| | | |
HIGH PLAINS GAS, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW FOR THE SIX MONTHS ENDED JUNE 30, 2011 AND 2010 (UNAUDITED) |
| SIX MONTHS ENDED JUNE 30, |
| 2011 | | 2010 |
Cash Flows from Operating Activities: | | | |
Net income/(loss) | (18,783,324) | | (147,587) |
Adjustments to reconcile net loss to net cash provided by operating activities: | | | |
Depletion, depreciation, and accretion | 3,736,111 | | 131,141 |
Amortization of fees | 1,595,430 | | -- |
Abandonment of oil and gas prospect | 4,125,010 | | -- |
Stock based compensation | 253,054 | | -- |
Stock issued for services | 813,004 | | -- |
Loss on fair value of equity securities | 893,506 | | -- |
Loss on extinguishment of debt | 532,932 | | -- |
Amortization of debt discount | 455,108 | | -- |
Unrealized hedge (gain) loss | 28,215 | | -- |
Interest added to related party notes payable | 102,480 | | -- |
| | | |
Changes in operating assets and liabilities: | | | |
Accounts receivable | (433,386) | | (737,559) |
Prepaid and other assets | 85,402 | | -- |
Accounts payable and accrued liabilities, includes related party | 8,166,873 | | (228,996) |
Net cash provided (used in) operating activities | 1,570,415 | | (983,001) |
| | | |
Cash Flows from Investing Activities: | | | |
Additions to oil and gas properties | (623,931) | | (392,990) |
Deposits on acquisition of oil and gas property | (2,000,000) | | -- |
Purchase of property, plant and equipment | (546,839) | | (89,486) |
Net cash (used in) investing activities | (3,170,770) | | (482,476) |
| | | |
Cash Flows from Financing Activities: | | | |
Proceeds from related party notes payable | 642,261 | | -- |
Repayment of related party notes payable | (668,541) | | (30,196) |
Proceeds from line of credit | 75,000 | | -- |
Repayment of line of credit | (118,134) | | (917,432) |
Proceeds from term debt | 1,885,000 | | 1,709,790 |
Repayment of term debt | (1,229,387) | | -- |
Member contributions | -- | | 799,300 |
Warrants issued for cash | 1,000,000 | | -- |
Stock issued for cash, net of fees | 2,054,889 | | -- |
Payment of bond commitment fees | (214,951) | | (25,000) |
Payment of financing fees | (770,000) | | -- |
Net cash provided by financing activities | 2,656,137 | | 1,536,462 |
| | | |
Net Increase (Decrease) in Cash and Cash Equivalents | 1,055,782 | | 70,985 |
| | | |
Cash and Equivalents, at beginning of period | 208,823 | | 45,526 |
| | | |
Cash and Equivalents,at end of period | $ 1,264,605 | | $ 116,411 |
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| | | |
HIGH PLAINS GAS, INC. CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW (CONT’D) FOR THE SIX MONTHS ENDED JUNE 30, 2011 AND 2010 (UNAUDITED) |
| SIX MONTHS ENDED JUNE 30, |
| 2011 | | 2010 |
| | | |
Other Information: | | | |
| | | |
Cash paid for interest | $ 883,204 | | $ 59,786 |
| | | |
Deposit on acquisition of oil and gas property with stock | $ 2,125,010 | | $ -- |
| | | |
Stock and warrants issued in conjunction with related party notes payable | $ 309,573 | | $ -- |
| | | |
Warrants issued as compensation | $ 27,403 | | $ -- |
| | | |
Additions to Asset Retirement Obligation | $ -- | | $ 220,002 |
See accompanying notes to financial statements
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HIGH PLAINS GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2011
1.
ORGANIZATION AND BASIS OF PRESENTATION:
High Plains Gas, Inc (“High Plains ”, The Company”, “We”, “Our”) is a natural gas and petroleum exploration, development and production company, primarily engaged in locating and developing hydrocarbon resources throughout the Rocky Mountain region. The Company’s principal business is the acquisition of leasehold interests in natural gas and petroleum rights and the development of properties subject to these leases. The Company is currently focusing its operational efforts in the Powder River Basin in Wyoming.
High Plains was originally incorporated in Nevada as Northern Explorations, Ltd., (“Northern Explorations”) on November 17, 2004. From its inception, the Company was engaged in the business of exploration of natural resource properties in the United States. After the effective date of its registration statement filed with the Securities and Exchange Commission (February 14, 2006), the Company commenced quotation on the Over-the-Counter Bulletin Board under the symbol “NXPN.”
On September 13, 2010 the Company amended its Articles of Incorporation to change its name to High Plains Gas, Inc. We also completed a 1 for 200 reverse split of the common stock and increased the authorized common stock to 250,000 shares. In April 2011, we increased our authorized common stock to 350,000,000 shares.
On September 30, 2010 the Company entered into an Operations and Convertible Note Purchase Agreement (“Agreement”) with Current Energy Partners Corporation (“CEP”), a Delaware corporation and its wholly owned subsidiary CEP-M Purchase LLC (“CEP-M”). Under terms of the Agreement, the Company purchased a convertible note from CEP with the proceeds to be used by CEP to acquire a significant resource base and land position from Pennaco Energy, Inc., a wholly owned subsidiary of Marathon Oil Company. On October 31, 2010 the Company acquired a 49% interest in CEP-M. On November 19, 2010 the convertible note was converted into a 51% membership interest in CEP-M, giving the Company effective control of 100% of CEP-M.
On October 18, 2010, the Company pursuant to a reorganization agreement with High Plains Gas, LLC issued 52,000,000 shares to nine individuals representing 100% of the membership of High Plains Gas, LLC and as a result High Plains Gas, LLC became a wholly owned subsidiary of the Company. Also under the reorganization agreement, shareholders and other parties representing what was Northern Explorations retained approximately 13,000,000 shares of the Company’s common stock.
The reorganization has been accounted for as a reverse merger and under the accounting rules for a reverse merger, the historical financial statements and results of operations of High Plains Gas, LLC became those of the Company.
The trading symbol has been changed to “HPGS” to more accurately reflect the Company’s new identity.
The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q. They do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for a complete financial presentation. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, considered necessary for a fair presentation have been included in the accompanying
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unaudited financial statements. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. These financial statements should be read in conjunction with the financial statements and footnotes which are included as part of the Company’s Form 10-K for the year ended December 31, 2010.
Until November 2010, operations consisted of 92 producing methane wells. During November 2010, the Company purchased all of the North and South Fairway gas fields from Pennaco Energy, a subsidiary of Marathon Oil, which included gas leases along with personal property in 1,614 producing or idled methane wells (located in Campbell, Johnson and Sheridan Counties, Wyoming). The Company paid an adjusted purchase price of $30,654,813 for these assets. The gas fields included in this sale are located in the following Wyoming counties: Campbell, Johnson, and Sheridan. The net leased acreage for the North and South Fairway assets is approximately 133,000 acres. This transaction is referred to herein as the “Marathon Transaction.”
On February 2, 2011, the Company signed a Purchase and Sales Agreement with J.M. Huber Corporation in which the Company agreed to purchase approximately 313,000 net acres of leasehold and 2,302 natural gas wells located in Wyoming and Montana for $35,000,000. The Company provided $2,000,000 in non-refundable cash deposits and HPG stock valued at $1,635,000. The transaction was scheduled to close in April 2011. On May 3, 2011, the Company issued 500,000 additional restricted shares to J.M. Huber Corporation in connection with the extension of closing the purchase agreement. On July 29, 2011, the Purchase and Sale Agreement was terminated and all expenses related to the acquisition were expensed in the quarter ended June 30, 2011.
The Company continues to re-work and reactivate wells acquired in the Marathon Transaction. As of June 30, 2011, the Company has a total of 1,671 methane wells, of which 551 are producing and 1,120 are either idle or shut-in, awaiting re-activation. In order to complete this business plan, the Company will need to raise significant funds by seeking additional debt or equity financings.
No assurances can be given that the Company will be successful in raising required debt or equity financing. In the event the Company is unable to raise the required funds, the Company will be required to substantially reduce its plans to re-activate the idle or shut-in wells or to develop the unevaluated property, and if it is unable to obtain financing, it will be unable to continue as a going concern.
2.
