Fellows Energy Ltd. Form 10-QSB
United States
Securities And Exchange Commission

Washington, D.C. 20549
_____________________
 
Form 10-QSB
_____________________

 
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2006
 
Commission File Number: 000-33321
 
_____________________
Fellows Energy Ltd.
(Exact Name of Small Business Issuer as Specified in its Charter)
_____________________
 
 
 
Nevada
 
33-0967648
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
370 Interlocken Boulevard, Suite 400
Broomfield, Colorado 80021
 
(Address of Principal Executive Offices)
 
(303) 327-1525
(Registrant’s Telephone Number, Including Area Code)
_____________________
 
 
Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 

¨ Yes x No

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date: As of August 14, 2006 there were 63,828,173 shares of the issuer’s $.001 par value common stock issued and outstanding.
 
Transitional Small Business Disclosure Format: ¨ Yes x No

FELLOWS ENERGY LTD.

Quarterly Report on Form 10-QSB for the
Quarterly Period Ending June 30, 2006

Table of Contents
 

PART I. FINANCIAL INFORMATION
 
 
 
    Item 1.  Financial Statements 
 
 
 
Balance Sheets: 
 
June 30, 2006 (Unaudited)  
3  
 
 
Statements of Operations: 
 
Three and Six Months Ended June 30, 2006 and 2005 (Unaudited) 
4
 
 
Statements of Cash Flows: 
 
Six Months Ended June 30, 2006 and 2005 (Unaudited) 
5 
 
 
Notes to Unaudited Financial Statements:  
 
June 30, 2006
6-11
 
 
    Item 2.  Management Discussion and Analysis
14
 
 
    Item 3.  Controls and Procedures  
20
 
 
PART II. OTHER INFORMATION
 
 
 
    Item 1.  Legal Proceedings
21
 
 
    Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds 
21
 
 
    Item 3. Defaults Upon Senior Securities 
21
 
 
    Item 4. Submission of Matters to a Vote of Security Holders
21
 
 
    Item 5.  Other Information 
21
 
 
    Item 6. Exhibits
21
 
 
Signatures
22

2

Part I: Financial Information
Item 1.
Financial Statements

Fellows Energy Ltd.
Balance Sheet
(Unaudited)
     
June 30, 2006 
    
December 31, 2005
  
Assets
            
Cash and cash equivalents
  
$
440,334
  
$
347,558
  
Marketable securities, available-for-sale
    
—
    
405,556
  
Accounts receivable
    
238,095
    
—
  
Interest receivable
    
2,568
    
179
  
Prepaid expenses
    
213
    
—
  
Note receivable
    
 179,879
    
 99,879
  
Total current assets
    
861,089
    
853,172
  
 
              
Unproved oil & gas property 
    
10,261,813
    
9,575,813
  
Equipment, net of $45,959 and $18,418 accumulated depreciation respectively
    
1,467,780
    
287,836
  
Deposits
    
162,000
    
716,000
  
Restricted cash
    
260,000
    
235,000
  
Deferred debt issue costs
    
  381,263
    
  533,769
  
 
              
Total assets  
  
$
13,393,945
  
$
12,201,590
  
 
              
Liabilities And Stockholders’ Equity
              
Accounts payable and accrued expenses
  
$
355,049
  
$
313,703
  
Convertible debenture interest payable
    
165,700
    
—
  
Joint venture partner interest payable
    
 123,584
     
 —
  
 
              
Total current liabilities
    
644,333
    
313,703
  
 
              
Long term payables
    
41,780
    
—
  
Convertible debenture
    
3,977,155
    
5,063,848
  
Notes payable
    
1,340,286
    
12,000
  
Stockholders’ equity:
              
Preferred stock, $.001 par value; 25,000,000 shares
              
authorized; none outstanding
    
—
    
—
  
Common stock, $.001 par value; 100,000,000 shares
              
authorized; 61,492,903 shares issued and outstanding
    
61,493
    
52,545
  
Additional paid-in capital
    
18,338,395
    
15,973,152
  
Stock issuance obligation
    
159,493
    
—
  
Stock pledged as collateral
    
(1,665,000
)
  
(1,665,000
)
Accumulated deficit
    
(9,508,473
)
  
(7,555,331
)
Accumulated other comprehensive income
     
 4,483
     
 6,673
  
 
              
Total stockholders’ equity
     
 7,390,391
     
 6,812,039
  
 
              
Total liabilities and stockholders’ equity
  
$
13,393,945
    
12,201,590
  

See accompanying notes to financial statements
 
 

 
3

Fellows Energy Ltd.
Statements of Operations
(Unaudited)
 
  
   
Three Months Ended
June 30,
  
Six Months Ended
June 30,
  
   
2006
  
 2005
  
2006
  
2005
  
                    
Revenue
  
$
282,926
  
$
—
  
$
343,841
  
$
—
  
 
                  
Operating expense
                  
Exploration and production
    
348,124
    
31,277
    
564,196
    
243,768
  
General and administrative
     
 1,302,310
    
 551,084
     
 1,994,445
    
 984,320
  
 
                  
Operating (loss)
    
(1,367,508
)
  
(582,361
)
  
(2,214,800
)
  
(1,228,088
)
 
                  
Other income (expense)
    
365
    
136
    
365
    
3,369
  
Interest expense
    
(59,758
)
  
(48,094
)
  
(76,757
)
  
(129,408
)
Gain on sale of property
    
—
    
5,393
    
—
    
1,442,674
  
Gain on extinguishment of debt
    
—
    
383,531
    
—
    
383,531
  
Project revenue applied as credit to purchase
   
—
    
—
    
198,361
    
—
  
Note receivable default penalty
    
—
    
—
    
80,000
    
—
  
Re-sale of pipe
    
34,644
    
—
    
34,644
    
—
  
Insurance rebates and project purchase credit
    
—
    
—
    
19,993
    
—
  
 
                  
Income (loss) before income tax
    
(1,392,257
)
  
(241,395
)
  
(1,958,194
)
  
472,078
  
 
                  
Income tax expense
    
—
    
—
    
—
    
—
  
Deferred tax benefit
    
—
    
—
    
—
    
—
  
 
                  
Net income (loss)
  
$
(1,392,257
)
$
(241,395
)
$
(1,958,194
)
$
472,078
  
 
                  
Other comprehensive income (loss)
                  
Unrealized holding gains on marketable securities
    
(9,641
)
  
