UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q
(Mark One)

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the transition period from to

HIGH PLAINS GAS, INC.
(Exact name of registrant as specified in its charter)

 Nevada 26-3633813
--------------------------------------------------------------------------------
 (State or other jurisdiction of (I. R. S. Employer Identification No.)
 incorporation or organization)

 3601 Southern Dr, Gillette, WY 82718
--------------------------------------------------------------------------------
 (Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (307) 686-5030
 ----------------

(Former name, former address and former fiscal year, if changed since last
report)

Copies of all communications should be sent to:

Cutler Law Group
3355 W Alabama, Ste 1150
Houston, Texas 77098
Telephone: (713) 888-0040
Facsimile: (800) 836-0714
Email: rcutler@cutlerlaw.com

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

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

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

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

The number of shares of the registrant's common stock outstanding as of March 31, 2011 was 166,746,102 shares and the number of shares of the registrant's common stock outstanding as of May 16, 2011 was 167,243,602.

HIGH PLAINS GAS, INC.
INDEX TO QUARTERLY REPORT ON FORM 10-Q

Item 1. Interim Financial Statements (Unaudited)

Condensed Consolidated Balance Sheets of High Plains Gas, Inc. at March 31, 2011 (unaudited) and December 31, 2010 4

Condensed Consolidated Statements of Operations of High Plains Gas, Inc. for the Three Months ended March 31, 2011 and 2010 (Unaudited) 6

Condensed Consolidated Statement of Cash Flows of High Plains Gas, Inc. for the Three Months ended March 31, 2011 and 2010 (Unaudited) 7

Notes to Interim Financial Statements for High Plains Gas, Inc. (unaudited) 9

Item 2. Management's Discussion and Analysis 19

Item 3. Quantitative and Qualitative Disclosures about Market Risk. 31

Item 4. Controls and Procedures 31

Item 1. Legal Proceedings 33

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 33

Item 3. Defaults Upon Senior Securities 33

Item 4. (Removed and Reserved) 33

Item 5. Other Information 34

Item 6. Exhibits 34

Signatures 35

HIGH PLAINS GAS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
MARCH 31, 2011 AND DECEMBER 31, 2010

 MARCH 31, DECEMBER 31,
 2011 2010
 ------------- --------------
ASSETS (UNAUDITED)
CURRENT ASSETS:
 Cash and cash equivalents $ 622,887 $ 208,823
 Accounts receivable 1,195,209 1,114,335
 Investment in equity securities, at fair value 2,641,859 2,645,108
 Deferred financing fees, net 116,027 196,238
 Bond commitment fees, net 1,595,806 2,469,914
 Funds in escrow 750,000 --
 Deferred equity issuance costs 184,170 --
 Prepaid and other assets 178,228 143,741
 ------------- --------------
 Total current assets 7,284,186 6,778,159
 ------------- --------------

OIL AND GAS PROPERTIES-using successful efforts
 method
 Deposit on acquisition of oil and gas properties 3,635,000 --
 Unproven oil and gas properties 17,371,984 18,238,813
 Proven oil and gas properties 25,570,711 24,516,504
 Less accumulated depletion, depreciation
 and amortization (5,074,212) (3,174,836)
 ------------- --------------
 Oil and gas properties, net 41,503,483 39,580,481
 ------------- --------------

PROPERTY, PLANT AND EQUIPMENT, NET 1,313,776 1,316,307
CERTIFICATES OF DEPOSIT 200,000 200,000
OTHER ASSETS 125,000 125,000
 ------------- --------------

TOTAL ASSETS $ 50,426,445 $ 47,999,948
 ============= ==============

LIABILITIES AND EQUITY

CURRENT LIABILITIES:

 Accounts payable and accrued liabilities $ 7,693,119 $ 3,994,301
 Accounts payable - related parties 287,281 232,048
 Current portion-term debt 1,661,685 1,661,685
 Current portion - lines of credit 6,352,579 6,352,579
 Current portion - commodity hedge 126,267 --
 Notes payable - related parties 6,402,203 6,224,062
 ------------- --------------
 Total current liabilities 22,523,134 12,431,009

