Attached files
_______________________________________________________________________________
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
________________________________________________________________________________
FORM 10-K
________________________________________________________________________________
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010
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Commission file number 333-125068
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________________________________________________________________________________
HIGH PLAINS GAS, INC.
(Exact name of registrant as specified in its charter)
www.highplainsgas.com
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NEVADA 36-36343813
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(State or other jurisdiction (I. R. S. Employer Identification No.)
of incorporation or organization)
Registrant's telephone number, including area code: (307) 686-5030
3601 SOUTHERN DR., GILLETTE, WYOMING 82718
(Address of principal executive offices)
________________________________________________________________________________
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
________________________________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on which Registered
None None
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Securities registered pursuant to Section 12(g) of the Act:
Common Stock ($.001 par value)
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(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as
defined in Rule 405 of the Securities Act.
Yes [ ] No [x]
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ] No [x]
Indicate by check mark whether the registrant has submitted electronically and
posted on its corporate Web site, if any, every Interactive Data File required
to be submitted and posted pursuant to Rule 405 of Regulation S-T during the
preceding 12 months (or for such shorter period that the registrant was required
to submit and post such files).
Yes [ ] No [ ]
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
definition of "accelerated filer, large accelerated filer and smaller reporting
company" as defined in Rule 12b-2 of the Exchange Act.
Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [ ] Smaller reporting company [x]
Indicate by checkmark whether the registrant is a shell company (as defined in
Rule 126-2 of the Act)
Yes [ ] No [x]
The aggregate market value of the common equity held by non-affiliates of the
registrant as of April 13, 2011 was $63,589,634.
The number of shares of the registrant's common stock outstanding as of April
13, 2011, was 166,523,602 shares.
[TOC]
CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
The following discussion is included to inform our existing and potential
security holders generally of some of the risks and uncertainties that can
affect us and to take advantage of the "safe harbor" protection for
forward-looking statements afforded under federal securities laws.
From time to time, our management or persons acting on our behalf make
forward-looking statements to inform existing and potential security holders
about us. This Annual Report on Form 10K contains forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities and Exchange Act of 1934, as amended, which are
subject to a number of risks and uncertainties, many of which are beyond our
control. These statements by nature are subject to certain risks, uncertainties
and assumptions and will be influenced by various factors. Should any of the
assumptions underlying a forward-looking statement prove incorrect, actual
results could vary materially. Although we believe that the expectations
reflected in such forward-looking statements are reasonable, we can give no
assurance that such expectations will prove to have been correct. Important
factors that could cause actual results to differ materially from our
expectations include, but not limited to, our assumptions about:
- business and financial strategy
- oil and natural gas reserves;
- lower oil and natural gas prices negatively affecting our ability to
borrow or raise capital, or enter into joint venture arrangements and
potentially requiring accelerated repayment of amounts borrowed under our credit
facility;
- declines in the values of our oil and natural gas properties resulting in
write-downs;
- exploration and development drilling prospects, inventories, projects and
programs
- ability to obtain industry partners for our prospects on favorable terms
to reduce our capital risks and accelerate our exploration activities;
- ability to obtain permits and governmental approvals;
- identified and future drilling locations;
- changing regulatory environment;
- transportation and access to pipelines;
- the ability of our hedge counterparties to fulfill their obligations;
- lease operating expenses and costs related to the acquisition and
development of oil and gas properties;
- availability and costs of drilling rigs and field services;
- the impact of current economic and financial conditions on our ability to
raise capital;
- general and administrative costs, oilfield services costs and other
expenses related to our business;
- technology;
- future operating results; and
- plans, objectives, expectations and intentions.
It is difficult to predict and many of these factors are beyond our ability to
control. These factors are not intended to represent a complete list of the
general or specific factors that may affect us.
All of these types of 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. These statements involve risks and
uncertainties inherent in our business, including those set forth in Item 1A
under the caption "Risk Factors," "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations" and other sections in this
Annual Report on Form 10-K for the year ended December 31, 2010, and other
filings with the SEC, and are subject to change at any time. Our actual results
could differ materially from these forward-looking statements. We undertake no
obligation to update publicly any forward-looking statements as a result of new
information, future events or otherwise. These cautionary statements qualify
all forward-looking statements attributable to us or persons acting on our
behalf.
