A Notes are subject to a four month hold period and may not be traded before May 31, 2007 unless permitted under applicable securities legislation and the rules of the Toronto Stock Exchange.

The Company intends to use the net proceeds from the Series A and Series B Notes along with addition senior bank financing to fund its 2007 U.S. capital expenditure budget requirements.  It also used a portion of the net proceeds on the Series A Notes to repay the remaining $7.5 million of mezzanine debt that was borrowed in connection with the Powder River Basin acquisition completed in August 2006.

Additional Financing

The Company is constantly investigating participation opportunities in additional exploration and development projects.  If new project interests are acquired, the Company will require additional funds for acquisition and exploration and/or development of these new projects.

Off-Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2006, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. The Company does not believe that these arrangements are reasonably likely to materially affect its liquidity or availability of, or requirements for, capital resources.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In December 2005, the Company adopted the U.S. dollar as its functional and reporting currency because the majority of its activity is conducted in U.S. dollars.  The Company believes this will facilitate a more direct comparison to other North American exploration and development companies.  Prior to December 2005, the Company presented its financial statements using generally accepted accounting principles in Canada, and utilized the Canadian dollar as its functional and reporting currency.

43




Critical accounting estimates used in the preparation of the financial statements include the Company’s estimate of the value of stock-based compensation.  These estimates involve considerable judgment and are, or could be, affected by significant factors that are out of the Company’s control.

Oil and Gas Reserves

Storm Cat follows the full cost method of accounting whereby all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a “full cost pool.” Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves.  Under the full cost method of accounting, capitalized oil and gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost, or estimated fair value if lower, of unproved properties.  Should capitalized costs exceed this ceiling, an impairment would be recognized.

Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company’s overall value.  These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company’s proved properties.

Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process.  The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

The most accurate method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data.  The accuracy of the decline analysis method generally increases with the length of the production history. Since most of the Company’s wells have been producing less than five years, their production history is relatively short, so other (generally less accurate) methods such as volumetric analysis and analogy to the production history of wells of other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company’s estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company’s wells are produced over time and more data is available, the estimated proved reserves will be re-determined on an annual basis and may be adjusted based on that data.

Actual  future  production,  gas and oil prices,  revenues,  taxes,  development expenditures,  operating  expenses and  quantities  of  recoverable  gas and oil reserves most likely will vary from the  Company’s  estimates.  Any significant variance could materially affect the quantities and present value of the Company’s reserves. For example a decrease in price of 10% per Mcf for natural gas would  result in a  decrease  in the Company’s December  31, 2006  present  value of future  net cash  flows of  approximately $2.0 million.  In addition, the Company may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of exploration  and  development  and prevailing gas and oil prices.  The Company’s reserves may also be susceptible to drainage by operators on adjacent properties.

Impairment of Long-lived Assets

The cost of the  Company’s  unproved  properties  is withheld from the depletion base as described  above,  until  such a time  as the  properties  are  either developed or abandoned.  These properties are reviewed periodically for possible impairment.

As of December 31, 2006, the Company had fully impaired its Mongolia property for a total of $2.2 million.  Its Moose Mountain property in Canada was also impaired for a total of $1.9 million.

44




Revenue Recognition

The Company’s revenue is derived from the sale of gas production from its producing wells. This revenue is recognized as income when the production is produced and sold.  The Company typically receives its payment for production sold one to three months subsequent to the month of the sale.  For this reason, the Company must estimate the revenue that has been earned but not yet received as of the reporting date.  The Company uses actual production reports to estimate the quantities sold and the Colorado Interstate Gas (“CIG”) spot price, less marketing and transportation adjustments, to estimate the price of the production.  Variances between estimates and the actual amounts received are recorded in the month the payment is received.