DEBT OBLIGATIONS - LINES OF CREDIT, NET
 OF CURRENT 194,571 162,624
DEBT OBLIGATIONS - TERM DEBT, NET OF CURRENT 903,441 943,065
COMMODITY HEDGE, NET OF CURRENT 898,389 603,742
ASSET RETIREMENT OBLIGATION 8,448,854 8,229,630
 ------------- --------------
 Total liabilities 32,968,389 28,403,736

HIGH PLAINS GAS, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
MARCH 31, 2011 AND DECEMBER 31, 2010 (CONT'D)

 MARCH 31, DECEMBER 31,
 2011 2010
 ------------- --------------
EQUITY: (UNAUDITED)
Preferred stock - $.001 par value: 20,000,000xxx
 shares authorized; 0 shares issued and
 outstanding -- --
Common stock-$.001 par value: 250,000,000
 shares authorized; 166,746,102 shares and
 160,934,202 shares issued and outstanding,
 respectively 166,746 160,934
Subscription receivable (217,500) --
Additional paid in capital 30,308,654 25,256,500
Accumulated income (loss) (12,799,844) (5,821,222)
 ------------- --------------
Total equity 17,458,056 19,596,212
 ------------- --------------

TOTAL LIABILITIES AND EQUITY $ 50,426,445 $ 47,999,948
 ============= ==============

See accompanying notes to financial statements

HIGH PLAINS GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 2010 AND 2011
(UNAUDITED)

THREE MONTHS ENDED
MARCH 31,

 2011 2010
 ------------- ------------

REVENUES
 Oil and gas production revenue $ 4,027,084 $ 356,311
 Other -- 40,687
 ------------- ------------
 Total Revenue 4,027,084 396,998

COSTS AND EXPENSES
 Lease operating expense and production
 taxes 4,126,138 217,838
 General and administrative expense 2,255,696 100,384
 Depreciation, depletion, amortization
 and accretion 2,152,791 288,578
 Exploration costs 439,170 -
 ------------- ------------
 Total Costs and Expenses 8,973,795 606,800
 ------------- ------------

OPERATING (LOSS) (4,946,711) (209,802)

OTHER INCOME (EXPENSE)
 Other income 6,868 --
 (Loss) on valuation of equity securities (3,249) --
 Amortization of bond commitment and
 financing fees (853,168) --
 Realized commodity hedge gain 151,745 --
 Unrealized commodity hedge (loss) (420,914) --
 Interest (expense) (913,194) (38,336)
 ------------- ------------
 Total Other Income (Expense) (2,031,912) (38,336)
 ------------- ------------

NET (LOSS) $ (6,978,623) $ (248,138)
 ============= ============

Net (loss) per share $ (0.04) $ (0.01)

Weighted average number of common shares
 outstanding - basic and diluted 161,427,692 65,000,000

See accompanying notes to financial statements

HIGH PLAINS GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010
(UNAUDITED)

THREE MONTHS ENDED
MARCH 31,

 2011 2010
 -------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
 Net loss $ (6,978,623) $ (248,138)
 Adjustments to reconcile net loss to net cash
 provided by operating activities:
 Depletion, depreciation, amortization
 and accretion 2,152,791 288,578
 Unrealized hedge (gain) loss 420,914 --
 Stock based compensation 1,250 --
 Stock issued for services 30,000 --
 (Loss) on fair value of equity securities 3,249 --
 Amortization of fees 853,168 --
 Interest added to related party notes payable 87,254 --
 Changes in operating assets and liabilities:
 Accounts receivable (80,874) 28,677
 Prepaid and other assets 45,724 (23,290)
 Accounts payable and accrued liabilities 3,785,089 (224,670)
 -------------- --------------
 Net cash (used in) operating activities 319,942 (178,843)

CASH FLOWS FROM INVESTING ACTIVITIES:
 Additions to oil and gas properties (187,378) (85,572)
 Purchase of property, plant and equipment (41,757) (21,904)
 Deposit on acquisition of oil and gas property (2,000,000) --
 -------------- --------------
 Net cash (used in) investing activities (2,229,135) (107,476)