—
    
4,483
    
—
  
Comprehensive Income (loss)
  
$
(1,401,898
)
$
(241,395
)
$
(1,953,711
)
$
472,078
  
 
                  
Basic earnings (loss) per share
  
$
(0.02
)
$
-nil-
  
$
(0.03
)
$
0.01
  
Basic weighted average shares outstanding 
    
59,930,245
    
47,164,723
    
57,591,674
    
44,484,056
  
Diluted earnings (loss) per share
    
(0.02
)
  
-nil-
    
(0.02
)
  
0.01
  
Diluted weighted average shares outstanding
    
 85,896,866
     
 66,252,800
    
 83,558,295
    
 63,572,133
  
 

See accompanying notes to financial statements



4

Fellows Energy Ltd.
Statements of Cash Flows
(unaudited)
 
 
  
Six Months Ended
June 30, 
  
 
  
 2006
  
 2005
  
Cash flow from operating activities:
          
Net income (loss)
  
$
(1,958,194
)
$
472,078
  
Adjustments to reconcile net income to net cash used in operating activities:
          
Loss on sale of marketable securities
    
50,530
    
—
  
Gain on sale of unproved oil and gas property
    
—
    
(1,442,674
)
Gain from extinguishment of debt
    
—
    
(383,531
)
Debt issue costs and discount amortization
   
870,231
    
102,928
  
Depreciation
    
27,541
    
3,878
  
Expenses paid with stock issuance
    
—
    
264,500
  
Interest paid with stock issuance
    
—
    
44,712
  
Changes in operating assets and liabilities:
          
Receivables
    
(320,484
)
  
(130
)
Prepaid expense
    
(213
)
  
(71,378
)
Deferred debt issue costs
    
152,506
    
(459,868
)
Accounts payable and accrued expenses
    
41,346
    
(188,019
)
Convertible debenture interest payable
    
165,700
    
85,700
  
Joint venture partner interest payable
    
123,584
    
—
  
Long term payables
    
41,780
    
—
  
Net cash provided by (used in) operating activities
    
(805,673
)
  
(1,571,805
)
 
          
Cash flow from investing activities:
          
Proceeds from sale of marketable securities
    
355,026
    
—
  
Deposits
    
554,000
    
—
  
Proceeds on sale of oil and gas property
    
—
    
1,930,083
  
Purchase of software
   
(43,430
)
      
Purchase of Furniture & fixtures
    
(1,699
)
      
Property sale receivable
    
—
    
—
  
Unproved oil and gas property additions
    
(686,000
)
  
(1,493,792
)
Restricted Cash
    
(25,000
)
  
(100,000
)
Purchase of equipment
    
(1,162,356
)
  
(9,555
)
Net cash provided by (used in) investing activities
    
(1,009,459
)
  
326,736
  
 
          
Cash flow from financing activities:
          
Proceeds from issuance of convertible debenture
    
—
    
3,849,685
  
Payments on convertible debenture
    
(501,453
)
  
—
  
Proceeds from note payable
    
—
    
—
  
Issuance of common stock
    
—
    
922,376
  
Borrowings on note payable
    
2,700,000
    
80,000
  
Payments on notes payable
    
(290,639
)
  
(1,252,848
)
Net cash provided by financing activities:
    
1,907,908
    
3,599,213
  
 
          
Net increase (decrease) in cash and equivalents
    
92,776
    
2,354,144
  
Cash and equivalents at beginning of period
    
347,558
    
149,027
  
 
          
Cash and equivalents at end of period 
  
$
440,334
  
$
2,503,171
  
 
          
Supplemental Disclosure of Cash Flow and Non-cash Investing and Financing Activity:
          
Income tax paid
  
$
—
  
$
—
  
Interest paid
  
$
—
  
$
81,750
  
Non cash:
          
Conversion of $350,000 convertible note into common stock
  
$
—
  
$
394,711
  
Acquisition of oil & gas interest in exchange for common stock
  
$
—
  
$
600,000
  
Convertible debenture paid with stock issuance
  
$
1,696,424
  
$
—
  
Legal and advisory services in exchange for stock issuance obligation
  
$
159,493
  
$
—
  

 See accompanying notes to financial statements
  
 
5

Fellows Energy Ltd.
Notes to Unaudited Financial Statements
June 30, 2006
 
Note 1—Basis of Presentation and Nature of Operations
 
We have prepared the accompanying unaudited condensed financial statements in accordance with accounting principles generally accepted in the United States for interim financial information. They do not include all information and notes required by generally accepted accounting principles for complete financial statements. You should read these financial statements with our Annual Report on Form 10-KSB for the year ended December 31, 2005, as well as the 10-QSB for the quarter ended March, 31, 2006. In our opinion, we have included all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation. Operating results for the quarters presented are not necessarily indicative of the results that you may expect for the full year.

We are engaged in the exploration, extraction, processing and reclamation of coal bed methane, natural gas, and oil projects in the western United States. We were incorporated in the state of Nevada on April 9, 2001 as Fuel Centers, Inc. On November 12, 2003, we changed our name to Fellows Energy Ltd. Our principal offices are located in Broomfield, Colorado.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income reflects changes in equity that result from transactions and economic events from non-operating sources. For the Company, such items consisted of unrealized holding gains and losses on market securities for the current period.

Earnings (Loss) per share
 
We compute basic and diluted earnings (loss) per share as net income or loss divided by the weighted average number of shares of common stock outstanding for the period. Diluted earnings per share is similar to basic earnings per share but also presents the dilutive effect on a per share basis of securities convertible into common shares (e.g. stock options, warrants and other convertible securities) as if they had been converted at the beginning of the periods presented. In periods in which we incur losses we exclude potential shares from convertible securities from the computation of diluted loss per share as their effect is antidilutive in those periods.

Stock Options
 
On October 9, 2003, we adopted an incentive stock option plan, pursuant to which shares of our common stock are reserved for issuance to satisfy the exercise of options. The plan authorizes up to 2,000,000 shares of authorized common stock to be purchased pursuant to the exercise of options. Our stockholders approved the plan on November 10, 2003. On September 15, 2004, we granted an option for 200,000 shares to our CEO, 150,000 shares to our vice president and 125,000 shares to an employee. These options are exercisable at $0.80 per share, the price of our stock on the grant date. The options vested 50% on the grant date and vest 50% on September 15, 2005. On October 3, 2005, we granted an option for 100,000 shares to our CEO, 150,000 to our Vice President and 175,000 and 200,000 shares to two employees respectively. The options vest 6 months from the date of grant.