We caution you not to place undue reliance on these forward-looking statements.
We urge you to carefully review and consider the disclosures made in this Form
10-K and our reports filed with the SEC that attempt to advise interested
parties of the risks and factors that may affect our business.
PART I
ITEM 1. BUSINESS
GENERAL
High Plains Gas Inc., ("Company," "we," "our," or "us") 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, which will include
investing in and profitably developing 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. Substantially all of our
revenues are generated through the sale of natural gas at market prices and the
settlement of commodity hedges. Our management team has significant experience
acquiring and developing E&P assets in the Rocky Mountains and has an extensive
network of industry relationships in the region. Through its solid foundation
and experience, the Company intends to pursue expansion plans across this
region.
SUMMARY OF RECENT COMPANY HISTORY
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 July 28, 2010, the Company entered into an agreement to acquire High Plains
Gas, LLC, a Wyoming limited liability company ("High Plains LLC") (the
"Reorganization Agreement). On September 13, 2010, the Company amended its
Articles of Incorporation to change its name to High Plains Gas, Inc. and
increase its authorized common
stock to 250,000,000 shares. Effective October 29, 2010, the Company completed
the acquisition of High Plains Gas, LLC, the operating entity for the Company's
business. The reorganization has been accounted for as a reverse merger and
under the accounting rules for a reverse merger, the historical financial
statements and results of operations of High Plains Gas, LLC became those of the
company. The symbol was changed on January 20, 2011 to "HPGS" to more
accurately reflect the Company's new name. Under the Reorganization Agreement,
shareholders and other parties representing what was Northern Explorations
retained 26,000,000 shares of the Company's common stock and designees of High
Plains LLC were issued 104,000,000 shares of the Company's common stock.
As of September 30, 2010, the Company entered into agreements with Current
Energy Partners Corporation, a Delaware Corporation ("Current") and its wholly
owned subsidiary CEP M Purchase LLC ("CEP"). In accordance with the terms of
the agreements, the Company initially purchased a Convertible Note from Current
for the amount of $3,550,000 and also provided assistance with CEP's bonding
requirements. The proceeds from the Convertible Note as well as approximately
$6,000,000 in bank financing were used (described below) by Current through its
subsidiary CEP to purchase a significant resource base and land position from
Pennaco Energy, Inc. ("Pennaco"), a wholly owned subsidiary of Marathon Oil
Company. The assets consisted of Pennaco's "North & South Fairway" assets
located in the Powder River Basin. These properties encompass approximately
155,000 net operated acres (the "Marathon Assets"). The acquisition included
many operational capacities including flow lines, transportation rights and
production wells both active and idle. The transaction did not transfer deep
oil rights, but focused upon mineral rights between the surface and depth above
the base Tertiary Paleocene Fort Union Formation, generally above 2,500 feet.
Under the original agreement, the Company was appointed to perform the operating
duties with respect to the assets as specified in the underlying Purchase and
Sale Agreement executed on July 21, 2010 by and among Current, CEP and Pennaco
(the "Pennaco Agreement").
On October 18, 2010, the Company, pursuant to the Reorganization Agreement,
issued 104,000,000 shares to nine individuals representing 100% of the
membership in High Plains LLC and as a result, High Plains LLC became a 100%
owned subsidiary of the Company.
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, at $0.03 per
share for $600,000. The purchase price of $600,000 consisted of a combination
of $200,000 cash and 739,180 restricted shares of the Company valued at
$400,000. The Purchase Agreement also grants the Company warrants to purchase
an additional 10,000,000 shares of restricted common stock of Big Cat at $0.15
per share. If the Company exercised the warrants, it would own 30,000,000
shares of Big Cat's common stock, which represents 40.6% of Big Cat. The
warrants have a term of five years from the effective date of the Purchase
Agreement. The number of warrants is to be adjusted in the event of a
reclassification, change, stock dividend, stock split, combination,
reorganization, merger or consolidation affecting the price or number of shares
issuable or exercisable under the warrants so as to maintain an approximately
equivalent number of shares and exercise price for the warrant holders before
and after such a transaction. Any such adjustment is to be made pursuant to
official notice from the Company in connection with the transaction. On the
closing of this transaction, Big Cat nominated Mark Hettinger, Chairman of the
Company, to Big Cat's Board of Directors.