CASH FLOWS FROM FINANCING ACTIVITIES:
 Proceeds from related party notes payable 1,668,604 131,919
 Repayment of related party notes payable (1,351,000) --
 Proceeds from line of credit 75,000 30,000
 Repayment of line of credit (43,053)
 Member contributions -- 118,124
 Warrants issued for cash 1,000,000 --
 Stock issued for cash 1,947,500 --
 Payment of financing fees (750,000) --
 Payment of equity issuance fees (184,170) --
 Payment on debt (39,624) --
 -------------- --------------
 Net cash provided by financing activities 2,323,257 280,043

NET INCREASE (DECREASE) IN CASH AND
 CASH EQUIVALENTS 414,064 (6,276)

CASH AND EQUIVALENTS, at beginning of period 208,823 45,426
 -------------- --------------

CASH AND EQUIVALENTS, at end of period $ 622,887 $ 39,150
 ============== ==============

HIGH PLAINS GAS, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE THREE MONTHS ENDED MARCH 31, 2011 AND 2010 (CONT'D)
(UNAUDITED)

THREE MONTHS ENDED
MARCH 31,

 2011 2010
 -------------- -----------------
OTHER INFORMATION:

Cash paid for interest $ 241,799 $ 38,336
 ============== =================

Deposit on acquisition of oil and gas
 property with stock $ 1,635,000 $ --
 ============== =================

Stock sold through subscription receivable $ 217,500 $ --
 ============== =================

Stock and warrants issued in conjunction
 with related party notes payable $ 309,573 $ --
 ============== =================

Warrants issued as compensation $ 1,250 $ --
 ============== =================

See accompanying notes to financial statements

HIGH PLAINS GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2011

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 and Montana, targeting coal bed methane reserves with prospective acreage potential located in the Niobrara Shale, Mowry Shale and Muddy formations.

The Company's operations and plans for expansion are dependent upon continued equity or debt financing.

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 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.

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) income taxes, and (8) cash flow estimates used in impairment tests of long-lived assets.

Oil and Natural Gas Properties

High Plains follows the successful efforts method of accounting for its investments in oil and natural gas properties.

Depletion expense was $1,893,226 and $285,406 for the three months ended March 31, 2011 and 2010, respectively.

The Company transferred unproved costs of $866,829 and $0 to the amortization base during the three months ended March 31, 2011 or 2010, respectively.

During the three months ended March 31, 2011 and 2010 there was no impairment expense related to oil and natural gas properties.

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:

 2011 2010
 ----------------- --------------

Proved oil and gas properties $ 25,570,711 $ 24,516,504
Accumulated DD&A (5,074,212) (3,174,836)
 ----------------- --------------

Net capitalized costs $ 20,496,499 $ 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:

 2011 2010
 ---------------- -------------

Deposit on acquisition of oil and
 gas properties $ 3,635,000 $ -
Unproven properties 17,371,984 18,238,813
Acquisition costs 9,269,415 9,002,071
Development costs 8,141,784 7,354,921
ARO Costs 8,159,512 8,159,512
 ---------------- -------------

Total $ 46,577,695 $ 42,755,317
 ================ =============

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.

 March 31, December 31,
 2011 2010
 ----------- --------------
Transportation and vehicles $631,597 $607,422
Equipment and other 582,698 582,698
Computers and software 169,496 155,861
 ----------- --------------
 1,383,791 1,345,981
Less Depreciation (70,015) (29,674)
 ----------- --------------
 $1,313,776 $1,316,307
 =========== ==============

Depreciation expense was $40,341 and $1,827 during the three months ended March 31, 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 March 31, 2011 the off-balance sheet arrangements that the Company had entered into include undrawn letters of credit, operating lease agreements, gathering, compression, 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 project 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 March 31, 2011 and 2010 were not significant.

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 March 31, 2011 or December 31, 2010.

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 taxes through March 31, 2011 are subject to a full valuation allowance.

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 March 31 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 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.