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), “Share-Based Payment” (“SFAS 123(R)”), which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS 123(R) is effective for public companies for the first fiscal year beginning after June 15, 2005, supersedes Accounting Principles Board Opinion No. 25 (“APB 25”), Accounting for Stock Issued to Employees, and amends SFAS 95, Statement of Cash Flows. SFAS 123(R) eliminates the option to use APB 25’s intrinsic value method of accounting and requires recording expense for stock compensation based on a fair value based method.

On July 1, 2005, the Company adopted the “modified prospective method” which requires the Company to recognize compensation costs, for all share-based payments granted, modified or settled, in financial statements issued subsequent to July 1, 2005, as well as for any awards that were granted prior to the adoption date for which the required service has not yet been performed. The adoption of SFAS 123(R) did not have a material effect on the Company’s financial condition or results of operations because subsequent to July 1, 2005, the Company did not enter into any share-based transactions.
 
6
Prior to July 1, 2005, the Company accounted for its stock-based compensation using APB 25 and related interpretations. Under APB 25, compensation expense was recognized for stock options with an exercise price that was less than the market price on the grant date of the option. For stock options with exercise prices at or above the market value of the stock on the grant date, the Company adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”) for the stock options granted to the employees and directors of the Company. Accordingly, no compensation cost was recognized for these options prior to June 30, 2005.

Compensation expense has been recognized in the accompanying financial statements for stock options that were issued to our outside consultants. Had compensation expense for the options granted to our employees and directors been determined based on the fair value at the grant date for options, consistent with the provisions of SFAS 123, the Company’s net (loss) income and net (loss) income per share for the three months ended March 31, 2006 and 2005 would have been the pro forma amounts indicated below.

We estimate the fair value of the options we grant at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the quarter ended June 30, 2006: a risk-free interest rate of 4.37%; no expected dividend; a volatility factor of 97.5%; and a maturity date of ten years.
 
For purposes of pro forma disclosures, we amortize to expense the estimated fair value of the options over the options’ vesting period. Our pro forma information for the second quarter of 2006 is as follows (in thousands, except per share amounts).

 
  
Six Months Ended
  
Six Months Ended
  
 
  
June 30, 2006
  
June 30, 2005
  
 
  
 
  
 
  
Net Income (loss) as reported
  
$
(1,958,829
)
$
472,078
  
Deduct: Total stock based employee compensation expense
          
determined under fair value based method for all awards
    
(13,955
)
  
(51,100
)
 
          
Pro forma net income (loss)
  
$
(1,944,874
)
$
420,978
  
 
          
Basic and diluted earnings per share—as reported  
  
$
-nil-
  
$
-nil-
  
 
          
Pro forma basic and diluted gain per share  
  
$
-nil-
  
$
-nil-
  
 
The Black-Scholes option-pricing model was developed for use in estimating the fair value of traded options that have no vesting restrictions, are fully transferable, and are not subject to trading restrictions or blackout periods. In addition, option valuation models require the input of highly subjective assumptions, including the expected stock price volatility. Because our employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, it is our opinion that the existing models do not necessarily provide a reliable single measure of the fair value of our employee stock options.
 
Reclassifications

We have made certain reclassifications to the 2005 financial statements to conform with the 2006 financial statement presentation.
 

 
7

Note 2—Going Concern
 
As shown in the accompanying financial statements, we have incurred significant operating losses since inception and previously incurred a loss on our discontinued automotive fuel business. As of June 30, 2006, we have limited financial resources until such time that we are able to generate additional positive cash flow from operations. These factors raise substantial doubt about our ability to continue as a going concern. However, in the first quarter of 2006 we closed the acquisition of an interest in the Carbon County project, a producing gas field, and commenced production in the first well of the Creston project.  We have increased production on both projects, and expect to continue to augment production and cash flow. Our ability to continue to achieve and maintain profitability and positive cash flow is dependent upon our ability to locate profitable mineral properties, generate revenue from our planned business operations, and control exploration cost. Management plans to fund its future operation by joint venturing, obtaining additional financing, and attaining additional commercial production. There is no assurance that we will be able to obtain additional financing from investors or private lenders, or that additional commercial production can be attained. Although management believes production from these two projects will generate revenues sufficient to sustain the Company, no assurance can be given that such revenues will be generated from the projects and there is no assurance that we will be able to obtain additional financing from investors or private lenders.

Note 3—Sale of Oil and Gas Property

In February 2005 we sold the Circus project for $2.04 million to an unrelated third party. We acquired the leases in October, 2004, with a total cost of $487,000 and thus realized a gain of $1.5 million on the sale. Additionally, we incurred $53,000 of closing cost on the sale.   

Note 4—Deposits

In March of 2006, we acquired the interests in one producing property and maintained our interest in three other exploration oil and gas properties. The project we acquired is known as the Carbon County project. We continue to retain deposits of $66,000, $65,000 and $31,000 on other projects for which we are negotiating. All the funds are fully refundable.

Note 5—Marketable Securities

The Company determines the appropriate classification of its investments in debt and equity securities at the time of purchase and reevaluates such determinations at each balance-sheet date. Debt securities are classified as held-to-maturity when the Company has the positive intent and ability to hold the securities to maturity. Debt securities for which the Company does not have the intent or ability to hold to maturity are classified as available-for-sale. Held-to-maturity securities are recorded as either short-term or long-term on the Balance Sheet based on contractual maturity date and are stated at amortized cost. Marketable securities that are bought and held principally for the purpose of selling them in the near term are classified as trading securities and are reported at fair value, with unrealized gains and losses recognized in earnings. Debt and marketable equity securities not classified as held-to-maturity or as trading, as classified as available-for-sale, and are carried at fair market value, with the unrealized gains and losses included in the determination of comprehensive income and reported in stockholders’ equity.

The fair value of substantially all securities is determined by quoted market prices. The estimated fair value of securities for which there are no quoted market prices is based on similar types of securities that are traded in the market. 