ACCOUNTING POLICIES:
Use of Estimates
The preparation of the financial statements in conformity with generally accepted accounting principles of the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates under different assumptions or conditions. The Company’s financial statements are based on a number of significant estimates, including: (1) oil and gas reserve quantities; (2) depletion, depreciation and amortization; (3) assigning fair value and allocating purchase price in connection with business combinations; (4) valuation of commodity derivative instruments; (5) asset retirement obligations; (6) valuation of share-based payments; (7) allowance for bad debts; (8) income taxes; and (9) cash flow estimates used in impairment tests of long-lived assets.
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Oil and Natural Gas Properties
High Plains follows the successful efforts method of accounting for its investments in oil and natural gas properties.
Depletion and depreciation expense was $1,302,866 and $131,141 for the three months ended June 30, 2011 and 2010, respectively.
Depletion and depreciation expense was $3,202,242 and $274,519 for the six months ended June 30, 2011 and 2010, respectively.
During the quarter ended June 30, 2010, management evaluated the factors used in calculating depletion and determined a change in estimate which would have decreased the amount of depletion reported for the three months ended March 31, 2010 by $145,201 and the Company would have reposted depletion of $143,377 for the three months ended March 31, 2010.
The Company transferred unproved costs of $1,548,438 to proven leaseholds during the first six months of 2011, compared to $0 during the first six months of 2010.
No impairment expense related to oil and natural gas properties has been recorded in the three and six months ended June 30, 2011 and 2010, respectively.
Aggregate Capitalized Costs
Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities, including asset retirement costs and related accumulated depreciation, depletion and amortization are as follows:
| | | |
| At June 30 and December 31: |
| 2011 | | 2010 |
| | | |
Proved oil and gas properties | $ 28,285,103 | | $ 24,516,504 |
Accumulated DD&A | (6,377,082) | | (3,174,836) |
| | | |
Net capitalized costs | $ 21,908,021 | | $ 21,341,668 |
Costs incurred in Oil and Gas Activities
Costs incurred in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities are shown below:
| | | |
| At June 30 and December 31: |
| 2011 | | 2010 |
| | | |
Unproven properties | 16,690,375 | | 18,238,814 |
Acquisition costs | 9,608.403 | | 9,002,072 |
Development costs | 8,920,958 | | 7,354,921 |
ARO Costs | 8,159,512 | | 8,159,512 |
| | | |
Total | $ 43,379,248 | | $ 42,755,318 |
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Equipment and Depreciation
Property and equipment is stated at cost and is depreciated using the straight-line method over estimated useful lives of 5 to 10 years.
| | | | |
| | June 30, | | December 31, |
| | 2011 | | 2010 |
Transportation and vehicles | | $ 632,805 | | $ 607,422 |
Equipment and other | | 840,628 | | 582,698 |
Computers and software | | 419,387 | | 155,861 |
| | 1,892,820 | | 1,345,981 |
Less Depreciation | | (174,793) | | (29,674) |
| | $ 1,718,027 | | $ 1,316,307 |
Depreciation expense was $104,778 and $1,827 during the three months ended June, 2011 and 2010 and was $145,119 and $6,764 during the six months ended June 30, 2011 and 2010, respectively.
Off-Balance Sheet Arrangements
From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of June 30, 2011, the off-balance sheet arrangements that the Company had entered into include undrawn letters of credit, operating lease agreements, gathering, compression agreements, processing and water disposal 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.
Revenue Recognition and Gas Imbalances
Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title as transferred, collectability is reasonably assured, and evidenced by a contract. This occurs when oil or gas has been delivered to a pipeline or a tank lifting has occurred. The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners’ gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company’s remaining over-and-under produced gas balancing positions are considered in the Company’s proved oil and gas reserves. Gas imbalances at June 30, 2011 and 2010 were not significant.
Funds in Escrow
During 2010, the Company incurred a $1,000,000 bond commitment fee with PP&J, a Wyoming entity. This fee was to be satisfied by issuance of 800,000 common shares to PP&J. As the shares are restricted and cannot be readily disposed to satisfy the obligation, a deposit of $750,000 has been made to an escrow account held at First National Bank of Gillette, Wyoming. If the value of the shares held by PP&J is less than the $1,000,000 at the date of disposal, any shortfall will be satisfied from the funds in escrow. The value of the shares held by PP&J as of June 30, 2011 was $320,000.
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Income Taxes
The Company has analyzed filing positions in all of the federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in these jurisdictions. No uncertain tax positions have been identified as of June 30, 2011.
The Company is generally no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2007, and for state and local tax authorities for years before 2006.
The Company is in a position of cumulative reporting losses for the current and preceding reporting periods. The volatility of energy prices and uncertainty of when energy prices may rebound is not readily determinable by management. At this date, this fact pattern does not allow the Company to project sufficient sources of future taxable income to offset tax loss carryforwards and net deferred tax assets. Under these circumstances, it is management’s opinion that the realization of these tax attributes does not reach the “more likely than not criteria” under Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 740 – Income Taxes. As a result, the Company’s deferred tax assets as of June 30, 2011 and December 31, 2010 are subject to a full valuation allowance.
Bond Commitment Fees
Fees paid to secure commitments from lenders and to secure bonding arrangements with the State and other local government entities are capitalized and amortized on a straight-line basis over the expected term of the arrangement. Fees paid during 2010 to shareholders and others totaled $2,963,897 and $214,951 during the six months ended June 30, 2011. Amortization of these fees is over a 12-month period. Amortization during the six months ended June 30, 2011 and the year ended December 31, 2010 totaled $1,132,774 and $493,983, respectively. There was no amortization of bond commitment fees for the three and six months ended June 30, 2010.
Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during the reporting period. Contingently issuable shares (unvested restricted stock) are included in the computation of basic net income (loss) per share when the related conditions are satisfied. Diluted earnings (loss) per share is computed using the weighted average number of common shares outstanding including all and potentially dilutive securities (unvested restricted stock and unexercised stock options) outstanding during the period. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding as their inclusion would be anti-dilutive.
As of June 30, 2011 and 2010, the Company had shares of common stock outstanding and warrants for the purchase of shares. The warrants were excluded from the calculation of diluted earnings per share for both years, due to the fact that because of net (loss) positions, they would be anti-dilutive.
Recently Adopted Accounting Standards
We evaluate the pronouncements of various authoritative accounting organizations, primarily the Financial Accounting Standards Board (“FASB”), the SEC, and the Emerging Issues Task Force (“EITF”) to determine the impact of new pronouncements on U.S. generally accepted accounting principles (“GAAP”) and the impact on the Company. We have adopted the following new standards during the period ended June 30, 2011:
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Fair Value Measurements – Accounting Standards Update (“ASU”) 2010-06 amended existing disclosure requirements about fair value measurements by adding required disclosures about items transferring into and out of levels 1 and 2 in the fair value hierarchy; adding separate disclosures about purchase, sales, issuances and settlements relative to level 3 measurements; and clarifying, among other things, the existing fair value disclosures about the level of disaggregation. The final provisions of ASU 2010-06 were adopted during the period ended June 30, 2011 and adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows.
Share-based Payments – ASU 2010-13 clarifies the classification of an employee based payment award with an exercise price denominated in the currency of a market in which the underlying security trades. The Company adopted ASU 2010-13 during the period ended June 30, 2011 and adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows.
Business Combinations – ASU 2010-29 requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. This ASU is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 31, 2010 with early adoption permitted. The Company adopted ASU 2010-29 during the period ended June 30, 2011 and adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows.
Recently Issued Accounting Standards
We have reviewed all recently issued, but not yet effective, accounting pronouncements and do not believe the future adoption of any such pronouncements may be expected to cause a material impact on our financial condition or the results of our operations.
3.
HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS:
The Company utilizes a swap contract to hedge the effect of price changes on a portion of its future natural gas production. The objective of the Company's hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements.
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company generally has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contract may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company is not required to post collateral when the Company is in a derivative liability position.
As of June 30, 2011 and December 31, 2010, the Company had entered into a swap agreement related to its natural gas production. Location and quality differentials attributable to the Company's properties are not included. The agreement provides for monthly settlement based on the differential between the agreement price and the actual CIG Rocky Mountains price.
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4.
RELATED PARTY TRANSACTIONS:
During the six months ended June 30, 2011, the Company had the following transactions with related parties:
The Company borrowed $642,261 from and repaid $668,541 to related parties.
Default penalty interest of $102,480 was added to outstanding principal balances owed to related parties during the six months ended June 30, 2011.
The Company purchased drilling tools from a related party totaling $97,966, of which $1,202 is included in accounts payable at June 30, 2011.
The Company incurred legal fees from a related party totaling $433,661, of which $61,919 is included in accounts payable at June 30, 2011.