The Company utilizes swap contracts 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's derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty. 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 contracts 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 March 31, 2011 and December 31, 2010, the Company had entered into swap agreements related to its natural gas production as summarized below. Location and quality differentials attributable to the Company's properties are not included in the following prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual CIG Rocky Mountains price.

During the three months ended March 31, 2011, the Company had the following transactions with related parties:

The Company borrowed and repaid a total of $1,150,000 of short-term debt from various shareholders.

The Company repaid debt to a shareholder of $201,000 that was outstanding as of December 31, 2010.

The Company borrowed $291,887 from shareholder-officers that remains outstanding at March 31, 2011.

Default penalty interest of $87,254 was added to outstanding principal balances owed to shareholder-officers during the three months ended March 31, 2011.

The Company was reimbursed operating expenses from a related entity totaling $87,140.

The Company incurred consulting fees from a related party totaling $4,000 of which $4,000 is included in accounts payable as of March 31, 2011.

The Company purchased the use of drilling tools from a related party totaling $97,966 of which $47,653 is included in accounts payable as of March 31, 2011.

The Company incurred legal fees from a related party totaling $16,623 which, when added to legal fees incurred in earlier periods, totals $73,868 included in accounts payable as of March 31, 2011.

The Company incurred travel costs owed to a related party totaling $5,495 which, when added to travel costs incurred in earlier periods, totals $8,780 included in accounts payable as of March 31, 2011.

The Company paid loan origination fees of $71,075 to a related party.

See Note 6 for details of equity transactions with related parties.

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, 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 March 31, 2011 the fair value of the securities was $.09 per share, or $1,800,000. The fair value of the warrants has decreased to $841,859 and the decrease of $3,249 has been recognized in the statement of operations.

During the three months ended March 31, 2011, the Company had the following transactions:

The Company had private placements of 4,330,000 shares of restricted stock to qualified investors. The Company received proceeds of $1,947,500 for these private placements and has an outstanding subscription receivable balance of $217,500 as of March 31, 2011.

The Company issued 60,000 shares of restricted stock in payment of $30,000 of legal fees.

The Company issued 125,000 shares of 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 624,679 warrants relating to outstanding related party debt valued at $287,022.

The Company issued 200,000 warrants for compensation valued at $7,564.

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.

 Number of Weighted Avg Remaining
 Shares Exercise Price Contractual Term
 --------- --------------- -----------------
Warrants outstanding
 - January 1, 2011 5,289,627
Granted during period 824,679 $ 0.50 $ 4.88
Exercised during period
Forfeited during period
Expired during period
 --------- --------------- -----------------
Warrants outstanding
 - March 31, 2011 6,114,306 $ 0.50 $ 4.88
 ========= =============== =================

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.

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 (effective rate was 4.25% as of December 31, 2010). Any outstanding amounts and related interest 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 March 31, 2011.

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 March 31, 2011 the outstanding principal balance was $200,000.

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 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 March 31, 2011 the outstanding principal balance was $6,000,000. The credit facility is subject to restrictive covenants and as of December 31, 2010, the Company is not in compliance with certain covenants. This condition has caused the reclassification 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 March 31, 2011 the outstanding principal balance was $347,150.

 2011
 ----------
 Total outstanding principal $6,547,150
 Current portion 6,352,579
 ----------
 Long-term portion of lines of credit $ 194,571
 ==========

 Outstanding balances are due:
 2011 $6,352,579
 2012 194,571
 2013 --
 ----------
 $6,547,150
 ==========


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 March 31, 2011 the outstanding principal balance was $1,029,479.

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 March 31, 2011 the outstanding principal balance is $35,647.

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 March 31, 2011 the outstanding principal balances is $1,500,000.

 2011
 --------------

Total outstanding principal $ 2,565,126
Current portion 1,661,685
 --------------
Long-term portion of term debt $ 903,441
 ==============

 [15]

Outstanding balances are due:
 2011 $ 1,661,685
 2012 170,122
 2013 710,740
 2014 15,291
 2015 7,288
 --------------
 $ 2,565,126
 ==============

See details of additions to related party notes payable at Note 4. A total of $6,402,203 and $6,224,062 was owed to various related parties as of March 31, 2011 and December 31, 2010, respectively.