During the fiscal quarter ended December 31, 2010, the Company entered into a
$75,000,000 credit facility with Amegy Bank of which $6,000,000 was borrowed to
finance the Pennaco Acquisition.
On January 24, 2011, the Company's Board of Directors amended the Company's
bylaws to provide for a five member Board of Directors, and appointed Gary
Davis, Cordell Fonnesbeck and Alan R. Smith as directors in addition to the
already appointed directors, Mark D. Hettinger and Joseph Hettinger.
On February 2, 2011, the Company signed a Purchase and Sale Agreement with J.M.
Huber Corporation (the "Huber Purchase Agreement") in which the Company agreed
to purchase approximately 313,000 net acres of leasehold and 2,302 wells in the
Basin for $35,000,000 (the "Huber Acquisition"). The Company provided
$2,000,000 in non-refundable deposits in connection with the Huber Purchase
Agreement and later issued 1,500,000 shares of common
stock to extend the closing date (which shares will either be returned to the
Company or applied to the purchase price at 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, which shares will either
be returned or applied to the purchase price at closing.
The Company and its subsidiaries have not been in bankruptcy, receivership, or
any similar proceeding, and, to the best knowledge of management, have not
defaulted on the terms of any note, loan, lease, or other indebtedness or
financing arrangement requiring the issuer to make any material payments. Other
than described above, the Company has not recently been a party to any material
reclassification, merger, consolidation, or purchase or sale of a significant
amount of assets not in the ordinary course of business.
AREAS OF OPERATION
Powder River Basin
[GRAPHIC OMITTED]
The Powder River Basin is located in northeastern Wyoming and southeastern
Montana and covers an area of approximately 25,800 square miles, of which
approximately 75% is in Wyoming. Fifty percent of the Powder River Basin is
believed to have the potential for coalbed methane ("CBM") production.
Coal beds in this region intermingle at varying depths with sandstones and
shale. The majority of the productive coal zones range from 150 feet to 1,850
feet below ground. The uppermost formation is the Wasatch Formation, extending
from land surface to 1,000 feet deep. Most of the coal seams in the Wasatch
Formation are continuous, but thin (six feet or less). The Fort Union Formation
lies directly below the Wasatch Formation and can be as thick as 3,000 feet.
The coal beds in Fort Union formation are usually more plentiful in the upper
portion, named the Tongue River member. This member is normally 1,500 to 1,800
feet thick, of which a net total of 350 feet of coal can be found in various
seams. The thickest of the individual coal seams is over 150 feet thick.
CBM production is primarily from the Fort Union rather than the overlying
Wasatch. The Fort Union Formation supplies municipal water to the city of
Gillette, WY and is the same formation that contains the coals that are
developed for CBM. The coal beds contain and transmit more water than the
sandstones. The sandstones and coal beds are both used for the production of
water and the production of CBM. Total Dissolved Solids (TDS) levels in the
water produced from these coal beds meet the water quality criteria for drinking
water. The huge coal deposits contain enormous amounts of methane gas due to
their unusual thickness as evident in the amount of coal produced from this
region. The low gas content per ton and low pressure were initially seen as
barriers to development. The first wells drilled and completed produced massive
volumes of water but little gas. As companies altered their drilling to more
shallow wells, production increased. The low drilling costs, the short
completion time and the relatively good quality of water coupled with
inexpensive water management i.e. surface discharge encouraged development.
COAL BED METHANE INDUSTRY
OVERVIEW. Once a nuisance and mine safety hazard, CBM has become a valuable
part of our Nation's energy portfolio. CBM production has increased during the
last 15 years and now accounts for about a twelfth of U.S. natural gas
production. As America's natural gas demand grows substantially over the next
two decades, CBM will become increasingly important for ensuring adequate and
secure natural gas supplies for the United States.