The Company paid loan origination fees of $71,075 to a related party, of which $11,163 is included in accounts payable at June 30, 2011.
The Company incurred consulting fees from a related party totaling $27,027, all of which is included in accounts payable at June 30, 2011.
The Company incurred travel costs owed to related party totaling $175,594 of which $50,350 is included in accounts payable at June 30, 2011.
The Company was invoiced for various business-related reimbursements of which $51,890 is included in accounts payable as of June 30, 2011.
As further discussed in Note 6, the Company has issued equity instruments to Current Energy Partners Corporation, a shareholder, in cancellation of a promissory note. The Company also issued warrants as compensation to certain employees and common shares to certain members of the Board of Directors.
See Note 6 for details of equity transactions with related parties.
5.
INVESTMENT IN MARKETABLE SECURITIES
On December 8, 2010, the Company signed a definitive Stock Purchase Agreement (the “Purchase Agreement”) with Big Cat Energy Corporation (“Big Cat”) to purchase 20,000,000 shares of Big Cat’s restricted common stock, or approximately 31.3% of the projected issued and outstanding shares. As allowed by FASB ASC 825-10,Financial Instruments,the Company has elected to follow the fair value option for reporting the securities received from Big Cat because the Company believes this accounting treatment represents a more realistic measure of value that may be realized by the Company should they dispose of the securities on the open market. The Company has elected the fair value option for both the common stock and the warrants.
As of June 30, 2011, the fair value of the securities was $.06 per share, or $1,200,000. The fair value of the warrants was $551,602, and the total decrease in value of $893,506 has been recognized in the statement of operations.
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6.
EQUITY TRANSACTIONS:
During the three months ended March 31, 2011, the Company had the following transactions:
The Company had private placements of 4,250,000 shares of restricted stock to qualified investors. The Company received proceeds of $2,120,750 for these private placements.
The Company issued 60,000 shares of restricted stock in payment of $30,000 of legal fees.
The Company cancelled 125,000 shares of previously issued restricted stock in payment of Investor and Public Relations services.
The Company issued 44,400 shares of restricted stock valued at $22,551 to an officer of the Company for guaranteeing certain loans by the Company.
The Company issued 1,500,000 shares of restricted stock valued at $1,635,000 to J.M. Huber Corporation for the extension of the Sale and Purchase Agreement executed April 1, 2011. The Company issued 2,500 shares of restricted stock as compensation totaling $1,250.
The Company issued 2,500 shares of restricted stock as compensation totaling $1,250.
The Company issued 624,679 warrants relating to outstanding related party debt valued at $287,022.
The Company issued 200,000 warrants for compensation valued at $151,277, which will be vested over a 6-year period. Compensation recorded for both three month periods ended March 31, 2011 and June 30, 2011 was $7,564 each.
The Company entered into an agreement with Fletcher International, Ltd. to sell warrants for $1,000,000. The warrant permits the purchase of up to $5,000,000 in common shares until February 24, 2018. The exercise price for share purchased is the lesser of (i) $1.25 and (ii) the average of the volume weighted average market price for the calendar month immediately preceding the date of the first notice of exercise, but in no event can the exercise price be less than $.50. The exercise price and shares issuable pursuant to the warrants are subject to certain adjustments as set forth in the warrant agreement, which also contains a cashless exercise provision.
During the three months ended June 30, 2011, the Company had the following equity transactions:
The Company sold 120,000 shares of restricted stock through a private placement transaction to qualified investors. The Company received proceeds of $60,000 through these transactions.
The Company issued 600,000 shares of restricted stock in payment for $300,000 of legal fees.
The Company issued 220,000 shares as compensation to certain members of the Board of Directors for services rendered, valued at $224,400.
The Company issued 500,000 shares of restricted stock valued at $490,010 to J.M. Huber Corporation for an extension of the Purchase and Sale Agreement.
The Company issued 185,200 shares of restricted stock to Wakabayashi Fund in payment of $142,604 of Investor Relations services.
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The Company issued 2,639,384 shares of restricted to stock to Current Energy Partners Corporation in cancellation of a promissory note for $1,500,000. The shares were valued at $2,032,932 as of the date of the transaction, which generated a loss on extinguishment of debt totaling $532,932 for the six months ended June 30, 2011.
The Company issued 300,000 warrants as compensation to certain employees as part of employment contracts, valued at $245,505 that will vest over a 5 year period. Compensation recorded for the three month period ended June 30, 2011 was $27,403.
The Company recorded a debt discount for certain Convertible Debt Agreements of $734,989 that was assigned to equity.
Outstanding Warrants at June 30, 2011:
| | | |
| Number of | Weighted Avg | Remaining |
| Shares | Exercise Price | Contractual Term |
Warrants outstanding - January 1, 2011 | 5,289,627 | | |
Granted during period | 1,189,679 | $ 0.52 | $ 4.67 |
Exercised during period | | | |
Forfeited during period | | | |
Expired during period | | | |
Warrants outstanding – June 30,, 2011 | 6,479,306 | $ 0.52 | $ 4.67 |
The above private offerings were made in reliance on an exemption from registration in the United States under Section 4(2) and/or Regulation D of the United States Securities Act of 1933, as amended.
7.
LETTERS OF CREDIT
During 2010, the Company entered into a line of credit agreement with First National Bank of Gillette on November 12, 2010 to provide letters of credit to various agencies and entities for the bonding required to operate the Company’s methane wells. These letters of credit total $7,839,358, and any outstanding balances carry an interest rate of 1% over the U.S. Bank Denver Prime Rate. Any outstanding amounts and related interests are due on demand. The agreement is secured by the right of setoff against corporate depository account balances, a mortgage on certain real property, all improvements and equipment on certain well sites and including rights to future production, assignment of a life insurance policy on the Chief Operating Officer as well as personal guarantees of certain shareholders. There were no amounts outstanding on this agreement as of June 30, 2011 and Dec. 31, 2010.
8.
DEBT FINANCING – LINES OF CREDIT
On January 20, 2010, the Company entered into an agreement with U.S. Bank for a line of credit of up to $200,000 with a maturity date of October 31, 2011. The line of credit carries an interest rate of 4.95% per annum and is secured by assignments to oil and gas production, and all inventory and accounts receivable and equipment. As of June 30, 2011 and December 31, 2010, the outstanding principal balance was $200,000 and $125,000, respectively.
On November 19, 2010, the Company (through its wholly owned subsidiary CEP-M Purchase LLC) entered into a letter of credit facility with Amegy Bank National Association (“Amegy”) for a revolving
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line of credit of up to $75,000,000. The facility is to be used to finance up to 60% of the Company’s oil and gas acquisitions, subject to approval by Amegy. The interest rate is based on LIBOR, the amount of the credit facility in use and other factors to determine the prevailing rate on outstanding principal balances (effective rate of 6.25% as of December 31, 2010). Outstanding principal balances and any related accrued interest is due on September 17, 2013 subject to mandatory prepayment terms per the agreement. The credit facility is secured by all assets of CEP-M Purchase LLC, a mortgage on all proved reserves of specific wells. As of June 30, 2011 and December 31, 2010, the outstanding principal balance was $6,000,000. The credit facility is subject to restrictive covenants, and as of December 31, 2010 and June 30, 2011, the Company was not in compliance with certain covenants. This condition has caused the classification of the outstanding balance to be presented as a current liability.
On November 29, 2010, the Company entered into an agreement with First National Bank of Gillette for a line of credit of up to $461,148 to be used for the purchase of corporate vehicles. The line of credit carries an interest rate of 6% interest rate and is secured by the right of offset against corporate depository account balances. Terms include the requirement of a monthly payment of $20,400 with any outstanding principal balance and accrued interest due on November 30, 2012. As of June 30, 2011 and December 31, 2010 the outstanding principal balance was $272,069 and $390,202, respectively.
Outstanding lines of credit at June 30, 2011:
| | | |
| | 2011 | |
Total outstanding principal | | $ 6,472,069 | |
Current portion | | 6,315,492 | |
Long-term portion of lines of credit | | $ 156,577 | |
| | | |
Outstanding balances are due: | | | |
2011 (remaining) | | $ 6,315,492 | |
2012 | | 156,577 | |
2013 | | -- | |
| | $ 6,472,069 | |
9.