Fair Value Measurements at March 31, 2011 Using:

 Quoted Prices in Significant
 Active Markets Other Significant
 for Identical Observable Unobservable
 Assets Inputs Inputs
Description (Level 1) (Level 2) (Level 3)
------------------ ------------- ----------------- ----------- -------------

Equity securities
 recorded at fair
 value $ 2,641,859 $ 1,800,000 $ - $ 841,859

Commodity hedge
 liability ($1,024,656) - - ($1,024,656)

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 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
Issued value of warrants --
Decrease in value (3,249)
 -------------
Balance, March 31, 2011 $ 841,859
 =============

Balance, January 1, 2011 ($603,742)
Change in value of commodity hedge (420,914)
 -------------
Balance, March 31, 2011 ($1,024,656)
 =============

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.

Changes in the Company's asset retirement obligations were as follows:

THE THREE MONTHS ENDED
MARCH 31,

 2011 2010
 ------------- -----------
Asset retirement obligations,
 beginning of period $ 8,229,630 $ 33,046
Liabilities related to acquisitions -- 35,087
Revisions in estimated liabilities -- --
Accretion expense 219,224 1,013
 ------------- -----------
Asset retirement obligations,
 end of period $ 8,448,854 $ 69,146
 ============= ===========

OPERATING LEASES

The Company is currently renting office space on a month-to-month basis and has no long-term lease commitments.

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 March 31, 2011 we are committed to the following pipeline capacities:

 GROSS
 TYPE OF PIPELINE SYSTEM / DELIVERABLE DELIVERIES
 ARRANGEMENT LOCATION MARKET (MMBTU/D) TERM
-------------- ----------------- ----------- ----------- -------------

 Rocky
Firm Transport WIC Medicine Bow Mountains 15,000 07/10 -11/15

 Kinder Morgan Rocky
Firm Transport Trailblazer Mountains 22,500 07/10 - 05/12

 Rocky
Firm Transport Copano Fort Union Mountains 10,000 07/10 - 11/11

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.

Pursuant to FASB ASC 855, management has evaluated all events and transactions that occurred from March 31, 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 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. On May 3, 2011, the Company issued 500,000 additional restricted shares to J.M. Huber Corporation in connection with the extension of closing of the purchase agreement until May 31, 2011.

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; 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.

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 has 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, which will either be returned or be credited to the purchase price at the time of closing.

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 in shares of the Company's common stock for a purchase 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.

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. The shares will either be credited to the purchase price or returned at closing.

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. The shares will also either be credited to the purchase price or returned at closing if the Company is able to raise the funds necessary to complete the closing.

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 March 31, 2011, the Company had a total of 1,671 methane wells, in which we operated 730 producing methane wells, and 941 methane wells were either idle or shut-in.

RESULTS OF OPERATIONS

The following table sets forth selected operating data for the periods indicated:

THREE MONTHS ENDED MARCH 31, 2011 COMPARED TO THREE MONTHS ENDED MARCH 31, 2010

 2011 2010
 ------------ ----------
REVENUES:
 Gas and oil revenue $ 4,027,084 $ 356,311
 Other -- 40,687
 ------------ ----------
 Total Revenue 4,027,084 396,998

COSTS AND EXPENSES
 Lease operating expense and production taxes 4,126,138 217,838
 General and administrative expense 2,255,696 100,384
 Depreciation, depletion, amortization and
 accretion 2,152,791 288,578
 Exploration costs 439,170 --
 ------------ ----------
 Total Costs and Expenses 8,973,795 606,800
 ------------ ----------

OPERATING (LOSS) (4,946,711) (209,802)

OTHER INCOME (EXPENSE)
 Other income 6,868 --
 (Loss) on valuation of equity securities (3,249) --
 Amortization of bond commitment and
 financing fees (853,168) --
 Realized commodity hedge gain 151,745 --
 Unrealized commodity hedge (loss) (420,914) --
 Interest (expense) (913,194) (38,336)
 ------------ ----------
 Total Other Income (Expense) (2,031,912) (38,336)
 ------------ ----------

NET INCOME (LOSS) $(6,978,623) $(248,138)
 ============ ==========

PRODUCTION REVENUES AND VOLUMES. Production revenues increased to $4,027,084 for the three months ended March 31, 2011 from $356,311 for the three months ended March 31, 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.