Note 6—Note Receivable

In October 2005, we entered into an agreement to obtain up to a 75% working interest in certain well bores owned by Mountain Oil and Gas, known as the Creston project. In connection with this, we advanced Mountain Oil and Gas approximately $80,000 and $19,900 for the purpose of well bonding and working capital. Of this, $80,000 was due and payable back to the Company on December 30, 2005 either in cash or labor towards the workover of the well bore. As a result of this default, we are now entitled to $160,000 ($80,000 plus an additional $80,000) of the net revenues from the 1-16A1E well beginning January 1, 2006. Repayment is secured by a pumping unit located on the Dye-Hall well for the value of the working capital and well bonding. At June 30, 2006, we consider all amounts outstanding under this agreement as fully collectible.

8
Note 7—Note Payable

Over the period October 2005 through June 2006 we borrowed a total of $224,000 on an unsecured 8% demand note payable to an entity controlled by our CEO. In the second quarter 2006, we paid $157,000 of principal on the note.

In March 2006, we borrowed $750,000 on a secured 12% note payable. The note is for a period of 36 months, with only interest payments due during the first six months.

Note 8—Related Party Transactions

At June 30, 2006 we owed $83,000 on an unsecured, 8% demand note payable to an entity controlled by our CEO.

In October 2005, we entered into a joint venture project funding agreement for the Creston project, the financing for which was secured by our President and CEO as well as Diamond Oil and Gas Corporation, an entity controlled by our President and CEO. The agreement was finalized in April 2006, and as of June 30, 2006, the total of $1,250,000 in funding has been provided.

Note 9—Common Stock

We issued 2,513,630 and 4,033,043 shares of common stock in the first and second quarters of 2006 for the debt service of our convertible debentures. First quarter related redemption share payments amounted to 617,433 shares, 1,341,500 shares, and 554,697 shares at an average price of $0.37, $0.27, and $0.27 per share respectively. Second quarter related redemption share payments amounted to 751,818 shares, 1,425,192 shares, 1,737,976 shares, and 118,057 shares at an average price of $0.27, $0.25, $0.21, and $0.27 per share respectively.

In May 2006 we issued 700,000 shares in connection with the joint venture of one of our projects with a price of $0.28, we also issued 861,921 shares at $0.25 in accordance with ratchet down rights under the May 18, 2005 private placement. In addition, we issued 790,000 shares at $0.32 in connection with the joint venture secured project funding.

In June 2006, we issued 48,980 shares at $0.25 in accordance with the May 2006 note payable.

As of June 30, 2006, we intend to issue common stock for obligations amounting to $159,000.

Note 10 —Convertible Debentures

On June 17, 2005, we closed a financing pursuant to a securities purchase agreement with three accredited investors for the issuance of $5,501,200 in face amount of debentures maturing at the end of the 27th month from the date of issuance, and three year warrants to purchase common stock of the company. The debentures bear no interest and the investors paid $3,849,685, after discounts of $1,651,515, for the debentures. A commission of 9% on the $3.85 million was paid in connection with the transaction, and we paid $100,000 in legal fees, resulting in net proceeds to the company of $3,403,267. The debentures are unsecured and we are obligated to pay 1/24th of the face amount of the debenture on the first of every month, starting October 1, 2005, which payment can be made in cash or in common stock. We may pay this amortization payment in cash or in stock at the lower of $0.60 per share (the Set Price) or 80% of the volume weighted average price of the stock for the five trading days prior to the repayment date. In the event that we make the payment in cash, we shall pay 110% of the monthly redemption amount. At any time after 90 days from the date that a registration statement registering the shares of common stock underlying the debentures and warrants is declared effective (the Effective Date), and if certain conditions are met, we have the right to redeem some or all of the debentures in a cash amount equal to 110% of the face amount of the debentures being redeemed. At any time, the debentures are convertible into common stock at the Set Price.

9
We issued warrants to the investors, expiring June 17, 2008, to purchase 4,584,334 shares of restricted common stock, exercisable at a per share of $0.649. In addition, the exercise price of the warrants will be adjusted in the event we issue common stock at a price below the exercise price, with the exception of any securities issued pursuant to a stock or option plan adopted by our board of directors, issued in connection with the debentures issued pursuant to the securities purchase agreement, or securities issued in connection with acquisitions or strategic transactions. Upon an issuance of shares of common stock below the exercise price, the exercise price of the warrants will be reduced to equal the share price at which the additional securities were issued and the number of warrant shares issuable will be increased such that the aggregate exercise price payable for the warrants, after taking into account the decrease in the exercise price, shall be equal to the aggregate exercise price prior to such adjustment.

Warrants to purchase 250,000 shares, at the same price and for the same term as the warrants issued to the investors, have been issued to HPC Capital Management as additional compensation for its services in connection with the transaction with the investors.
 
In addition to the $1,651,515 cash discount, we also recorded a discount of $626,042 based on a Black-Scholes model valuation of the 4,584,334 warrants issued to the debenture holders and the 250,000 warrants issued to HPC Capital Management.

On September 21, 2005, we closed a financing pursuant to a securities purchase agreement with two accredited investors for the issuance of $3,108,000 in face amount of debentures maturing December 21, 2008, and three year warrants to purchase common stock of the company. The debentures do not accrue interest and the investors paid $2,174,947.52 for the debentures. A commission of 8% on $2,000,000 raised was paid to in connection with the transaction, and we placed $50,000 in escrow for the payment of future legal fees, resulting in net proceeds to the company of $1,964,947.52 before $39,000 in associated current legal fees. Net proceeds will be used for general working capital. The debentures are unsecured and we are obligated to pay 1/24th of the face amount of the debenture on the first of every month, starting January 1, 2006, which payment can be made in cash or in restricted common stock. We may pay this amortization payment in cash or in stock at the lower of $0.75 per share (the Set Price) or 80% of the volume weighted average price of the stock for the five trading days prior to the repayment date, provided that there is an effective registration statement and the monthly conversion price is greater of than $0.60. In the event that we make the payment in cash, we shall pay 110% of the monthly redemption amount. At any time after 90 days from the date that a registration statement registering the shares of common stock underlying the debentures and warrants is declared effective (the Effective Date), and if certain conditions are met, we have the right to redeem some or all of the debentures in a cash amount equal to 110% of the face amount of the debentures being redeemed. At any time, the debentures are convertible to restricted common stock at the Set Price.