DEBT FINANCING – TERM DEBT
On January 20, 2010, the Company entered into a term loan agreement with U.S. Bank of $1,200,000 with a maturity date of January 20, 2013. Payments are due monthly of $16,935 which include interest at 4.95% per annum. The agreement is secured by the right of offset against corporate depository accounts and is guaranteed by certain shareholders. As of June 30, 2011 and December 31, 2010, the outstanding principal balance was $991,537 and $1,067,225, respectively.
On March 11, 2010, the Company entered into a term loan agreement with Ford Motor Credit of $42,820 with a maturity date of March 31, 2015. Payments are due monthly of $871 which include interest at 7.99% per annum. The agreement is secured by a corporate vehicle. As of June 30, 2011 and December 31, 2010 the outstanding principal balance was $33,837 and $37,525, respectively.
On November 23, 2010, the Company entered into a term loan agreement with CEP-M with a maturity date of January 31, 2011. The note does not bear interest and is unsecured. As of June 30, 2011 the outstanding principal balances is $0. The Company issued 2,639,384 shares of common stock to satisfy the repayment of the note. See Note 6.
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During April and May 2011, the Company entered into term loan agreements totaling $1,735,000 with various unrelated persons. Payments are due monthly and include interest at between 10-15% per annum. As of June 30, 2011 unpaid principal totaled $735,000. The agreements are unsecured. The terms allow the outstanding balance to be converted into common shares. The conversion terms result in a beneficial conversion feature at the date of issuance as a result of the market price of the stock trading at a price higher than the conversion price, resulting in the recording of the term loans at a discount of $734,989. Accretion of the discount was $246 for the three and six months ended June 30, 2011.
Outstanding term debt at June 30, 2011:
| | | |
| | 2011 | |
| | | |
Total outstanding principal | | $ 1,025,631 | |
Current portion | | 82,127 | |
Long-term portion of term debt | | $ 943,504 | |
| | | |
Outstanding balances are due: | | | |
2011 (remaining) | | $ 82,127 | |
2012 | | 170,122 | |
2013 | | 760,954 | |
2014 | | 9,830 | |
2015 | | 2,598 | |
| | $ 1,025,631 | |
10. DEBT FINANCING – RELATED PARTIES
A total of $6,334,516 and $6,224,062 was owed to various related parties as of June 30, 2011 and December 31, 2010, respectively.
During the six months ended June 30, 2011, the Company had the following debt transactions with related parties:
A director/shareholder had an outstanding balance at January 1, 2011 of $5,392,591. During the six months ended June 30, 2011, he loaned the Company an additional $182,500 and received payments of $49,491. Default penalty interest of $44,090 was added to the outstanding balance. As of June 30, 2011, a total of $5,569,690 is due to this director/shareholder.
A director/shareholder had an outstanding balance at January 1, 2011 of $588,429. During the six months ended June 30, 201, he loaned the Company an additional $52,261 and received payments of $25,550. Default penalty interest of $39,309 was added to the outstanding balance. As of June 30, 2011 a total of $654,449 is due to this director/shareholder.
A shareholder had an outstanding balance at January 1, 2011 of $163,927. During the six months ended June 30, 2011, he loaned the Company an additional $357,500 and received payments of $568,500. Default penalty interest of $47,073 was added to the outstanding balance. As of June 30, 2011 a total of $0 is due to this shareholder.
A director/shareholder had an outstanding balance at January 1, 2011 of $79,115. During the six months ended June 30, 2011, he received payments of $25,000. Default penalty interest of $7,912 was added to the outstanding balance. As of June 30, 2011 a total of $62,027 is due to this director/shareholder.
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An employee loaned the Company $50,000. The terms allow the outstanding balance to be converted into common shares. The conversion terms result in a beneficial conversion feature at the date of issuance as a result of the market price of the stock trading at a price higher than the conversion price, resulting in the recording of the loan at a discount of $1,907. As of June 30, 2011 a total of $48,093 is due to this employee.
11. FAIR VALUE MEASUREMENT AND DISCLOSURE
Fair Value Measurements at June 30, 2011 Using:
| | | | |
|
Description | | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) |
| | | | |
Equity securities recorded at fair value | $ 1,751,602 | $ 1,200,000 | $ - | $ 551,602 |
| | | | |
Commodity hedge liability | ($631,957) | - | - | ($631,957) |
| | | | |
Level 3 assets are comprised of the impairment reserve for unevaluated properties. The Company has identified the impairment reserve as a Level 3 due to the lack of available data to obtain market values for the unevaluated properties. The company considered current natural gas prices and the remaining lease term as a basis for determining the reserve amount.
| | |
Level 3 reconciliation tables: | |
| Balance, January 1, 2011 | $ 845,108 |
| Decrease in value | (293,506) |
| Balance, June 30,2011 | $ 551,602 |
| | |
| Balance, January 1, 2011 | ($603,742) |
| Change in value of commodity hedge | (28,215) |
| Balance, June 30,2011 | ($631,957) |
Financial Instruments
Financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, lines of credit, and long-term debt. With the exception of the long-term debt, the financial statement carrying amounts of these items approximate their fair values due to their short-term nature. The carrying amount of long-term debt approximates the fair value due to its floating rate structure.
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12. ASSET RETIREMENT OBLIGATION
Changes in the Company’s asset retirement obligations were as follows:
| | |
| The Six Months Ended June 30, |
| 2011 | 2010 |
Asset retirement obligations, beginning of period | $ 8,229,630 | $ 33,046 |
Liabilities related to acquisitions | -- | 214,944 |
Revisions in estimated liabilities | -- | -- |
Accretion expense | 388,746 | 5,158 |
Asset retirement obligations, end of period | $ 8,618,376 | $ 253,048 |
13. COMMITMENTS AND CONTINGENCIES
Operating leases
The Company is currently renting office space on a month-to-month basis and is in the process of negotiating a long term lease.
Employment contracts:
The Company is party to several employment agreements with key personnel, all of which are effective for a 12-month period beginning January 1, 2011. The agreements range from $80,000 to $175,000 per year and all agreements contain customary terminology as to termination criteria
Delivery Commitments:
The Company has certain pipeline transportation obligations that specify the delivery of a fixed and determinable quantity of natural gas or the payment of the respective transportation fees. The following table sets forth information about material long- term firm transportation contracts for pipeline capacity. These contracts were acquired as part of the acquisition of the Pennaco “North & South Fairway Assets.” Under these firm transportation contracts, we are obligated to deliver minimum daily gas volumes, or pay the respective transportation fees for any deficiencies in deliveries. Although exact amounts vary, as of June 30, 2011 we are committed to the following pipeline capacities:
| | | | | | | | | | |
Type of Arrangement | | Pipeline System / Location | | Deliverable Market | | Gross Deliveries | | Term |
(MMBtu/d) |
| | | | | | | | |
Firm Transport | | WIC Medicine Bow | | Rocky Mountains | | | 15,000 | | | 07/10 –11/15 |
| | | | | | | | | | |
Firm Transport | | Kinder Morgan Trailblazer | | Rocky Mountains | | | 22,500 | | | 07/10 - 05/12 |
| | | | | | | | | | |
Firm Transport | | Copano Fort Union | | Rocky Mountains | | | 10,000 | | | 07/10 - 11/11 |
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Environmental impact:
The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operation thereof. If the Company acquires existing or previously drilled well bores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up or restoration, the liability to cure such a violation could fall upon the Company. Management believes its properties are operated in conformity with local, state and federal regulations. No claim has been made, nor is the Company aware of any uninsured liability which the Company may have, as it relates to any environmental cleanup, restoration or the violation of any rules or regulations relating thereto.
14. SUBSEQUENT EVENTS:
Pursuant to FASB ASC 855, management has evaluated all events and transactions that occurred from June 30, 2011 through the date of issuance of the financial statements. During this period we did not have any significant subsequent events, except as disclosed below:
On July 29, 2011 the Purchase Sale Agreement between the Company and J.M. Huber Corporation was terminated and all expenses related to the acquisition were expensed in the current reporting period, totaling $4,125,000.
On August 1, 2011, the Company formed HPG Services, LLC, as a subsidiary of High Plains Gas, Inc. in order to engage in oil and gas field services.
On August 1, 2011, the Company entered into a non-binding term sheet with Ironridge Global Energy, a division of Ironridge Global IV, Ltd. (“Ironridge”) for proposed future funding of up to $13.5 million. Should proposed funding commence, the event will be expected to take place over the next several Quarters. The Company agreed to issue approximately 4,236,000 common shares in settlement of approximately $1,121,000 in accounts payable of the Company. At no time may Ironridge and its affiliates collectively own more than 9.99% of the total number of outstanding common shares of the Company.