CBM is simply methane found in coal seams. Most coal beds are permeated with
methane, and a cubic foot of coal can contain six or seven times the volume of
natural gas that exists in a cubic foot of a conventional sandstone reservoir.
It is produced by non-traditional means, and although it is sold and used the
same as traditional natural gas, its production is very different. Often a coal
seam is saturated with water which provides a trapping mechanism to contain the
methane inside the coal seams.
Within coal seams, methane is present on the surface of the solid material.
Hydrostatic pressure causes the methane to adhere to the coal surface via a
phenomenon termed adsorption. Whenever reservoir pressure is reduced, the
methane desorbs off of coal surfaces, diffuses through the matrix material, and
then flows through a system of natural fractures (cleats) and into a well for
delivery to the surface. CBM is the same as the natural gas in our transmission
and distribution pipelines; it is used for space heating and power generation,
as a feedstock for chemical production, and in manufacturing processes.
Coal bed natural gas is either biogenic or thermogenic in origin. Biogenic
methane is generated from bacteria in organic matter and is typically a dry gas.
It is generally found at depths of less than 1,000 feet from the earth's surface
in low-rank coals (those coals with a lower carbon content). Thermogenic
methane forms when heat and pressure transform organic matter in coal into
methane. This type of methane is typically a wet gas and frequently contains
trace amounts of water vapor, carbon dioxide, nitrogen, and possibly hydrogen
sulfide. It is generally found at greater depths, in higher-rank coals.
The contiguous United States is estimated to have CBM in-place resources of 700
trillion cubic feet (Tcf), of which 100 Tcf may be economically recoverable.
The most prolific basins exist in the western United States, but eastern areas
of the nation also have notable reserves of CBM. Other areas that have
significant CBM potential include Alaska and the Illinois Basin.
UNITED STATES AND THE BASIN COAL BED NATURAL GAS RESOURCES. United States CBM
proved reserves and production have grown nearly every year since 1989. In
2007, CBM accounted for 21.9 Tcf of the reserves in the U.S., with 1.6 Tcf
being produced in 2007. CBM produced in Colorado, New Mexico, and Wyoming
totaled nearly 1.3 Tcf during 2007, which represents over 80% of total CBM
production in the U.S. Other notable producing areas include the Central
Appalachian and Warrior basins in the eastern United States and the Uinta and
Raton basins in the Rocky Mountain region. The majority of future CBM
production is expected from western basins.
Estimates of amounts of methane gas in the Basin vary and are often
re-calculated. There are several methods to estimate the amount of recoverable
gas from a coal seam, all having varying degrees of accuracy.
Coal bed natural gas can be recovered from underground mines before, during, or
after mining operations. Significant volumes of CBM also are extracted from
"non-mineable" coal seams that are relatively deep or thin, of poor or
inconsistent quality, or represent difficult mining conditions. Ninety percent
of the country's coal resource is non-mineable but represents a vast potential
source of natural gas.
Vertical and horizontal wells, including multi-laterals, are used to develop CBM
resources. For the most part, the quality of a seam's cleat system
(high-conductivity flow paths) will dictate the type of well completion and
stimulation employed. In high-permeability settings, flow enhancement may not be
required. In other situations, hydraulic fracturing and cavitation stimulations
are used.
Although development of CBM resources has been quite successful, the industry
continues to face many issues. These issues are varied, some highly
contentious, and include access to resources, permitting, exhaustive
environmental planning, litigation, produced-water management, natural gas
markets and capital formation, and the need for advanced technologies.
Another important environmental issue for CBM developers stands as a positive.
The release of methane into the atmosphere, either through natural seeps,
ventilation during mining, or via other means, has environmental consequences.
Methane is a potent greenhouse gas, with 21 times the global warming potential
of carbon dioxide. In fact, coal mining accounts for about 10% of U.S. methane
emissions. Therefore, recovery of CBM mitigates a large source of methane
emissions and allows for economic use of the energy source.
HOW DOES CBM COMPARE TO CONVENTIONAL NATURAL GAS? Methane is the chief
component of natural gas, and CBM can be used in very much the same way as
conventional gas. Conventional gas is formed in limestone and shale formations;
pressure and temperature unite to transform organic matter into hydrocarbons
over time, similar to thermogenic production in deeper coals. Natural gas
migrates upward until trapped by a geologic barrier or fault and remains in this
reservoir until it is discovered and drilled, or released by some natural means.