We issued warrants to the investors, expiring September 21, 2008, to purchase 2,072,000 shares of restricted common stock, at a price per share of $0.80. The number of shares underlying the warrants equals 50% of the shares issuable on full conversion of the debentures at the set price (as if the debentures were so converted on September 21, 2005). In addition, the exercise price of the warrants will be adjusted in the event we issue common stock at a price below the exercise price, with the exception of any securities issued pursuant to a stock or option plan adopted by our board of directors, issued in connection with the debentures issued pursuant to the securities purchase agreement, or securities issued in connection with acquisitions or strategic transactions. Upon an issuance of shares of common stock below the exercise price, the exercise price of the warrants will be reduced to equal the share price at which the additional securities were issued and the number of warrant shares issuable will be increased such that the aggregate exercise price payable for the warrants, after taking into account the decrease in the exercise price, shall be equal to the aggregate exercise price prior to such adjustment.

Warrants to purchase 100,000 shares, at the same price and for the same term as the warrants issued to the investors, have been issued to HPC Capital Management as additional compensation for its services in connection with the transaction with the investors.

In addition to the $933,052 cash discount, we also recorded a discount of $614,905 based on a Black-Scholes model valuation of the 2,072,000 warrants issued to the debenture holders and the 100,000 warrants issued to HPC Capital Management.

Note 11—Unproved Oil and Gas Property

On September 12, 2005, we entered into an agreement to purchase a gas field in Carbon County, Utah (the “Carbon County Project”) producing approximately 30 million cubic feet of natural gas per month. The field comprises 5,953 gross acres (4,879 net acres) with three gas wells currently producing and has an additional six wells drilled that are presently shut-in. Production is derived from the Ferron Sandstone formation, and the gas is marketed into the adjacent gas pipeline operated by Questar Gas Resources. The field has potential for 20 additional well sites on 160 acre spacing on the undeveloped acreage. The property is adjacent to our Gordon Creek project and to the successful Drunkards Wash field originally developed by River Gas Corp. On March 13, 2006 we closed the purchase of an interest in the Carbon County project, and have commenced operations on the project along with a joint venture partner, MBA Resources, Corp.
 
10
On October 25, 2005, the Company announced that it had entered into a participation agreement with Mountain Oil and Gas, Inc., Creston Resources Ltd, and Homeland Gas and Oil Ltd. (collectively “Creston”), and is completing arrangements with private investors, whereby the Company is to supply operating expertise and program supervision to earn working interests in up to 45 producing oil wells in the Uintah Basin of Utah. The Company has since commenced a rework program to re-complete previously-completed zones and extend behind pipe reserves in the wells, located primarily in the prolific Altamont-Bluebell Field, which has produced over 350 million barrels of oil equivalent. Creston will retain the current or historical production while Fellows and the private investors will earn a variable percentage of the production increase resulting from the reworking operations. Work has commenced on two of the first four, and we plan on maintaining continuous operations until all wells have been brought to full potential.
 
Under the participation agreement, Fellows is to rework wells as necessary to revitalize production across the 9,000 acres that pertain to the wells. Due to the over-pressured, fractured nature of reservoir in the field, as well as the large vertical extent of potential pay zones, many of the wells have formation damage resulting from high drilling mud weights and cementing operations. These conditions have left many zones unable to produce to their potential. Fellows will employ a variety of conventional and innovative proprietary techniques to reduce the effects of formation damage and increase oil and gas recovery. 

In mid-2004 we drilled the 10-33C2 well on the Johns Valley Project in Utah to its planned depth of 1,365 feet. We drilled through a potentially productive coal seam. We cored the well and have sent the core to a lab for evaluation. We have expensed the cost of this well as exploration expense. On April 14, 2005, we entered into a letter of intent to purchase the project, and we are under continuing negotiations to purchase the project or an interest in the project through an earn-in arrangement. We have made a payment of $300,000 toward the purchase. We are currently in negotiations to enter into an industry standard earn-in agreement on the project, and plan to acquire existing seismic data to evaluate further exploration on the property.



 
11

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Forward-Looking Statements

This report includes certain forward-looking statements. Forward-looking statements are statements that predict the occurrence of future events and are not based on historical fact. Forward-looking statements may be identified by the use of forward-looking terminology, such as “may”, “shall”, “will”, “could”, “expect”, “estimate”, “anticipate”, “predict”, “probable”, “possible”, “should”, “continue”, or similar terms, variations of those terms or the negative of those terms. We have written the forward-looking statements specified in the following information on the basis of assumptions we consider to be reasonable. However, we cannot predict our future operating results. Any representation, guarantee, or warranty should not be inferred from those forward-looking statements.
 
The assumptions we used for purposes of the forward-looking statements specified in the following information represent estimates of future events and are subject to uncertainty in economic, legislative, industry, and other circumstances. As a result, judgment must be exercised in the identification and interpretation of data and other information and in their use in developing and selecting assumptions from and among reasonable alternatives. To the extent that the assumed events do not occur, the outcome may vary substantially from anticipated or projected results. Accordingly we express no opinion on the achievability of those forward-looking statements. We cannot guarantee that any of the assumptions relating to the forward-looking statements specified in the following information are accurate. We assume no obligation to update any such forward-looking statements.

Overview

On January 5, 2004, we began operations as an oil and gas exploration company. We acquired interests in certain assets owned by Diamond Oil & Gas Corporation, in exchange for 3,500,000 shares of common stock. The transaction was deemed to have a value of $6,405,000. The assets included certain oil and gas projects, as well as the right to enter into the Exploration Services Funding Agreement with Thomasson Partner Associates, Inc. of Denver, Colorado. Diamond is controlled by our CEO, George S. Young. The operations we plan for the remainder of 2006 will be to continue to operate the Carbon County and Creston projects and to continue exploring and drilling leases we have acquired, as well as seeking to acquire and explore additional property. Our goal is to discover substantial commercial quantities of oil and gas, including coalbed methane, on the properties.