On August 10, 2011, the Board of Directors adopted a resolution designating a new series of preferred stock as Series A Convertible Preferred Stock (“Series A Shares”). There were a total number of 2,500 shares designated having a par value of $1,000 each. The holders of Series A Shares are entitled to receive monthly dividends as defined in the resolution. Holders of Series A Shares shall have no voting rights until such time as shares convert into common stock pursuant to the resolution.
On August 10, 2011, the Company entered in to an agreement with Mark Hettinger whereby Mr. Hettinger agreed to convert $1,782,958 of notes payable into 1,783 shares of Series A Convertible Preferred Stock.
On August 10, 2011, the Company entered in to an agreement with Joe Hettinger whereby Mr. Hettinger agreed to convert $297,160 of notes payable into 297 shares of Series A Convertible Preferred Stock.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
Statements about our future expectations are "forward-looking statements" within the meaning of applicable Federal Securities Laws, and are not guarantees of future performance. When used herein, the words "may," "will," "should," "anticipate," "believe," "appear," "intend," "plan," "expect," "estimate," "approximate," and similar expressions are intended to identify such forward-looking statements. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the following risks and uncertainties:
·
volatility of market prices received for oil and natural gas;
·
regulatory approvals;
·
legislative or regulatory changes;
·
economic and competitive conditions;
·
debt and equity market conditions;
·
derivative activities;
·
exploration risks such as drilling unsuccessful wells;
·
the ability to obtain industry partners for our prospects on favorable terms to reduce our capital risks and accelerate our exploration activities;
·
future processing volumes and pipeline throughput;
·
reductions in the borrowing base under our Credit Facility;
·
ability to comply with requirements of our Credit Facilities and Debt Instruments;
·
the potential for production decline rates from our wells to be greater than we expect;
·
changes in estimates of proved reserves;
·
potential failure to achieve expected production from existing and future exploration or development projects;
·
declines in values of our natural gas and oil properties resulting in impairments;
·
capital expenditures and other contractual obligations;
·
liabilities resulting from litigation concerning alleged damages related to environmental issues, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;
·
higher than expected costs and expenses including production, drilling and well equipment costs;
·
occurrence of property acquisitions or divestitures;
·
ability to obtain adequate pipeline transportation capacity for our production;
·
change in tax rates;
·
ability to access capital markets to adequately fund the needs of the Company ;and
·
other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, particularly in the “Cautionary Note Regarding Forward-Looking Statements’, all of which are difficult to predict.
In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to publicly correct or update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.
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Overview
High Plains Gas, Inc is a Rocky Mountain exploration and production company that seeks to enhance shareholder value by executing a long-term growth strategy. We seek to build stockholder value through profitable growth in reserves and production by investing in and implementing key existing development programs as well as growth through exploration and acquisitions. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns, but possess the potential to generate revenues from existing assets. Substantially all of our revenues are generated through the sale of natural gas at market prices and the settlement of commodity hedges. The members of our management team share significant experience in acquiring and developing E&P assets in the Rocky Mountains and has an extensive network of industry relationships in the region.
The Company was originally incorporated in Nevada as Northern Explorations, Ltd. (“Northern Explorations”) on November 17, 2004. From its inception, the Company was engaged in the business of exploration of natural resource properties in the United States. After the effective date of its registration statement filed with the Securities and Exchange Commission (February 14, 2006), the Company commenced quotation on the Over-the-Counter Bulletin Board under the symbol “NXPN.”
On September 13, 2010 the Company amended its Articles of Incorporation to change its name to High Plains Gas, Inc. Effective October 29, 2010, the Company completed the acquisition of High Plains Gas, LLC, the entity for the Company’s business. The symbol was changed on January 20, 2011 to “HPGS” to more accurately reflect the Company’s new name.
On January 24, 2011, the Company’s Board of Directors amended the Company’s bylaws to provide for a five member Board of Directors, and appointed Gary Davis, Cordell Fonnesbeck and Alan R. Smith as directors in addition to the already appointed directors, Mark D. Hettinger and Joseph Hettinger.
On February 2, 2011, the Company signed a Purchase and Sale Agreement with J.M. Huber Corporation (the “Huber Purchase Agreement”) in which the Company agreed to purchase approximately 313,000 net acres of leasehold and 2,302 wells in the Basin for $35,000,000 (the “Huber Acquisition”). The Company provided $2,000,000 in non-refundable cash deposits and later an additional 2,000,000 shares of High Plains Gas common stock, valued at $1,635,000.
On February 24, 2011, the Company entered into an agreement with Fletcher International, Ltd. (“Fletcher”) pursuant to which it sold Fletcher warrants to purchase 5,000,000 shares of the Company’s common stock for a price of $1,000,000. The exercise price for Common Stock to be purchased in the warrants issued to Fletcher is the lesser of (i) $1.25 and (ii) the average of the volume weighted average market price for all of the business days in the calendar month immediately preceding the date of the first notice of exercise of the Warrants, but in no event can the exercise price be less than $0.50. The warrants include a cashless exercise provision. The proceeds of the Fletcher warrants were utilized as a deposit for the Huber Purchase Agreement.
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On March 31, 2011, the Company signed an amendment to the Huber Purchase Agreement in which both parties agreed to extend the closing date to April 29, 2011. The Company agreed to provide 1,500,000 shares of stock in a non-refundable deposit in exchange for this extension.
On May 3, 2011, The Company signed an additional amendment to the Huber Purchase Agreement in which both parties agreed to extend the closing date to May 31, 2011. The Company agreed to provide 500,000 shares of stock in a non-refundable deposit in exchange for this extension.
On June 29, 2011, the Company was party to a reorganization transaction of Current Energy Partners Corporations, whereby, Current Energy Corporation became a wholly owned Subsidiary of High Plains Gas, Inc. Concurrently, the promissory note between the parties of $1,500,000 was satisfied by the issuance of 2,639,384 shares of High Plains Gas, Inc. common stock.
On July 29, 2011, The Purchase Sale Agreement between the Company and J.M. Huber Corporation was terminated and all expenses related to the acquisition were expensed in the current reporting period, totaling $4,125,000.
On August 1, 2011, the Company formed HPG Services, LLC as a subsidiary of High Plains Gas, Inc. in order to engage in oil and gas field services.
On August 1, 2011, the Company entered into a non-binding term sheet with Ironridge Global for proposed future funding of up to $13.5 million. Should proposed funding commence, the event will be expected to take place over the next several Quarters. The Company agreed to issue approximately 4,236,000 common shares in settlement of approximately $1,121,000 in accounts payable of the Company. At no time may Ironridge and its affiliates collectively own more than 9.99% of the total number of outstanding common shares of the Company.
On August 10, 2011, the Board of Directors adopted a resolution designating a new series of preferred stock as Series A Convertible Preferred Stock (“Series A Shares”). The number of shares designated was 2,500 shares having a par value of $1,000 each. The holders of Series A Shares are entitled to receive monthly dividends as defined in the resolution. Holders of Series A Shares shall have no voting rights until such time as shares convert into common stock pursuant to the resolution.
On August 10, 2011, the Company entered in to an agreement with Mark Hettinger, whereby, Mr. Hettinger agreed to convert $1,782,958 of notes payable into 1,783 Series A Convertible Preferred Stock.
On August 10, 2011, the Company entered in to an agreement with Joe Hettinger, whereby, Mr. Hettinger agreed to convert $297,160 of notes payable into 297 shares of Series A Convertible Preferred Stock.
Plan of operation
High Plains Gas intends to continue to operate existing methane fields including continuing plans for well reworks and re-activations and gathering systems improvements. As of June 30,
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2011, the Company had a total of 1,671 methane wells, in which we operated 551 producing methane wells, and 1,120 methane wells were either idle or shut-in.