Stock-based Compensation

The factors affecting stock-based compensation include estimates of when stock options might be exercised and the stock price volatility.  The timing for exercise of options is out of the Company’s control and will depend, among other things, upon a variety of factors including the market value of Company shares and the financial objectives of the holders of the options.  The Company has used historical data to determine volatility in accordance with Black-Scholes modeling, however, future volatility is inherently uncertain and the model has its limitations.  As of December 31, 2006 the Company’s Black-Scholes model assumed a cumulative forfeiture rate of 8.76%.  While these estimates can have a material impact on the amount of stock-based compensation expense, and hence results of operations, it has no impact on the Company’s financial condition.

Accounting for Oil and Gas Properties

The Company’s recorded value of its oil and gas properties is, in all cases, based on historical costs.  The Company is in an industry that is exposed to a number of risks and uncertainties, including exploration risk, development risk, commodity price risk, operating risk, ownership and political risk, funding and currency risk as well as environmental risk.  The Company’s financial statements have been prepared with these risks in mind.  All of the assumptions set out herein are potentially subject to significant change and out of the Company’s control.  Such changes are not determinable at this time.

Recent Accounting Pronouncements

On June 1, 2005, the Financial  Accounting  Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 154,  Accounting Changes and Error Corrections”, which replaced Accounting Principles Board Opinion No. 20,  Accounting  Changes and SFAS No. 3. SFAS 154 provided guidance on the accounting for and reporting of accounting changes and error corrections.  It established retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error.  SFAS 154 was effective for accounting changes and corrections of errors made January 1, 2006.  The adoption of SFAS No. 154 had no impact on the Company’s financial statements.

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No. 133 and 140.” SFAS No. 155 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No.  140, “Accounting for Transfers and  Servicing of Financial Assets and Extinguishments of Liabilities,” and also resolves issues addressed in SFAS No. 133 Implementation Issue No. D1, “Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.” SFAS No. 155 was issued to eliminate the exemption from applying SFAS No. 133 to interests in securitized financial assets so that similar instruments are accounted for in a similar fashion, regardless of the instrument’s form.  The Company does not believe that its financial position, results of operations or cash flows will be impacted by SFAS No. 155 as the Company does not currently hold any hybrid financial instruments.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes.”  The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.”  Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions.  The interpretation is effective for fiscal years beginning after December 15, 2006.  The Company is currently

45




evaluating whether the adoption of FIN 48 would have a material impact on its financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”. This Statement defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure related to the use of fair value measures in financial statements.  The Statement is to be effective for the Company’s financial statements issued in 2008; however, earlier application is encouraged. The Company is currently evaluating the timing of adoption and the impact that adoption might have on its financial position or results of operations.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 “Consideration of Prior Years’ Errors in Quantifying Current Year Misstatements” (“SAB 108”).  Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary.  SAB 108 is effective for fiscal years ending after November 15, 2006, and early application is encouraged.  The adoption of SAB 108 did not have a material impact on the Company’s financial position or results from operations.

In December 2006, the FASB issued FASB Staff Position (“FSP”) EITF 00-19-2, “Accounting for Registration Payment Arrangements.” This FSP specifies that the contingent   obligation   to  make  future   payments  or   otherwise   transfer consideration  under a  registration  payment  arrangement  should be separately recognized and measured in accordance with FASB Statement No. 5, “Accounting for Contingencies”.  This FSP is effective immediately for registration payment arrangements and the financial instruments subject to those arrangements that are entered into or modified subsequent to December 21, 2006. For registration payment arrangements and financial instruments subject to those arrangements that were entered into prior to December 21, 2006, the guidance in the FSP is effective January 1, 2006 for the Company.  The Company does not believe that this FSP will have a material impact on its financial position or results from operations.

On February 15, 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial  Assets  and  Financial  Liabilities.”  This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial  position or results of operations.

FINANCIAL RESULTS

Results of Operations

The following table presents information regarding the production volumes, average sales prices received and average production costs associated with the Company’s sales of natural gas for the periods indicated.

 

For the Years Ended

 

 

 

December 31,

 

 

 

2006

 

2005

 

2004

 

Natural gas production (Mmcf)

 

1,606.2

 

693.5

 

17.3

 

Average sales price per Mmcf

 

$

5.88

 

$

6.08

 

$

6.01

 

 

46




Comparative Results of Operations for the Years Ended December 31, 2006 and 2005, respectively.