The production volumes increased to 1,173,190 Mcf for the three months ended March 31, 2011 from 86,754 Mcf for the three months ended March 31, 2010. The increase was primarily attributed to added increase in production attributed to the Marathon Transaction.

HEDGING ACTIVITIES. As of March 31, 2011, approximately 40% of our natural gas volumes were subject to financial hedges, which resulted in an increase in natural gas revenues of $151,745 after settlements for all derivatives. Through the end of the three months ended March 31, 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 three months ended March 31, 2011 reported an unrealized commodity hedge (loss) of $420,914. The Company entered into no commodity hedge contracts during the three months ended March 31, 2010. The loss was primarily due to the change in natural gas contracts.

LEASE OPERATING EXPENSES AND PRODUCTION TAXES. Lease operating expenses increased to $4,126,138 during the three months ended March 31, 2011 from $217,838 for the same period in 2010. The increase in lease operating expenses was primarily due to the increased operating expenses due to the operation of the Marathon wells.

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 $945,792 during the three months ended March 31, 2011 from $0 (a nominal amount) during the three months ended March 31, 2010. The increase was primarily

due to the operation of the Marathon wells. 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 months ended March 31, 2011 and March 31, 2010.

DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A"). DD&A was $2,152,791 for the three months ended March 31, 2011 compared to $288,578 for the three months ended March 31, 2010. 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 $2,255,696 for the three months ended March 31, 2011 from $100,384 for the three months ended March 31, 2010. Non-cash stock-based compensation for services and payment of legal fees totaled $31,250 for the three months ended March 31, 2011 and $0 for the three months ended March 31, 2010. Consulting and other professional fees increased by $396,934 due to the Marathon Transaction, costs associated with the anticipated 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 $913,194 during the three months ended March 31, 2011 from $38,336 during the three months ended March 31, 2010 due to an increase in debt levels, primarily due to the Marathon Transaction.

NET INCOME. Net (loss) increased by ($6,730,485), from ($248,138) in the three months ended March 31, 2010 to ($6,978,623) in the three months ended March 31, 2011. This is primarily due to the Marathon Transaction and the inherent costs associated with increased operational costs of the assets.

CAPITAL RESOURCES AND LIQUIDITY

During the fiscal quarter ended March 31, 2011, the Company issued a total of 4,330,000 shares to 39 accredited investors through a private placement for cash consideration of $1,947,500 invested. The Company also issued 1,500,000 shares to J.M. Huber Corporation valued at $1,635,000 in connection with an extension on the acquisition of the Huber Assets. The Company issued an additional 500,000 shares to J.M. Huber Corporation on May 3, 2011 for an additional extension of the closing date.

In addition, during the three months ended March 31, 2011, the Company issued a total of 2,500 shares in connection with a compensation arrangement, 60,000 shares for legal services and 44,400 shares connected to notes payable to related parties.

Our primary sources of liquidity after formation have been net cash provided by operating activities, 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 us 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 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 the $6,000,000 available under the Credit Agreement as partial payment in the acquisition of the Marathon Assets.

As of March 31, 2011, we had negative working capital of $15,238,948 compared to negative working capital of $5,652,850 at March 31, 2010. We will seek additional sources of capital for the 2011 fiscal year. The negative working capital at March 31, 2011 results from $6,000,000 of line of credit debt classified as a current liability due to debt covenant violations and from $6,402,203 of related party debt being classified as a current liability due to maturity dates expected within the next twelve months.

During the three months ended March 31 2011, the Company generated positive cash flow from operations totaling $319,942 compared to operations consuming cash flows for operations totaling ($178,843) during the three months ended March 31, 2010. The majority of the cash provided from operations during the three months ended March 31, 2011 was due to the non-cash depletion, amortization and accretion totaling $2,152,791 and to the increase in accounts payable and accrued expenses totaling $3,785,089 when added back to the reported net loss of ($6,978,623).