Results of Operations
The following table sets forth selected operating data for the periods indicated:
Three and Six Months Ended June 30, 2011 Compared to Three and Six Months Ended June 30, 2010
| | | | | | | |
| THREE MONTHS ENDED JUNE 30, | | SIX MONTHS ENDED JUNE 30, |
| 2011 | | 2010 | | 2011 | | 2010 |
Revenues | | | | | | | |
Oil and gas production revenue | $ 3,379,997 | | $ 283,852 | | $ 7,407,081 | | $ 640,163 |
Other | -- | | 15,868 | | -- | | 56,555 |
Total Revenue | 3,379,997 | | 299,720 | | 7,407,081 | | 696,718 |
| | | | | | | |
Costs and Expenses | | | | | | | |
Lease operating expense and production taxes | 3,166,764 | | 304,249 | | 7,292,902 | | 522,087 |
General and administrative expense | 4,021,289 | | 199,974 | | 6,276,985 | | 300,358 |
Depreciation, depletion, and accretion | 1,583,320 | | 131,141 | | 3,736,111 | | 274,519 |
Exploration costs | 234,347 | | -- | | 673,517 | | -- |
Amortization of bond commitment/ financing fees | 742,262 | | -- | | 1,595,430 | | -- |
Realized commodity hedge gain | (56,760) | | -- | | (208,505) | | -- |
Loss on abandonment of oil and gas prospects | 4,125,010 | | -- | | 4,125,010 | | -- |
Total Costs and Expenses | 13,816,232 | | 490,164 | | 23,491,450 | | 1,096,964 |
| | | | | | | |
Operating (Loss) | (10,436,235) | | (190,444) | | (16,084,369) | | (400,246) |
| | | | | | | |
Other Income (Expense) | | | | | | | |
Other income | 54,275 | | 64,307 | | 61,143 | | 64,307 |
(Loss) on valuation of marketable securities | (890,257) | | -- | | (893,506) | | -- |
Unrealized commodity hedge gain (loss) | 392,699 | | -- | | (28,215) | | -- |
Loss on extinguishment of debt | (532,932) | | -- | | (532,932) | | -- |
Interest (expense) | (392,251) | | (21,450) | | (1,305,445) | | (59,786) |
Total Other Income (Expense) | (1,368,466) | | 42,857 | | (2,698,955) | | 4,521 |
| - | | | | | | |
Net (Loss) | $ (11,804,701) | | $ (147,587) | | $ (18,783,324) | | $ (395,725) |
| | | | | | | |
Net (loss) per share | $ (0.07) | | $ (0.00) | | $ (0.11) | | $ (0.00) |
Weighted average number of common shares outstanding- Basic and Diluted | 167,314,447 | | 130,000,022 | | 161,911,391 | | 130,000,022 |
Production Revenues and Volumes. Production revenues increased 1,157% to $7,407,081 six months ended June 30, 2011 from $640,163 six months ended June 30, 2010, and to $3,379,997 from $299,720 for the three months ended June 30, 2010 due to the acquisition of oil and gas properties from Pennaco Energy, Inc., a wholly owned subsidiary of Marathon Oil Company (“Marathon Transaction”) and an increase in natural gas commodity pricing basis after the effects of realized cash flow hedges. The effects of realized hedges only include settlements from hedging instruments that were designated as cash flow hedges. See below for more information related to the Commodity derivative gain (loss) line item.
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The production volumes increased 2,481% to 2,134 MMcf for the six months ended June 30, 2011 from 86 MMcf for the six months ended June 30, 2010 and to 961 MMCF from 84 MMCF for the three months ended June 30, 2010. The increase was primarily attributed to added increase in production attributed to the Marathon Transaction.
Hedging Activities. As of June 30, 2011, approximately 40% of our natural gas volumes were subject to financial hedges. Through the end of the six months ended June 30, 2010, the Company had no financial hedges in place. It is expected that as the Company continues to increase production, we will continue our philosophy of hedging 40-60% of our natural gas volumes through financial hedges.
Commodity Hedge (Loss). The “Commodity Hedge (loss)” line item on the Consolidated Statements of Operations is comprised of ineffectiveness on cash flow hedges and realized and unrealized gains and losses on hedges that do not qualify for cash flow hedge accounting. Unrealized gains and losses represent the change in the fair value of the derivative instruments that do not qualify for cash flow hedge accounting. As those instruments settle, their settlements will be presented as realized gains and losses within this same lime item. The six months ended June 30, 2011 reported an unrealized commodity hedge (loss) of $28,215. The Company entered into no commodity hedge contracts during the six months ended June 30, 2010. The loss was primarily due to the change in natural gas contracts.
Lease Operating Expenses and Production Taxes. Lease operating expenses increased to $7,292,902 from $522,087 during the first six months ended June 30, 2011 and June 30, 2010 respectively. Lease operating expenses increased to $3,166,764 from $304,249 for the three months ended June 30, 2011 and June 30, 2010 respectively. The increase in lease operating expenses was attributed to the increased operating expenses incurred by the Company as a result of the Marathon transaction.
The increase in production taxes is primarily related to the operation of the Marathon wells. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities.
Production tax rates vary across the different areas in which we operate. As the proportion of our production changes from area to area, our average production tax rate will vary depending on the quantities produced from each area and the production tax rates in effect for those areas.
Gathering, Transportation and Processing Expense. Gathering, transportation and processing expense increased to $892,946 and $2,023,900 during the first three and six months ended June 30, 2011 from $0 during the first three and six months ended June 30, 2010 respectively. The increase was primarily due to the gathering and transportation of gas produced by the Company as a result of the Marathon transaction. Although we don’t anticipate increases in our fixed demand charges, we may incur additional costs from other pipelines in the future.
Impairment Dry Hole Costs and Abandonment Expenses. Our impairment, dry hole costs and abandonment expense is $0 for the three and six months ended June 30, 2011 and June 30, 2010.
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Depreciation, Depletion and Amortization (“DD&A”). DD&A increased to $1,583,320 and $3,736,111 for the first three and six months ended June 30, 2011, compared to $131,141 and $274,519 for the first three and six months ended June 30, 2010 respectively. The increase in DD&A was attributed to increased production levels due to the operation of the Marathon wells.
General and Administrative Expense. General and administrative expense increased to $4,021,289 and $6,276,985 for the first three and six months ended June 30, 2011 from $199,974 and $300,358 for the first three and six months ended June 30, 2010, respectively. Non-cash stock-based compensation for services and payment of legal fees totaled $251,803 for the six months ended June 30, 2011 and $0 for the six months ended June 30, 2010. Consulting and other professional fees increased to $1,974,071 assigned to the Marathon Transaction, as well as costs associated with the Huber Transaction and the inherent costs attributed to being a registrant.
The remaining increase was primarily due to an increase in employee compensation costs and benefit programs attributed to additional employees that were hired after the Marathon transaction.
Interest Expense. Interest expense increased to $392,251 and $1,305,445 during the three and six months ended June 30, 2011 from $21,450 and $59,786 during the same period ended June 30, 2010, respectively due to an increase in debt levels, primarily due to the Marathon Transaction.
Net Income. Net (loss) increased to ($11,804,701) and ($18,783,324) in the first three and six months ended June 30, 2011, compared to ($147,587) and ($395,725) in the three and six months ended June 30, 2010, respectively. This is primarily due to the expenses charged off in association with the Huber acquisition as well as the inherent costs associated with increased operational costs of the Marathon assets.
Capital Resources and Liquidity
During the six months ended June 30, 2011, the Company issued a total of 4,250,000 shares to accredited investors through a private placement for cash consideration of $2,120,750 invested. The Company also issued 2,000,000 shares to J.M. Huber Corporation valued at $2,125,010 in connection with extensions on the acquisition of the Huber Assets.
Our primary sources of liquidity after formation of the Company have been cash provided by operating activities and sales, and other issuances of equity and debt securities. Our primary use of capital has been for the development and acquisition of natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources, including issuance of equity and debt securities, available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources available to our Company and our success in finding or acquiring additional reserves. We actively review acquisition opportunities on an ongoing basis. If we were to make significant additional
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acquisitions for cash, we may need to obtain additional equity or debt financing, which may be at a higher cost than previous issuances.
Our liquidity requirements arise principally from our working capital needs, including funds needed to operate our oil and gas business, as well as targeted acquisitions.
On November 19, 2010 CEP-M Purchase LLC (“CEP-M), which was acquired as a subsidiary on or about November 19, 2010 by the Company, entered into a Credit Agreement (the “Credit Agreement”) with Amegy Bank National Association (“Amegy”) and other associated lenders. The Credit Agreement provides for a revolving line of credit and letter of credit facility of up to $75,000,000, with an initial commitment amount of $6,000,000. The Credit Agreement terminates on November 19, 2013 and provides for interest at Amegy’s prime rate (adjustable under certain circumstances). The Credit facility includes a 0.5% commitment fee payable per annum on available commitments and certain other fees, and has numerous positive and negative covenants required to maintain the facility. The Credit Agreement is secured by essentially all of the oil and gas assets of CEP-M pursuant to a Security Agreement. Upon execution of the Credit Agreement, CEP-M utilized $6,000,000 available under the Credit Agreement as partial payment for the acquisition of the Marathon Assets.