 

 

Year Ended December 31,

 

Selected Operating Data:

 

2006

 

2005

 

Net Sales Volume:

 

 

 

 

 

Natural Gas (MMcf)

 

1,606.2

 

693.5

 

 

 

 

 

 

 

Oil and Gas Sales (in thousands)

 

 

 

 

 

Natural Gas

 

$

9,444

 

$

4,214

 

 

 

 

 

 

 

Average Sales Prices:

 

 

 

 

 

Natural Gas (per Mcf)

 

$

5.88

 

$

6.08

 

 

 

 

 

 

 

Additional Data (per Mcf):

 

 

 

 

 

Gathering and Transportation

 

$

1.20

 

$

1.31

 

Lease Operating Expenses

 

$

1.49

 

$

2.61

 

Ad Valorem and Property Taxes

 

$

0.65

 

$

0.78

 

Depreciation, Depletion and Amortization

 

$

2.31

 

$

2.28

 

General and Administrative, net of capitalization

 

$

2.55

 

$

5.20

 

Stock-based Compensation

 

$

1.73

 

$

2.76

 

 

Natural Gas Sales.  Natural gas sales revenue increased approximately 124.1% from $4.2 million in 2005 to $9.4 million in 2006.  Sales revenue is a function of sales volumes and average sales prices. Sales volumes increased 131.6% between periods. The volume increase resulted primarily from acquisitions and successful drilling over the past year that produced new sales volumes that offset the natural decline in production.  The Company’s average price for natural gas decreased 3.2% between periods from $6.08 per Mcf in 2005 to $5.88 per Mcf in 2006.

Gathering and Transportation.  Gathering and transportation expenses increased approximately $1.0 million from $0.9 million in 2005 to $1.9 million in 2006.  The increase in total expense was a direct result of increase production volumes.  On a per Mcf basis, gathering and transportation expenses decreased $0.11 per Mcf from $1.31 per Mcf in 2005 to $1.20 per Mcf in 2006.  The decrease on a per Mcf basis is attributed to economies realized in transporting greater volumes.

Lease Operating Expenses. Lease operating expenses (excluding taxes) increased approximately $0.6 million to $2.4 million in 2006 compared to $1.9 million in 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 natural gas sales decreased from 44.0% during 2005 to 25.4% in 2006 as lease operating cost increases did not keep pace with volume increases.  Lease operating expenses per Mcf decreased 42.9% from $2.61 in 2005 to $1.49 in 2006.

Ad Valorem and Property Taxes. Ad valorem and property taxes increased approximately $0.5 million to $1.1 million in 2006 compared to $0.5 million in 2005.  The increase resulted from gas volume increases over the past year.  Ad valorem and property taxes as a percentage of natural gas sales decreased from 12.8% during in 2005 to 11.1% in 2006.  Ad valorem and property tax per Mcf decreased 16.5% from $0.78 during 2005 to $0.65 in 2006 due to production volume increases.

47




Depreciation, Depletion and Amortization. DD&A increased by $2.1 million to $3.7 million during in 2006 compared to $1.6 million in 2005.  This increase resulted from increased production from recent acquisitions, increased capital costs and an increase in the DD&A rate.  The per Mcf rate increased marginally by $0.03 from $2.28 in 2005 to $2.31 in 2006 primarily due to additions to the reserve estimate.  The components of DD&A expense were as follows:

 

 

Year Ended December 31,

 

In Thousands

 

2006

 

2005

 

Depreciation

 

$

305

 

$

237

 

Depletion

 

3,398

 

1,346

 

Amortization

 

0

 

0

 

Depreciation, Depletion and Amortization

 

$

3,703

 

$

1,583

 

 

Accretion.  Accretion expense increased by $0.1 million to $0.2 million in 2006 from $0.1 million in 2005.  This increase was the result of additional drilling in the Powder River Basin and Elk Valley as well as the acquisition of properties in the Powder River Basin.