Conventional gas wells are typically 4,000 to 12,000 feet deep and extract gas
from sandstone and shale formations. The location and extent of conventional
gas typically requires exploratory drilling since the location of reservoirs is
not apparent from the surface. Coal bed wells are generally considered shallow
and range from 400 to 1,500 feet in the Basin but can be as deep as 5,000 feet
in some basins.
COMPANY PROJECTS
DRY FORK. The Company began its operations in 2007 with the acquisition of the
Dry Fork project in the Powder River Basin. We first acquired acreage in the
Basin by securing a lease with Western Fuel Cooperative (Dry Fork Mine) for all
methane within a depth of 3,000 feet of surface. We developed this project and
had drilled and completed seven wells on this lease. These wells are currently
in the de-watering stage. The Company proceeded to build infrastructure and
gathering pipelines on the Dry Fork lease which essentially controls the access
to this project by owning the only transmission line to the nearest sales point.
This development makes up the Dry Fork Phase I and may ultimately be comprised
of 70 newly drilled wells. Dry Fork Phase II is a continuation of Phase I and
may include an additional 83 newly drilled wells.
GRAMS AND MILLS GILLETTE FIELD. In October 2010, the Company acquired a total
of 57 shut-in wells in the Grams and Mills Gillette fields, with an additional
10 drilling locations permitted, and another four locations in the permitting
process. Seven wells have been recompleted and re-enhanced with an additional
seven more wells scheduled in the near future.
THE PENNACO NORTH AND SOUTH FAIRWAY ACQUISITION. On November 19, 2010 the
Company secured approximately 155,000 net acres of leasehold, including 1,614
wells of which 493 wells are active and producing, from Pennaco Energy, a
subsidiary of Marathon Oil (the "Marathon Assets"). This acquisition included
approximately 13,600 Mcf/d net being produced from the 493 active wells. The
Marathon Assets have approximate 97% Working Interest
("WI") with a Net Revenue Interest ("NRI") of approximately 80%. The Company
assumed operational control on December 1, 2010 and has been successful in
activating several of the 1,100+ idle wells acquired with the property.
This is potentially helpful to the Company not only by increasing daily
production, but in decreasing and delaying idle well bonding costs associated
with the properties. These properties and wells comprise a significant
opportunity and responsibility for the Company in the refurbishment and
re-activation plan. The Company believes it can re-activate approximately 20-30
wells per month and place these wells into successful production, thus
increasing gas production and sales. The Company believes that there are over
40,000 net acres of undeveloped acres and opportunities for future drill sites
on the property as well. The Company intends to refurbish and re-activate wells
while natural gas pricing is relatively low and prepare for future developments
via drilling programs as natural gas prices strengthen to a level that warrants
development of available acreage. The Company is active in managing its
operational costs and focused on reducing these costs in the future.
OIL AND GAS DATA
PROVED RESERVES
The data in the below table represent estimates by NSAI, a leading independent
third party engineering firm with extensive experience in the Powder River
Basin. At this time, we believe they are more knowledgeable about the wells due
to the continual analysis throughout the year for other companies operating in
the region as compared to the relatively short term analysis performed
internally.
The natural gas reserves are an estimation of accumulations of natural gas that
cannot be measured exactly. The accuracy of any reserves estimate is a function
of the quality of available data and engineering and geological interpretation
and judgment. Accordingly, reserves may vary from the quantities of oil and
natural gas that are ultimately recovered. See "Item 1A. Risk Factors."
The following table presents our estimated net proved natural gas reserves and
the present value of our estimated proved reserves at December 31, 2010 based on
reserve report prepared by outside independent third party petroleum engineers.
All of our proved reserves included in our reserve report are located in North
American. Netherland, Sewell & Associates, Inc. ("NSAI") prepared our reserves
estimates as of December 31, 2010.