As of June 30, 2011, we had negative working capital of $19,069,779 compared to positive working capital of $279,048 at June 30, 2010. We will continue seek additional sources of capital for the 2011 fiscal year. The negative working capital at June 30, 2011 results from $6,000,000 of line of credit debt classified as a current liability due to the Company being out of compliance on the debt covenants and from $6,334,516 of related party debt being classified as a current liability due to maturity dates expected within the next twelve months and from continued cash flow restrictions which have increased accrued expenses.
During the six months ended June, 30 2011, the Company generated cash flow from operations totaling $1,570,415 compared to operations consuming cash flows totaling $1,146,504 during the six months ended June 30, 2010. The significant factors for this change between periods include an increase in accrued expense due to constrained funds as well as significant non-cash items such as the abandonment of oil and gas prospect, share-based compensation and depletion/amortization.
We believe we will successfully operate our wells and collect funds due on sales. Although there can be no assurance that we will be successful in our efforts, the Company believes the combination of our cash on hand and revenue from executing our strategy will be sufficient to meet our obligations of current and anticipated operating cash requirements beyond fiscal 2011. If necessary, we will meet anticipated operating cash requirements by reducing costs, and/or pursuing sales of certain assets, or through seeking additional debt or equity financings.
Contingencies
Our directors, officers, employees and agents may claim indemnification in certain circumstances. We seek to limit and reduce potential obligations for indemnification by carrying directors’ and officers’ liability insurance, subject to deductibles.
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We also carry liability insurance, casualty insurance, for owned or leased tangible assets, and other insurance as needed to cover us against potential and actual claims and lawsuits that occur in the ordinary course of business.
Funding and Capital Requirements
Equity Financing
Beginning in October 2010 and continuing through June 30, 2011, the Company undertook a private placement transaction pursuant to which it sold an aggregate of 4,250,000 shares of common stock for $2,120,750 to a total of 39 accredited investors.
On February 17, 2011, the Company executed the Promissory Notes with two accredited investors for total proceeds of $1,000,000. Those promissory notes were due and were repaid on February 28, 2011. The proceeds were utilized as a portion of the deposit required for the Huber acquisition. As part of the transaction, the investors were issued warrants to purchase shares of the Company’s common stock.
On February 24, 2011, the Company entered into an agreement with Fletcher International, Ltd. (“Fletcher”) pursuant to which it sold Fletcher warrants to purchase 5,000,000 shares of the Company’s common stock for a price of $1,000,000. The exercise price for Common Stock to be purchased in the warrants issued to Fletcher is the lesser of (i) $1.25 and (ii) the average of the volume weighted average market price for all of the business days in the calendar month immediately preceding the date of the first notice of exercise of the Warrants, but in no event can the exercise price be less than $0.50. The warrants include a cashless exercise provision. The proceeds of the Fletcher warrants were utilized as a deposit for the Huber Purchase Agreement.
Financial Instruments and Other Information
As of June 30, 2011 and December 31, 2010, we had cash, accounts receivable, accounts payable, notes payable and accrued liabilities, which are each carried at approximate fair market value due to the short maturity date of those instruments. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments.
Critical Accounting Policies
Use of Estimates in the Preparation of Financial Statements. We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements. The most critical estimate we make is the engineering estimate of proved oil and gas properties and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future net cash flows.
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Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable.
Estimated proven oil and gas reserves. The evaluation of our oil and gas reserves is critical to management of our operations and ultimately our economic success. Decisions such as whether a development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation, evaluating impairment and estimating the life of our oil and gas properties in the estimation of our asset retirement obligations. Our total reserves are classified as proved, possible and probable. Proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves and when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable estimates. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves and when probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed proved plus probable plus possible reserve estimates.
Independent reserve engineers prepare the estimates of our oil and gas reserves presented in this report based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the Securities and Exchange Commission. The evaluation of our reserves by the independent reserve engineers involves their rigorous examination of our technical evaluation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Reservoir engineers interpret this data to determine the nature of the reservoir and ultimately the quantity of total oil and gas reserves attributable to a specific property. Our total reserves in this report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the total reserves will be produced, the timing and the ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes or proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices or production equipment/facility capacity.
Standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs at year-end. Natural gas prices were calculated for each property using the differentials to an average for the year of the first of the month Henry Hub Louisiana Onshore price. The standardized measure is based on the average of the beginning of the month
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pricing for 2010. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since the market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil and gas prices.
Successful Efforts Method Accounting. The Company uses the successful efforts method of accounting for oil and gas producing activities. Oil and gas exploration and production companies choose one of two acceptable accounting methods, successful efforts or full cost. The most significant difference between the two methods relates to the accounting treatment of drilling costs for unsuccessful exploration wells “dry holes”) and exploration costs. Under the successful efforts method, exploration costs and dry hole costs (the primary uncertainty affecting this method) are recognized as expenses when incurred and the costs of successful exploration wells are capitalized as oil and gas properties. Entities that follow the full cost method capitalize all drilling and exploration costs including dry hole costs into one pool of total oil and gas property costs.
While it is typical for companies that drill exploration wells to incur dry hole costs, our primary activities during 2011 focused on development and re-opening existing well-bores. Nevertheless, it is anticipated that we will selectively expand our exploration drilling in the future. It is impossible to accurately predict specific dry holes. Because we cannot predict the timing and magnitude of dry holes, quarterly and annual net income can vary dramatically.
The calculation of depreciation, depletion and amortization of capitalized costs under the successful efforts method of accounting differs from the full cost method in that the successful efforts method requires us to calculate depreciation, depletion and amortization expense on individual properties rather than one pool of costs. In addition, under the successful efforts method, we assess our properties individually for impairment compared to one pool of costs under the full cost method.
Depreciation and Depletion of Oil and Natural Gas Properties. Capitalized costs of producing oil and gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of production method. This method is applied through the simple multiplication of reserve units produced by the leasehold costs per unit on a field by field basis. Leasehold cost per unit is calculated by dividing the total cost of acquiring the leasehold by the estimated total proved oil and gas reserves associated with that lease. Field cost is calculated by dividing the total cost by the estimated total proved producing oil and gas reserves associated with that field.
Risks and Uncertainties. Historically, oil and gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in prices received could have a significant impact on future results.
Stock-Based Compensation. Stock-based compensation and warrants are measured in accordance with the guidance of ASC Topic 718, Compensation – Stock Compensation (“ASC
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718”) at the grant date based on the value of the awards using the Black Scholes Option pricing model and are recognized on a straight-line basis over the requisite service period (usually the vesting period). The Company estimates forfeitures in calculating the cost related to stock-based compensation as opposed to recognizing these forfeitures and the corresponding reduction in expense as they occur. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. A market condition is not considered to be a vesting condition with respect to compensation expense. Therefore, an award is not deemed to be forfeited solely because a market condition is not satisfied.
Asset Retirement Obligation. The Company follows FASB ASC 410 – Asset Retirement and Environmental Obligations which requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. The fair value of asset retirement obligation liabilities has been calculated using an expected present value technique. Fair value, to the extent possible, should include a fair market risk premium for unforeseeable circumstances. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period and the capitalized cost is amortized over the useful life of the related asset. Upon retirement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires the Company to record a liability for the fair value of the dismantlement and plugging and abandonment costs, excluding salvage values.
Derivatives. Derivative financial instruments, utilized to manage or reduce commodity price related to the Company’s production, are accounted for under the provisions of FASB ASC 815 – Derivatives and Hedging. Under this statement, derivatives are carried on the balance sheet at fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivatives are recorded in other comprehensive income or loss and are recognized in the statement of operations when the hedged item affects earnings. If the derivative is not designated as a hedge, changes in the fair value are recognized in other expense. Ineffective portions of changes in the fair value of cash flow hedges are also recognized in loss on derivative liabilities.
As of June 30, 2011, the Company was required to hedge production of 5,500 MMBtu / day until December 2012.
Fair Value Measurements. The Company has elected to follow the fair value option for reporting the securities from Big Cat Energy Corporation. This election will require the Company to mark these securities to fair value at each reporting period.
The Company follows current accounting guidelines in measuring and disclosing their financial instrument’s fair values. Fair Values are determined using three levels of fair value hierarchy:
·
Level 1 – quoted prices in active markets for identical assets or liabilities;
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·
Level 2 – inputs, other than the quoted prices in active markets that are observable either directly or indirectly; and
·
Level 3 – unobservable inputs based on the Company’s own assumptions.