In February 2005 we amended our Exploration Services Agreement with Thomasson Partner Associates. Thomasson Partner Associates provides large-scale exploration opportunities to the oil and gas industry. By this agreement Thomasson Partner Associates provides to us the first right to review and purchase up to a 50% interest (as amended, a 100% interest beginning in February 2005) in oil and natural gas exploration projects developed by Thomasson Partner Associates. The agreement provides for Thomasson Partner Associates to present to us a minimum of eight project opportunities with the reasonable potential of at least 200 Bcf of natural gas reserves or 20 million barrels of oil reserves. We have the first right to review exploration projects developed by Thomasson Partner Associates and, after viewing a formal presentation regarding a project, we have a period of thirty days in which to acquire up to 100% of the project. We are not obligated to acquire any project. In consideration, in 2004 we paid to Thomasson Partner Associates a $400,000 acquisition consulting fee, and paid an $800,000 fee in 2005. We also pay a fee for each project we acquire from Thomasson Partner Associates. The agreement continues year to year until either party gives 90 days written notice of termination. Projects acquired from Thomasson Partner Associates include the Weston County project in Wyoming, the Gordon Creek project in Utah, the Carter Creek project in Wyoming, the Circus project in Montana, the Bacaroo project in Colorado, the Platte project in Nebraska, and the Badger project in South Dakota. In 2005, we paid Thomasson a total of $1,350,000, including the $800,000 acquisition consulting fee. As of June 30, 2006, we have not yet paid any acquisition consulting fees under the agreement. However, we anticipate acquiring additional projects and paying as appropriate the project acquisition fees for such projects that we acquire. We are negotiating an extension to maintain our rights under the agreement as to our first opportunity to review projects generated by Thomasson.

Operations Plans

During the next twelve months, we expect to pursue oil and gas operations on some or all of our property, including the acquisition of additional acreage through leasing, farm-out or option and participation in the drilling of oil and gas wells. We intend to continue to evaluate additional opportunities in areas where we feel there is potential for oil and gas reserves and production, and may participate in areas other than those already identified, although we cannot assure that additional opportunities will be available, or if we participate in additional opportunities, that those opportunities will be successful.
 
12
Our current cash position is not sufficient to fund our cash requirements during the next twelve months, including operations and capital expenditures. We intend to continue joint venture or equity and/or debt financing efforts to support our current and proposed oil and gas operations and capital expenditures. We may sell interests in our properties. We cannot assure that continued funding will be available.

We have not entered into commodity swap arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. We have no off-balance sheet arrangements.

Our future financial results continue to depend primarily on (1) our ability to discover or purchase commercial quantities of oil and gas; (2) the market price for oil and gas; (3) our ability to continue to source and screen potential projects; and (4) our ability to fully implement our exploration and development program with respect to these and other matters. We cannot assure that we will be successful in any of these activities or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production.

Oil & Gas Projects

Weston County, Wyoming

In November 2004 we executed a joint venture agreement with JMG Exploration, to drill our Weston County and Gordon Creek projects. Under the agreement, JMG Exploration will receive a 50% interest in exchange for spending $2,000,000 in exploration and drilling activity on the two projects by November 7, 2005. In addition, JMG Exploration loaned $1,500,000 to us with a short-term note. In connection with repayment of the JMG Exploration loan, we have assigned the remaining 50% interest in the Weston County project to JMG Exploration, subject to our right to reacquire those interests for approximately $391,000 by June 30, 2005, which right has been exercised. As part of the full settlement of the $1,500,000 note, JMG Exploration’s commitment to spend $2,000,000 in exploration and drilling activity by November 7, 2005 has been terminated. In connection with this transaction, we recorded a gain from extinguishment of debt of $383,531.

The Weston County project is a 19,290-acre project on the east flank of the Powder River Basin. The prospect is a potential extension of an existing producing field. We are continuing our work and evaluation with JMG Exploration on permitting and other pre-drilling activities. In addition, we are targeting nearby locations with potential in the Minnelusa sandstone and Dakota channel sandstone formations.

Gordon Creek, Utah

JMG Exploration will also drill on the 5,242-acre Gordon Creek project, which we acquired from The Houston Exploration Company for $288,000. The Gordon Creek project is in an area of known coal resources in Carbon County in eastern Utah near other operating coal bed methane projects, such as the Drunkard’s Wash Project, which our project personnel successfully drilled previously for River Gas Corporation.

Based on exploration results, JMG Exploration has indicated its intent to sell a portion of its working interest to Enterra Energy Trust in an arrangement under which JED Oil, Inc. under a development agreement with Enterra, will complete any development programs on the projects.

Carter Creek, Wyoming

In 2004 we purchased the 10,678-acre Carter Creek Project in the southern Powder River Basin. Although we previously contemplated drilling on the project, and we believe much of the project acreage is drill-ready, we have not yet commenced any drilling activities to date due to capital constraints. We are now entertaining proposals from industry partners for joint venturing the drilling and production activities. Based on our analysis of the geologic structure of this region, we anticipate productive sections in the Cretaceous, Niobrara, Turner (Frontier) and Mowry layers, in that several existing wells in the Carter Creek area currently produce oil.

13
Work continues to identify additional areas for leasing and drillsite delineation. We will continue our evaluation and preparation for drilling the fractured shales. It is likely that horizontal drilling methods will be identified as an effective technique to tap into the potential of this field.

Overthrust, Utah and Wyoming

In 2004 we optioned the Overthrust project for a 65% working interest in 183,000 acres of oil, gas and coal bed methane leases in northeastern Utah and southwestern Wyoming from Quaneco, an Oklahoma company. We plan to test the three identified coal seams that run through much of the area. Previous drilling has included seven exploratory wells that identified multiple coal seams of Tertiary and Cretaceous age that appear to be prospective for coal bed methane. Some of the coal is of similar age and depositional condition to other productive coal bed methane fields.

We drilled our first well in the project in 2004, the Crane 6-7, in Rich County, Utah. The well reached a total depth of 4,280 feet. We cored coal and carbonaceous shale over a combined interval of 556 feet. In September 2004 we received the results from the gas desorption tests from the Spring Valley coal of the Frontier formation and the coal in the Bear River formation in the well. Results showed 253 cubic feet of gas per ton on an ash-free basis in the coal in the well. Lesser amounts of gas were present in the carbonaceous shale in the well. These tests corroborate earlier data that was generated by Quaneco, our partner on the project, suggesting that coal in an area of the project that lies a considerable distance north of the Crane 6-7 may contain between 200 and 400 cubic feet of gas per ton. We have expensed the cost of this well as exploration expense, although we may choose to re-enter the well at a later date. The overall results indicate the potential for coal in a much wider area to contain economic levels of coal bed methane, and will help to further guide our ongoing logging, geologic and drilling operations. We believe the Overthrust project has attractive coal bed methane potential, although additional exploration activity will be necessary to prove up gas reserves.