Gas Reserves Future Net Revenues ($)
----------------------- ---------------------------
Gross Net Present Worth
Category MCF MCF Total at 10%
-------------------------- ----------- ---------- ----------- --------------
Proved Developed Producing 9,389,434 6,357,905 9,136,600 8,301,500
Proved Developed Non-
Producing 7,474,463 5,253,624 9,137,900 7,167,900
Proved Undeveloped 4,093,289 2,613,872 3,194,500 1,393,200
----------- ---------- ----------- --------------
Total Proved 20,957,186 14,225,401 21,469,000 16,862,600
Probable Developed 31,041,451 15,973,270 29,558,600 22,564,200
Probable UnDeveloped 87,752,757 55,580,483 78,061,800 33,702,000
----------- ---------- ----------- --------------
Total Probable 118,794,208 71,553,753 107,620,400 56,266,200
Possible Developed 27,490,451 6,862,488 14,471,700 10,383,500
Possible Undeveloped 95,848,508 62,726,123 80,437,500 33,829,600
----------- ---------- ----------- --------------
Total Possible 123,338,959 69,588,611 94,909,200 44,213,100
Gas volumes are expressed in thousands of cubic feet (MCF) at standard
temperature and pressure bases.
The estimates shown in this table are for proved reserves. This report does not
include any value that could be attributed to interests in undeveloped acreage
beyond those tracts for which undeveloped reserves have been estimated.
Reserves categorization conveys the relative degree of certainty; reserves
subcategorization is based on development and production status. The estimates
of reserves and future revenue included herein have not been adjusted for risk.
Future gross revenue to the HPG interest is prior to deducting state production
taxes and ad valorem taxes. Future net revenue is after deductions for these
taxes, future capital costs, and operating expenses but before consideration of
any income taxes. The future net revenue has been discounted at an annual rate
of 10 percent to determine its present worth, which is shown to indicate the
effect of time on the value of money. Future net revenue presented in this
report, whether discounted or undiscounted, should not be construed as being the
fair market value of the properties.
For the purposes of this report, NSAI did not perform any field inspection of
the properties, nor did NSAI examine the mechanical operation or condition of
the wells and facilities. NSAI has not investigated possible environmental
liability related to the properties; therefore, the estimates do not include any
costs due to such possible liability. Also, the estimates do not include any
salvage value for the lease and well equipment or the cost of abandoning the
properties.
Gas prices used in this report are based on the 12-month unweighted arithmetic
average of the first-day-of-the- month price for each month in the period
January through December 2010. The average CIG Rocky Mountains spot price of
$3.945 per MMBTU is adjusted by area for energy content and transportation fees.
All prices are held constant throughout the lives of the properties. For the
proved reserves, the average adjusted gas price weighted by production over the
remaining lives of the properties is $3.162 per MCF.
Lease and well operating costs used in this report are based on operating
expense records of HPG and the previous owners of the properties. For
nonoperated properties, these costs include the per-well overhead expenses
allowed under joint operating agreements along with estimates of costs to be
incurred at and below the district and field levels. As requested, lease and
well operating costs for the operated properties include only direct lease- and
field-level costs. For all properties, headquarters general and administrative
overhead expenses of HPG are not included. Lease and well operating costs are
held constant throughout the lives of the properties. Capital costs are
included as required for workovers, new development wells, and production
equipment. The future capital costs are held constant to the date of
expenditure.
NSAI has made no investigation of potential gas volume and value imbalances
resulting from overdelivery or underdelivery to the HPG interest. Therefore,
the estimates of reserves and future revenue do not include adjustments for the
settlement of any such imbalances; our projections are based on HPG receiving
its net revenue interest share of estimated future gross gas production.
For the purposes of this report, NSAI used technical and economic data
including, but not limited to, geologic maps, well test data, production data,
historical price and cost information, and property ownership interests. The
reserves have been estimated using deterministic methods; these estimates have
been prepared in accordance with the Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers (SPE Standards). NSAI used standard engineering and
geoscience methods, or a combination of methods, including performance analysis,
volumetric analysis, and analogy, that NSAI considered to be appropriate and
necessary to categorize and estimate reserves in accordance with SEC definitions
and guidelines.