Recent Accounting Pronouncements
We evaluate the pronouncements of various authoritative accounting organizations, primarily the Financial Accounting Standards Board (“FASB”), the SEC, and the Emerging Issues Task Force (“EITF”) to determine the impact of new pronouncements on U.S. generally accepted accounting principles (“GAAP”) and the impact on the Company. We have adopted the following new standards during the period ended June 30, 2011:
Fair Value Measurements – Accounting Standards Update (“ASU”) 2010-06 amended existing disclosure requirements about fair value measurements by adding required disclosures about items transferring into and out of levels 1 and 2 in the fair value hierarchy; adding separate disclosures about purchase, sales, issuances and settlements relative to level 3 measurements; and clarifying, among other things, the existing fair value disclosures about the level of disaggregation. The final provisions of ASU 2010-06 were adopted during the period ended June 30, 2011 and adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows.
Share-based Payments – ASU 2010-13 clarifies the classification of an employee based payment award with an exercise price denominated in the currency of a market in which the underlying security trades. The Company adopted ASU 2010-13 during the period ended June 30, 2011 and adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows.
Business Combinations – ASU 2010-29 requires a public entity to disclose pro forma information for business combinations that occurred in the current reporting period. The disclosures include pro forma revenue and earnings of the combined entity for the current reporting period as though the acquisition date for all business combinations that occurred during the year had been as of the beginning of the annual reporting period. This ASU is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 31, 2010 with early adoption permitted. The Company adopted ASU 2010-29 during the period ended June 30, 2011 and adoption had no impact on the Company’s consolidated financial position, results of operations or cash flows.
We have reviewed all recently issued, but not yet effective, accounting pronouncements and do not believe the future adoption of any such pronouncements may be expected to cause a material impact on our financial condition or the results of our operations.
Reliance on one revenue source
During the six months ended June 30, 2011, we continued to have a significant concentration of revenue from the marketing and sale of natural gas. Our business model provides for us to hedge our revenues to some extent by acquiring additional properties. Currently, we continue to rely upon the sale of natural gas as our significant concentration of revenue.
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Operating Leases
On July 1, 2011, we moved our primary office from 3601 Southern Drive, Gillette, Wyoming 82718, formerly the Marathon office location, to 1200 East Lincoln, Gillette, Wyoming, 82716. We are leasing the 1200 East Lincoln office space on a month to month lease, while terms for a new lease are being negotiated. We believe that these facilities are adequate for our current operations.
Employment contracts
The Company is party to several employment agreements with key personnel, all of which are effective for a 12-month period beginning January 1, 2011. The agreements range from $125,000 to $175,000 per year and all agreements contain customary terminology as to termination criteria.
Pipeline Transportation Obligations
The Company has certain pipeline transportation obligations that specify the delivery of a fixed and determinable quantity of natural gas or the payment of the respective transportation fees. The following table sets forth information about material long- term firm transportation contracts for pipeline capacity. These contracts were acquired as part of the acquisition of the Pennaco “North & South Fairway Assets.” Under these firm transportation contracts, we are obligated to deliver minimum daily gas volumes, or pay the respective transportation fees for any deficiencies in deliveries. Although exact amounts vary, as of June 30, 2011 we are committed to the following pipeline capacities:
| | | | | | | | | | |
Type of Arrangement | | Pipeline System / Location | | Deliverable Market | | Gross Deliveries (MMBtu/d) | | Term |
| | | | | | | | |
Firm Transport | | WIC Medicine Bow | | Rocky Mountains | | | 15,000 | | | 07/10 –11/15 |
| | | | | | | | | | |
Firm Transport | | Kinder Morgan Trailblazer | | Rocky Mountains | | | 22,500 | | | 07/10 - 05/12 |
| | | | | | | | | | |
Firm Transport | | Copano Fort Union | | Rocky Mountains | | | 10,000 | | | 07/10 - 11/11 |
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are a smaller reporting company as defined by Rule 12b-2 of the Securities Exchange Act of 1934 and are not required to provide the information under this item.
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ITEM 4. CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures
Brent M. Cook, the Company’s Principal Executive Officer and Joseph Hettinger, the Company’s Principal Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15e and 15d-15e under the Securities Exchange Act of 1934 (the “Exchange Act”) as of June 30, 2011. Disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported on a timely basis and that such information is accumulated and communicated to management, including the Principal Executive Officer and Principal Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Company’s Principal Executive Officer and Principal Financial Officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not effective.
Material Weakness
Internal Controls over Financial Reporting
In connection with the preparation of our consolidated financial statements for the quarter ended June 30, 2011, certain significant deficiencies in internal control became evident to management that represented material weaknesses, including:
i.
Lack of an audit committee. Until June 29, 2011, we did not have an audit committee who would be charged with the purpose of overseeing the accounting and financial reporting processes of the Company.
ii.
Insufficient segregation of duties in our accounting functions and limited personnel. During the year, we had limited staff that performed nearly all aspects of our financial reporting process including, but not limited to access to the underlying accounting records and systems, the ability to record journal entries and responsibility for the preparation of financial statements. This created certain incompatible duties and a lack of review over the financial reporting process that would likely result in a failure to detect errors in spreadsheets, calculations, or assumptions used to compile the financial statements and related disclosures as filed with the SEC. These control deficiencies could result in a material misstatement to our annual or interim consolidated financial statements that would not be prevented or detected. In addition, our Company’s accounting personnel do not have sufficient technical accounting knowledge relating to accounting for complex generally accepted accounting principle matters. Management corrected any errors prior to the release of our Company’s December 31, 2010 and June 30, 2011 consolidated financial statements.
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Changes in Internal Controls
During the six months ended June 30, 2011 the Board of Directors established an audit committee who is charged with the purpose of overseeing the accounting and financial reporting processes of the Company. Management believes that the changes in the Company’s internal controls over financial reporting that occurred during the six months ended June 30, 2011 are not yet sufficient to ensure internal control over financial reporting.
PART II: OTHER INFORMATION
ITEM 1 - LEGAL PROCEEDINGS
On approximately June 27th, 2011, High Plains Gas, Inc. relocated its corporate offices and warehousing facility from 3601 Southern Drive in Gillette, Wyoming to offices and warehouse facilities located at 1200 East Lincoln St., Gillette, Wyoming. The Company and the Landlord of the Southern Drive properties failed to agree upon lease terms for the previous office and warehouse location. The Company chose to relocate rather than obligate themselves to major repairs costs that were needed on the building and premises. Subsequent to the Company moving, the Landlord, Hunt Club Investment Group, LLC a Michigan limited liability company (“Hunt Club”) filed a lawsuit on July 20th, 2011 in District Court in Campbell County, Wyoming. Hunt Club alleges that a lease agreement was reached between the parties and that future rents in the amount of $20,000 per month for a three year period was agreed upon. They are seeking the principal remaining balance of $640,000 plus interest and attorney’s fees and costs in the lawsuit. The Company denies that any such lease agreement was reached and intends to defend itself from such claims.
From time to time, the Company may be named in claims arising in the ordinary course of business. Currently, no material legal proceedings or claims, other than those disclosed above, are pending against or involve the Company that, in the opinion of management, could reasonably be expected to have a material adverse effect on its business and financial condition.
ITEM 2 - UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
On May 3rd, 2011, the Company issued 500,000 shares of our common stock to J.M. Huber Corporation in connection with an extension of the closing date of the Huber asset acquisition.
ITEM 3 - DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 – (Removed and Reserved)
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ITEM 5 - OTHER INFORMATION
None.
ITEM 6 – EXHIBITS
High Plains Gas, Inc. includes by reference the following exhibits:
No.
Description
3.1
Articles of Incorporation, exhibit 3.1 filed with the registrant’s Registration Statement on Form SB-2, as amended; filed with the Securities and Exchange Commission on May 19, 2005.
3.2
Bylaws, filed as exhibit 3.2 with the registrant’s Registration Statement on Form SB-2, as amended; filed with the Securities and Exchange Commission on May 19, 2005.
The following exhibits are filed as part of this quarterly report on Form 10-Q:
No.
Description
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101
Interactive Data Files (XBRL)
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Dated: August, 19 2011
HIGH PLAINS GAS, INC.
(the registrant)
By:
\s\ Brent M. Cook
Brent M. Cook
Chief Executive Officer
By:
\s\ Joseph Hettinger
Joseph Hettinger
Chief Financial Officer
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