During the three months ended March 31 2011, the Company consumed cash flow for investing activities totaling $2,229,135 compared to operations consuming cash flows for operations totaling $107,476 during the three months ended March 31, 2010. The majority of the cash used

for investing activities during the three months ended March 31, 2011 was due to the $2,000,000 cash deposit paid to J.M. Huber Corporation for the anticipated oil and gas property acquisition.

During the three months ended March 31 2011, the Company generated positive cash flow from financing activities totaling $2,323,257 compared to $280,043 during the three months ended March 31, 2010. The majority of the cash provided from financing operations during the three months ended March 31, 2011 was due to the stock issued for cash totaling $1,947,500 and the warrants sold for cash totaling $1,000,000.

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, we believe 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.

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 March 2011, the Company undertook a private placement transaction pursuant to which it sold an aggregate of 8,615,000 shares of common stock for $4,307,500 to a total of 78 accredited investors.

On February 17, 2011 the Company entered into 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 in shares of the Company's common stock for a purchase 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 March 31, 2011 and 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. 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 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 2010 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 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 March 31, 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;

- 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 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 three months ended March 31, 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.

OPERATING LEASES

During April 2011, the Company continued negotiations to lease office space in Gillette, Wyoming at 3601 Southern Drive, Gillette, Wyoming 82718, where we currently occupy office

space. After the Marathon transaction was completed, we have remained in the 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 $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 March 31, 2011 we are committed to the following pipeline capacities:

 GROSS
 TYPE OF PIPELINE SYSTEM / DELIVERABLE DELIVERIES
 ARRANGEMENT LOCATION MARKET (MMBTU/D) TERM
-------------- ----------------- ----------- ----------- -------------

 Rocky
Firm Transport WIC Medicine Bow Mountains 15,000 07/10 -11/15

 Kinder Morgan Rocky
Firm Transport Trailblazer Mountains 22,500 07/10 - 05/12

 Rocky
Firm Transport Copano Fort Union 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.

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 March 31, 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 year ended December 31, 2010, certain significant deficiencies in internal control became evident to management that represented material weaknesses, including:

i. Lack of an audit committee. 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 March 31, 2011 consolidated financial statements.

CHANGES IN INTERNAL CONTROLS

During the three months ended March 31, 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. As the Committee is just forming and becoming familiar with the Company's accounting and financial reporting processes, management does not believe this material weakness is fully remediated as of March 31, 2011. Thus, management believes that there were no changes in the Company's internal controls over financial reporting that occurred during the three months ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II: OTHER INFORMATION

ITEM 1 - LEGAL PROCEEDINGS

No legal proceedings were initiated by or served upon the Company in the three month period ending March 31, 2011.

From time to time the Company may be named in claims arising in the ordinary course of business. Currently, no 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 February 28, 2011, the Company issued 4,330,000 shares of common stock to 39 accredited investors in a private placement for proceeds of $2,165,000. There was no general solicitation or advertising undertaken in connection with this private placement.

On February 28, 2011, the Company issued a total of 29,400 shares to our Chief Financial Officer as part of a compensation arrangement.

On February 28, 2011, the Company issued a total of 60,000 shares valued at $30,000 to two accredited investors for legal services to the Company.

On February 28, 2011, the Company issued a total of 125,000 shares of our common stock to an accredited investor for Financial and Public Relations services.

On March 24, 2011, the Company issued a total of 600,000 warrants to purchase our common stock to two accredited investors in connection with a financing of $1,000,000 utilized for the deposit on the Huber asset acquisition.

On March 31, 2011, the Company issued 1,500,000 shares of our common stock to J.M. Huber Corporation in connection with an extension of the closing date of the Huber asset acquisition. Those shares will either be applied to the closing price or returned to the Company upon closing of the acquisition.

ITEM 3 - DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 - (REMOVED AND RESERVED)

ITEM 5 - OTHER INFORMATION

None.

ITEM 6 - EXHIBITS

High Plains Gas, Inc. includes by reference the following exhibits:

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

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: May 16, 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