During the quarter ending September 30, 2005, we paid $275,000 to Quaneco representing payment obligations on the project and have negotiated extensions for various payment and work commitments in the future. Although we have not met all of the requirements and timelines for work and property payments as set forth under the 2004 option agreement, as amended, we continue to entertain discussions for extensions of the dates for work commitments and property payments. No assurance can be given that we will obtain any such extensions, and if obtained, what the terms and conditions of such extensions will be. In the event we are unable to successfully obtain such extensions, we may be unable to maintain our rights to the option, and will be subject to the terms of the option agreement, as amended..  We have progressed in the geologic evaluation of many of the potentially productive coal seams, and have delineated a number of areas for further work. Previous drilling activities have also identified reservoir quality sand which we believe has significant potential for conventional gas production if present in a favorable structural position. We will now review seismic data covering the area to evaluate the conventional gas potential simultaneously with our ongoing activities to pursue the coal bed methane potential of the project. After evaluating the seismic data and further evaluation of the logs from previous drilling, we will design and implement the next drilling phase to target both conventional and coal bed methane gas. The agreement is now under renegotiation.

Bacaroo, Colorado

In 2004 we optioned the Bacaroo project in Colorado through our affiliation with Thomasson Partner Associates. We believe the project is an opportunity to establish conventional oil and gas production with comparatively inexpensive drilling in areas of established production, while other projects being reviewed offer longer term, larger potential exploration opportunities. We are acquiring acreage in the prospect prior to commencing drilling operations.

Leasing and seismic evaluation activities continue. One entire target area is now under lease, and two additional areas are now undergoing leasing. We will perform additional geologic evaluation and permitting work in preparation for drilling in 2006.

14

Johns Valley Project, Utah

In early 2004 we acquired an agreement with Johns Valley Limited Partnership whereby we have the option to earn 70% working interest in 25,201 acres of oil and gas leases from the Utah School and Institutional Trust Lands Administration. In mid-2004 we drilled the 10-33C2 well in this project to its planned depth of 1,365 feet. We drilled through a potentially productive coal seam. We cored the well and have sent the core to a lab for evaluation. We have expensed the cost of this well as exploration expense. The option, which expired in October 2004, was for fifteen oil and gas leases that were for terms of ten years. On April 14, 2005, we entered into a letter of intent to purchase the project, and we are under continuing negotiations to purchase the project or an interest in the project through an earn-in arrangement.

Creston Project, Uintah Basin, Utah

On October 25, 2005, we announced that we had entered into a participation agreement with Mountain Oil and Gas, Inc., Creston Resources Ltd, and Homeland Gas and Oil Ltd. (collectively “Creston”), and are completing arrangements with private investors, whereby we are to supply operating expertise and program supervision to earn working interests in up to 45 producing oil wells in the Uintah Basin of Utah. We have since commenced a rework program to re-complete previously-completed zones and extend behind pipe reserves in the wells, located primarily in the Altamont-Bluebell Field. Creston will retain the current or historical production while we and the private investors will earn a variable percentage of the production increase resulting from the reworking operations. Work has commenced on two of the first four, and we plan on maintaining continuous operations until all wells have been brought to full potential.

Under the participation agreement, we are to begin reworking wells as necessary to revitalize production across the 9,000 acres that pertain to the wells. Due to the over-pressured, fractured nature of reservoir in the field, as well as the large vertical extent of potential pay zones, many of the wells have formation damage resulting from high drilling mud weights and cementing operations. These conditions have left many zones unable to produce to their potential. We will employ a variety of conventional and innovative proprietary techniques to reduce the effects of formation damage and attempt to increase oil and gas recovery.

During the first quarter of 2006, we completed the workover on the first well which commenced production at a daily rate of 100 BOE. We are now evaluating the next wells to be re-completed. In addition, we received joint venture financing arrangements with private investors to provide for $1.25 million in funds to conduct the reworking program.

Carbon County Project, Utah

On September 12, 2005, we entered into an option agreement to purchase a gas field in Carbon County, Utah which was producing approximately 30 million cubic feet of natural gas per month. The field comprises 5,953 gross acres (4,879 net acres) with three gas wells currently producing and has an additional five wells drilled that are presently shut-in. Production is derived from the Ferron Sandstone formation, and the gas is marketed into the adjacent gas pipeline operated by Questar Gas Resources. The acquisition included an associated gas gathering system and a 6 mile pipeline and compression facility servicing the project and adjacent production. The field has potential for 20 additional well sites on 160 acre spacing on the undeveloped acreage. The property is adjacent to our Gordon Creek project and to the very successful Drunkards Wash field originally developed by River Gas Corp.

The purchase option called for an acquisition price of $3 million, and we closed the purchase of the acquisition on March 13, 2006 with an industry partner, MBA Resource Corp. of Canada. (“MBA”). MBA paid $1.5 million and arranged third party financing of $750,000 toward the $3 million purchase price in exchange for a 50% interest in the project. We previously paid a deposit toward the purchase price and received production credits since October 1, 2005. We thus acquired a 50% interest in the project with only an additional payment of $241,000. Fellows and MBA have formed Gordon Creek, LLC a joint operating company incorporated in the state of Utah to carry out gas production and drilling operations as well as gas gathering activities for both project gas and adjacent third party production.

15
We will use the experience of our personnel who participated in the development of Drunkards Wash to increase current production and expand production in both the Ferron Sandstone and in the underlying coal bed methane seams that are not currently being exploited by the existing wells. We will immediately undertake to increase production in the existing wells, complete those wells in the coal for their coal bed methane potential, and thereafter drill additional wells on the acreage being acquired.
 
We are continuing with the reworking program in the Creston Project. In addition, we have mobilized a workover rig to commence reworking on one producing well and one shut-in well on the Carbon County Project. We similarly expect to engage in continuous operations at Carbon County until all wells are suitably reworked and all prospective new wellsites are drilled. We also hope to drill on the Overthrust project, the Carter Creek project, the Bacaroo project and the Johns Valley project during 2006. With our partner, JMG, we also hope to drill on the Weston County and Gordon Creek projects in 2006. We are seeking additional capital which we need in order to perform these projects. We currently do not have any contracts, commitments or arrangements for additional financing and there is no guarantee that we will be able to obtain such additional financing on terms that are favorable to us, or at all.

The operations we plan for 2006 include continuing development drilling and reworking activities on the Carbon County and Creston projects, exploring leases on the other projects we have acquired as well as seeking to acquire and explore additional property, and implementing production on one or more of our projects. Our goal is to discover and continue to produce substantial additional commercial quantities of oil and gas, including coalbed methane, on the properties, although no assurances can be given that commercial quantities are available, if at all.