 

 

Year Ended December 31,

 

In Thousands

 

2006

 

2005

 

Accretion

 

$

213

 

$

65

 

 

Impairment.  Impairment expense decreased by $0.1 million to $2.0 million in 2006 from $2.1 million in 2005.  In 2005, the Company impaired its Mongolia property and in 2006 it impaired its Moose Mountain property in Saskatchewan, and a small portion of the balance of Mongolia.

 

 

Year Ended December 31,

 

In Thousands

 

2006

 

2005

 

Impairment

 

$

2,027

 

$

2,125

 

 

General and Administrative Expense.  Net general and administrative expense increased $1.3 million to $6.9 million in 2006 compared to $5.5 million in 2005.  One of the largest components of the increase is attributed to salaries and related benefits and taxes which totaled $2.4 million in 2006 compared to $1.3 million in 2005.  The increase in salaries was attributable to an increase in the employee base, from 15 employees in 2005 to 27 employees in 2006, resulting from the Company’s continued growth.  Additionally, Sarbanes-Oxley and audit fees increased by $0.3 million, director and officer insurance increased by $0.2 million, legal fees increased by $0.2 million and bank fees increased by $0.3 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). Stock-based compensation increased $0.9 million to $2.8 million in 2006 from $1.9 million in 2005 primarily due to an increase in the number of employees between periods.  Capitalized overhead increased by $1.5 million to $2.1 million in 2006 from $0.6 million in 2005.  This increase in capitalized overhead was due to a combination of increases in the number of operated properties, new acquisitions, stepped-up drilling activity and the associated increased employee costs in 2006.

 

 

Year Ended December 31,

 

In Thousands

 

2006

 

2005

 

General and Administrative Expenses

 

$

6,168

 

$

4,198

 

Stock-based Compensation

 

2,783

 

1,914

 

Capitalized Overhead

 

(2,071

)

(592

)

General and Administrative Expense, net

 

$

6,880

 

$

5,520

 

 

Income Tax.  The income tax benefit realized in 2006 was $1.5 million.  This benefit is from spending capital that qualifies for immediate tax deduction and, in turn, this tax benefit is passed on to our flow-

48




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 spent, the liability is reduced and an income tax benefit is recorded to the income statement.  A flow-through share liability of $1.2 million still remains on the Company’s balance sheet and the associated capital must be spent by December 31, 2007.

Interest Expense.  Interest expense during 2006 consists primarily of interest expense related to the Company’s Senior Credit Facility with JPMorgan.  This facility was not in place in 2005.

Known Future Trends.  The Company expects continued increases in its production, revenue and lease operating expenses and interest expense due to its capital expenditure plans and wells coming on production.   The Company also expects ongoing significant capital expenditures in order to explore and develop its current acreage.

Comparative Results of Operations for the Years Ended December 31, 2005 and 2004, respectively.

 

 

Year Ended December 31,

 

Selected Operating Data:

 

2005

 

2004

 

Net Sales Volume:

 

 

 

 

 

Natural Gas (MMcf)

 

693.5

 

17.3

 

 

 

 

 

 

 

Oil and Gas Sales (in thousands)

 

 

 

 

 

Natural Gas

 

$

4,214

 

$

104

 

 

 

 

 

 

 

Average Sales Prices:

 

 

 

 

 

Natural Gas (per Mcf)

 

$

6.08

 

$

6.01

 

 

 

 

 

 

 

Additional Data (per Mcf):

 

 

 

 

 

Gathering and Transportation

 

$

1.31

 

$

2.25

 

Lease Operating Expenses

 

$

2.61

 

$

0.23

 

Ad Valorem and Property Taxes

 

$

0.78

 

$

 

Depreciation, Depletion and Amortization

 

$

2.28

 

$

1.10

 

General and Administrative, net of capitalization

 

$

5.20

 

$

54.97

 

Stock-based Compensation

 

$

2.76

 

$

 

 

Natural Gas Sales.  Natural gas sales revenue increased approximately 3951.9% from $0.1 million in 2004 to $4.2 million in 2005.  Sales revenue is a function of sales volumes and average sales prices. Sales volumes increased 3908.7% between periods. The volume increase resulted primarily from acquisition activities and successful drilling activities over the past year which produced new sales volumes that more than offset the natural decline in production.  The Company’s average price for natural gas increased 1.1% between periods.