The data used in our estimates were obtained from HPG, previous owners of the
properties, public data sources, and the nonconfidential files of Netherland,
Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting
geoscience, performance, and work data are on file in our office. The titles to
the properties have not been examined by NSAI, nor has the actual degree or type
of interest owned been independently confirmed. The technical persons
responsible for preparing the estimates presented herein meet the requirements
regarding qualifications, independence, objectivity, and confidentiality set
forth in the SPE Standards. NSAI are independent petroleum
engineers, geologists, geophysicists, and petrophysicists; NSAI does not own an
interest in these properties nor are they employed on a contingent basis.
The reserves estimates shown herein have been estimated by NSAI, a worldwide
leader of petroleum property analysis for industry and financial organizations
and government agencies. NSAI was founded in 1961 and performs consulting
petroleum engineering services under Texas Board of Professional Engineers
Registration No. F-002699. Within NSAI, the technical person primarily
responsible for auditing the estimates set forth in the NSAI audit letter
incorporated herein is Diana Ball. Ms. Ball has been practicing consulting
petroleum engineering at NSAI since 1997. She has an MBA with Finance
concentration from University of St. Thomas, Houston, 1985; BS in Petroleum
Engineering, University of Tulsa, 1980. Diana joined NSAI in 1997. She has
extensive CBM experience including multiple domestic projects in the Black
Warrior, San Juan, Raton, Uinta, and Powder River Basins.
The NSAI process of estimating our wells and reserves are intended to determine
the net proved reserves estimate and future net revenue (discounted 10%). The
process includes the following:
- The NSAI engineer performs an independent decline curve analysis on proved
producing wells based on production and pressure data. This data is provided to
NSAI by us as well as other companies operating in the Powder River Basin;
- The NSAI engineer may verify the production data with the public data;
- The NSAI engineer uses his or her individual interpretation of the
information and knowledge of the reservoir and area to make an independent
analysis of proved producing reserves;
- The NSAI technical staff will prepare independent maps and volumetric
analyses on our properties and offsetting properties. They review our geologic
maps, log data, core data, pertinent pressure data, test information and
pertinent technical analyses, as well as data from offsetting producers;
- The NSAI engineer will estimate the hydrocarbon recovery of the remaining
gas-in-place based upon his/her knowledge and experience; and
- The NSAI engineer confirms the oil and gas prices used for the SEC
reserves estimate.
The reserves audit letter provided by NSAI states that "the estimates in this
report have been prepared in accordance with the definitions and guidelines of
the U.S. Securities and Exchange Commission (SEC) and conform to the FASB
Accounting Standards Codification Topic 932, Extractive Activities - Oil and
Gas, except that per-well overhead expenses are excluded for operated properties
and future income taxes are excluded for all properties."
On December 31, 2008, the SEC published final rules and interpretations updating
its oil and gas reserves reporting requirements called "Modernization of Oil and
Gas Reporting." Many of the revisions were updates to definitions in the
existing oil and gas rules to make them consistent with the Petroleum Resource
Management system, which is a widely accepted set of evaluation guidelines that
are designed to support assessment processes throughout the resource asset
lifecycle. These guidelines were prepared by the Society of Petroleum
Engineers, or SPE, Oil and Gas Reserves Committee with cooperation from many
industry organizations. One of the key changes to the previous SEC rules
related to using a 12-month average commodity price to calculate the value of
proved reserves versus the former method of using year-end prices. Other key
revisions included the ability to include nontraditional resources in reserves,
the use of new technology for determining reserves, the opportunity to establish
proved undeveloped reserves without the requirement of an adjacent producing
well and permitting disclosure of probable and possible reserves. Companies
were required to comply with the amended disclosure requirements for
registration statements filed after January 1, 2010, and for annual reports for
fiscal years ending on or after December 31, 2009. Early adoption was not
permitted.
OPERATIONS
GENERAL
The Company is engaged in the operation and production of 1,726 methane wells
located in the Powder River Basin near Gillette, WY. The company's business
strategy focuses on revenue from production and operation of owned wells,
including rework or existing wells designed to increased production. The
Company's ability to manage production costs and increase revenues on a per well
basis provides a formula for continued operational success and distinguishes us
from our competitors. We are also actively engaged in the acquisition of
properties, primarily in the Powder River Basin, which contain revenue from
existing production and leased but undeveloped mineral acreage.