Results of Operations 

Revenue. For the three and six months ended June 30, 2006, we earned $283,000 and $344,000, respectively, from our Creston project and newly acquired Carbon County project, in addition to the $198,000 applied as a credit toward the purchase price of the Carbon County project, compared to $0 revenue for the three and six months ended June 30, 2005.

Operating expense. For the three and six months ended June 30, 2006, our operating expense was $1,368,000 and $2,215,000, respectively, compared to $582,000 and $1,224,000 for the three and six months ended June 30, 2005, respectively. The expenses came from oil and gas exploration and production, salaries, business advisory services, legal and professional fees, travel, occupancy and investor relations expense. The expense increased largely because of convertible debenture expense and production related costs.

Interest expense. We incurred interest expense of $60,000 and $77,000 for the three and six months ended June 30, 2006, respectively, compared to $48,000 and $129,000 for the three and six months ended June 30, 2005, repectively.

Liquidity and Capital Resources

For the quarter ended June 30, 2005, we had a loss of $241,000. For the quarter ended June 30, 2006, we incurred a net loss of $1,392,000. At June 30, 2006, we had $440,000 of cash and cash equivalents, total current assets of $861,000, and current liabilities of $644,000 for working capital of $217,000.

Based upon our significant operating losses from inception, there is substantial doubt as to our ability to continue as a going concern. Our audited and unaudited financial statements have been prepared on a basis that contemplates our continuation as a going concern and the realization of assets and liquidation of liabilities in the ordinary course of business. Our audited and unaudited consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern.

The Carbon County and Creston projects were acquired in late 2005, and were not brought into production until the first quarter of 2006. They have not yet been in production for a sufficient time, and have not yet been sufficiently reworked by additional field operations to determine their productive capacities. At this point, we have not generated sufficient oil and gas sales to sustain our operations. To fully carry out our business plans we need to increase production revenues, raise a substantial amount of additional capital, sell project assets, or obtain industry joint venture financing, which we are currently seeking. We can give no assurance that we will be able to increase production or raise such capital. We have limited financial resources until such time that we are able to generate such additional financing or additional cash flow from operations. Our ability to obtain profitability and positive cash flow is dependent upon our ability to exploit our mineral holdings, generate revenue from our planned business operations and control our exploration cost. To fully carry out our business plans we need to raise a substantial amount of additional capital, which we are currently seeking. We can give no assurance that we will be able to raise such capital. We have limited financial resources until such time that we are able to generate positive cash flow from operations. Our ability to maintain profitability and positive cash flow is dependent upon our ability to locate profitable natural gas or oil properties, generate revenue from our planned business operations, and control exploration cost. Should we be unable to raise adequate capital or to meet the other above objectives, it is likely that we would have to substantially curtail our business activity, and that our investors would incur substantial losses of their investment.

16
  Cash flow. For the six months ended June 30, 2006, we used $810,000 in our operating activity. We used $959,000 in investing activity for property and option acquisitions, and obtained $2,136,000 in financing activity from capital obtained through financings. We increased our March 31, 2006 cash balance of $74,000 to $404,000 at June 30, 2006.

Critical Accounting Policies and Estimates

Our Management's Discussion and Analysis of Financial Condition and Results of Operations section discusses our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an on-going basis, we evaluate our estimates and judgments, including those related to revenue recognition, accrued expense, financing operations, contingencies and litigation. We base our estimates and judgments on historical experience and on various other factors that we believe to be reasonable under the circumstances. Our estimates and judgments form the basis for determining the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. These carrying values are some of the most significant accounting estimates inherent in the preparation of our financial statements. These accounting policies are described in relevant sections in this discussion and in the notes to the financial statements included in our December 31, 2005 Form 10-KSB Annual Report.


17

Item 3. Controls and Procedures

(a) Evaluation of disclosure controls and procedures.

Our management, with the participation of our chief executive officer and chief financial officer, evaluated the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of June 30, 2006. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Based on our evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are designed at a reasonable assurance level but were not fully effective during the quarter in providing reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

(b) Changes in internal control over financial reporting.

We regularly review our system of internal control over financial reporting and make changes to our processes and systems to improve controls and increase efficiency, while ensuring that we maintain an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

There were no changes in our internal control over financial reporting that occurred during the period covered by this Quarterly Report on Form 10-QSB that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 

 

18

Part II: Other Information
 
Item 1. Legal Proceedings
 
From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. Except as described in our annual report on Form 10-KSB, filed with the Commission on April 17, 2006, we are currently not aware of any such legal proceedings or claims that we believe will have, individually or in the aggregate, a material adverse affect on our business, financial condition or operating results.
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
 
In May 2006, we issued 700,000 shares of common stock valued at $196,000 to Quaneco, LLC in connection with amending the drilling obligations and option payments of the agreement between Fellows Energy and Quaneco.

In May 2006, we issued 861,921 shares of common stock valued at $215,480 to investors in our May 2005 private placement as a result of anti-dilution provisions.

In May 2006, we issued 790,000 shares of common stock valued at $252,000 to GBV International in connection with amending the payment terms of the agreement among Fellows Energy, Diamond Oil & Gas Corp, George Young and GBV International.

In June 2006, we issued 48,980 shares of common stock valued at $12,245 to Al Michael as a finder’s fee in connection with our May 2005 private placement.

Item 3.     Defaults Upon Senior Securities

None.
 
Item 4.     Submission of Matters to a Vote of Securities Holders

None.
 
Item 5.     Other Information

None.

Item 6.      Exhibits 
 
 
31.1 
Certification of Chief Executive Officer pursuant to Rule 13a-14 and Rule 15d-14(a), promulgated under the Securities and Exchange Act of 1934, as amended 
 
 
31.2 
Certification of Chief Financial Officer pursuant to Rule 13a-14 and Rule 15d 14(a), promulgated under the Securities and Exchange Act of 1934, as amended 
 
 
32.1 
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer) 
 
 
32.2 
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer) 

 
 
 
19
 
Signatures
 
In accordance with the requirements of the Securities Exchange Act of 1934, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
     
  FELLOWS ENERGY LTD.
 
 		  
 		  
 
Date: August 21, 2006 By:   /s/ GEORGE S. YOUNG
 
George S. Young
 
Chief Executive Officer ( Principal Executive Officer Principal Accounting Officer and Principal Financial Officer)