Gathering and Transportation.  Gathering and transportation expenses increased approximately $0.9 million from $40,000 in 2004 to $0.9 million in 2005.  The increase in total expense was a direct result of increase production volumes.  On a per Mcf basis, gathering and transportation expenses decreased $0.94 per Mcf from $2.25 per Mcf in 2004 to $1.31 per Mcf in 2005.  The decrease on a per Mcf basis is attributed to economies realized in transporting greater volumes.

Lease Operating Expenses. Lease operating expenses (before taxes) increased approximately $1.9 million to $1.9 million in the 2005 compared to $4,000 in 2004.  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 increased from 3.8% in 2004 to 44.0% in 2005 due to a sharp increase in production between periods.  Lease operating expenses per Mcf increased 1034.8% from $0.23 in 2004 to $2.61 in 2005.

 

49




Ad Valorem and Property Taxes. Ad valorem and property taxes increased by 100% from zero in 2004 to $0.5 million in 2005 due to production first coming on-line in 2005.  Ad valorem and property taxes as a percentage of oil and gas sales equated to 12.8% in 2005, and ad valorem and property tax per Mcf was $0.78 in 2005.

Depreciation, Depletion and Amortization. DD&A increased by $1.6 million to $1.6 million during in 2005 compared to $20,000 in 2004.  This increase resulted from increased production from recent acquisitions, increased capitalized costs and an increase in the DD&A rate.  The per Mcf rate increased $1.18 from $1.10 in 2004 to $2.28 in 2005 primarily due to additions to the reserve estimate.  The components of DD&A expense were as follows:

 

Year Ended December 31,

 

In Thousands

 

2005

 

2004

 

Depreciation

 

$

237

 

$

 

Depletion

 

1,346

 

19

 

Amortization

 

 

 

Depreciation, Depletion and Amortization

 

$

1,583

 

$

19

 

 

Accretion.  Accretion expense increased from zero in 2004 to $0.1 million in 2005.  This increase was the result of a shift in the operational activities of the Company.  The Company first acquired gas wells in December 2004.  Wells were drilled in 2005 and the Northeast Spotted Horse field in the Powder River Basin was acquired.  A retirement obligation associated with the drilled and producing property was set up in 2005 and accretion was recorded.

 

Year Ended December 31,

 

In Thousands

 

2006

 

2005

 

Accretion

 

$

65

 

$

 

 

Impairment.  Impairment expense increased by $2.1 million in 2005 from zero in 2004 due to the impairment its Mongolia property.   

 

Year Ended December 31,

 

In Thousands

 

2005

 

2004

 

Impairment

 

$

2,125

 

$

 

 

General and Administrative Expense.  Net general and administrative expense increased $4.5 million to $5.5 million in 2005 compared to $1.0 million in 2004.  The increase was due to the significant growth of the Company between these two periods.  General and administrative expense before stock-based compensation and capitalized overhead increased $2.7 million to $3.6 million in 2005 compared to $0.9 million in 2004.  One of the largest components of the increase is attributed to salaries and related benefits and taxes which totaled $3.2 million in 2005 and $0.3 million in 2004.  The increase in salaries was attributable to an increase in the employee base, from one employee (our President, J. Scott Zimmerman) in 2004 to 15 employees in 2005.  Storm Cat had no stock-based compensation prior to 2005.  The Company only began capitalizing overhead in 2005 after its exploration team was in place.

 

Year Ended December 31,

 

In Thousands

 

2005

 

2004

 

General and Administrative Expenses

 

$

4,198

 

$

951

 

Stock-based Compensation

 

1,914

 

 

Capitalized Overhead

 

(592

)

 

General and Administrative Expense, net

 

$

5,520

 

$

951

 

 

50




Fourth Quarter Significant Adjustments

At year-end Storm Cat accrued for a net volume shortfall of $0.3 million relative to undelivered volumes in 2006, which was paid in February 2007, relative to undelivered volumes in 2006.

