UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the quarterly period ended March 31, 2011
---------------------------------------------
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 for the transition period from to
Commission file number 333-125068
----------
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
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(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 [ ]
[1]
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.
[2]
HIGH PLAINS GAS, INC.
INDEX TO QUARTERLY REPORT ON FORM 10-Q
PART I. FINANCIAL INFORMATION PAGE NO.
-------- ------------------------------------------------------------ -------
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
PART II. OTHER INFORMATION
-------- ----------------------------------------------------------------
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
[3]
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
[4]
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
[5]
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
[6]
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
============== ==============
[7]
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
[8]
HIGH PLAINS GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 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.
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) 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.
[9]
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:
AT MARCH 31 AND DECEMBER 31:
---------------------------------
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:
AT MARCH 31 AND DECEMBER 31:
-------------------------------
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
=========== ==============
[10]
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
[11]
(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.
3. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS:
--------------------------------------------
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.
4. RELATED PARTY TRANSACTIONS:
--------------------------
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.
[12]
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.
5. INVESTMENT IN EQUITY 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, 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.
6. EQUITY TRANSACTIONS:
-------------------
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.
[13]
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.
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
(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.
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 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
[14]
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
==============
10. DEBT FINANCING - RELATED PARTIES
--------------------------------
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.
11. FAIR VALUE MEASUREMENT AND DISCLOSURE
-------------------------------------
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)
=============
[16]
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.
12. ASSET RETIREMENT OBLIGATION
---------------------------
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
============= ===========
13. COMMITMENTS AND CONTINGENCIES:
-----------------------------
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:
[17]
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.
14. SUBSEQUENT EVENTS:
------------------
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.
[18]
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.
[19]
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.
[20]
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)
============ ==========
[21]
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
[22]
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.
[23]
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
[24]
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
[25]
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.
[26]
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.
[27]
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.
[28]
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
[29]
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
[30]
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
[31]
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.
[32]
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)
[33]
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
[34]
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: 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
[35]