Additionally, in the fourth quarter of 2006, the Company paid out approximately $0.1 million in bonuses to executives and employees.

ITEM 7A. QUANTATATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company manages exposure to commodity price fluctuations by periodically hedging a portion of estimated natural gas production.  The graph below details the rate of return for new wells drilled on the Company’s existing properties, realized at various natural gas price points for each of the Company’s geographic producing areas.  The prices reflected below include all capital expenditures and development costs, but do not include transportation and gathering charge, general and administrative expenses.

The Company recorded an unrealized gain of $3.5 million from its derivative contracts for the year ended December 31, 2006; $0.8 million of which was classified as a long-term asset, and $2.7 million of which was classified as a short-term asset.

As of December 31, 2006, the Company had entered into financial contracts through August 2009 for a total of approximately 4,677,700 MMBtu.  The Company anticipates that all forecasted transactions will occur by the end of their originally specified periods.  All contracts are entered into for purposes other than trading.

On July 21, 2006, Storm Cat entered into a commodity swap cash settlement transaction.  The outstanding quantity committed to the swap as of December 31, 2006 is 1,500 MMBtu’s per day beginning January 1, 2007 through July 9, 2009.  The total quantity is 1,414,500 MMBtu’s.  The fixed price in the agreement is $7.16 per MMBtu (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 December 31, 2006 is 2,000 MMBtu’s per day beginning January 1, 2007 through August 31, 2009.  The total quantity is 1,948,000 MMBtu’s.  The fixed price in the agreement is $7.27 per MMBtu (CIG pricing).

51




On December 31, 2006, Storm Cat entered into two additional commodity swap cash settlement transactions.  The outstanding quantity committed to the third swap as of December 31, 2006 is 2,400 MMBtu’s per day beginning January 1, 2007 through December 31, 2007.  The total quantity is 876,000 MMBtu’s.  The fixed price in the agreement is $5.12 per MMBtu (CIG pricing).

The outstanding quantity committed to the fourth swap as of December 31, 2006 is 1,200 MMBtu’s per day beginning January 1, 2008 through December 31, 2008.  The total quantity is 439,200 MMBtu’s.  The fixed price in the agreement is $6.61 per MMBtu (CIG pricing).

As of December 31, 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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” was an unrealized gain of $3.5 million as of December 31, 2006.

Realized gains or losses from the settlement of gas derivative contracts are reported in the total operating revenues section of 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.

At the time of the filing of this report, Storm Cat had the following commodity swaps in place:

Commodity

 

Period

 

Quarterly Volume
(MMBtu)

 

Fixed Price per
MMBtu

Natural Gas

 

01/2007

 

to

 

03/2007

 

135,000

 

$7.16

Natural Gas

 

04/2007

 

to

 

06/2007

 

136,500

 

$7.16

Natural Gas

 

07/2007

 

to

 

09/2007

 

138,000

 

$7.16

Natural Gas

 

10/2007

 

to

 

12/2007

 

138,000

 

$7.16

Natural Gas

 

01/2008

 

to

 

03/2008

 

136,500

 

$7.16

Natural Gas

 

04/2008

 

to

 

06/2008

 

136,500

 

$7.16

Natural Gas

 

07/2008

 

to

 

09/2008

 

138,000

 

$7.16

Natural Gas

 

10/2008

 

to

 

12/2008

 

138,000

 

$7.16

Natural Gas

 

01/2009

 

to

 

03/2009

 

135,000

 

$7.16

Natural Gas

 

04/2009

 

to

 

06/2009

 

136,500

 

$7.16

Natural Gas

 

07/2009

 

46,500

 

$7.16

 

Commodity

 

Period

 

Quarterly Volume
(MMBtu)

 

Fixed Price per
MMBtu

 

Natural Gas

 

01/2007

 

to

 

03/2007

 

180,000

 

$7.27

 

Natural Gas