High Plains' management of costs associated with the operation of methane wells
is the company's competitive advantage. By managing our lifting costs per MCF
at a lower rate than our competitors, the company is able to acquire wells that
companies with higher cost structures are forced to abandon. This cost
structure, when combined with the expected increases in production associated
with the rework of wells and pipeline systems, creates a sustainable business
model for the operation and production of High Plains' methane wells.
NATURAL GAS MARKETING AND DELIVERY COMMITMENTS
The spot markets for natural gas are subject to volatility as supply and demand
factors fluctuate. As detailed below, we sell our production under both
long-term (one year or more) or short-term (less than one year) agreements.
Regardless of the term of the contract, the vast majority of our production is
sold at variable or market sensitive prices.
NATURAL GAS MARKETING. Our natural gas is transported through our own and third
party gathering systems and pipelines, and we incur processing, gathering and
transportation expenses to move our natural gas from the wellhead to a
purchaser-specified delivery point. Our natural gas is also sold under both
long-term and short term agreements at prices negotiated with third parties.
These expenses vary based on the volume and distance shipped, and the fee
charged by the third-party gatherer, processor or transporter. Capacity on
these gathering systems and pipeline s is occasionally limited and at times
unavailable because of repairs or improvements, or as a result of priority
transportation agreements with other gas shippers. While our ability to market
our natural gas hasn't been delayed, if transportation space is restricted or is
unavailable, our cash flow from the affected properties could be adversely
affected. In certain instances, we enter into firm transportation agreements to
provide for pipeline capacity to flow and sell a portion of our gas volumes.
DELIVERY COMMITMENTS. A portion of our production is sold under certain
contractual arrangements that specify the delivery of a fixed and determinable
quantity. 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 December 31,
2010 we were committed to deliver the following fixed quantities of our natural
gas production:
GROSS
PIPELINE SYSTEM/ DELIVERABLE DELIVERIES
TYPE OF 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
HEDGING ACTIVITIES
We enter into hedging transactions with unaffiliated third parties for portions
of our production revenues to achieve more predictable cash flows and to reduce
our exposure to fluctuations in commodities prices. Typically, we intend to
hedge approximately 40-60% of our natural gas production on a forward 12-24
month basis.
COMPETITION
The oil and natural gas industry is intensely competitive, and we compete with
other companies, some that have greater resources. Many of these companies not
only explore for and produce oil and natural gas, but also carry on midstream
and refining operations and market petroleum and other products on a regional,
national or worldwide basis. These companies are able to pay more for
productive oil and natural gas properties and exploratory prospects or define,
evaluate, bid for and purchase a greater number of properties and prospects than
our financial or human resources permit. In addition, these companies have a
greater ability to continue exploration activities during periods of low oil and
natural gas market prices. Our larger or integrated competitors are better able
to absorb the burden of existing, and any changes to, federal, state and local
laws and regulations than we can, which could adversely affect our competitive
position. Our ability to acquire additional properties and to discover reserves
in the future will depend on our ability to evaluate and select suitable
properties and to consummate transactions in a highly competitive environment.
In addition, because we have fewer financial and human resources than many
companies in our industry, we may be at a disadvantage in bidding for
exploratory prospects and producing oil and natural gas properties.
MAJOR CUSTOMERS
We sell the majority of our gas production to pipelines. Gathering systems and
interstate and intrastate pipelines are used to consummate gas sales and
deliveries. Although a substantial portion of production is purchased by these
pipelines, we do not believe the loss of any one or several customers would have
a material adverse effect on our business as other customers or markets would be
accessible to us.
TITLE TO PROPERTIES
We have obtained title opinions on substantially all of our producing properties
and believe that we utilize methods consistent with practices customary in the
oil and natural gas industry and that our practices are adequately designed to
enable us to acquire satisfactory title to our producing properties. Prior to
completing an acquisition of producing natural gas and oil leases, we perform
title reviews on the most significant leases and, depending on the materiality
of the properties, we may obtain a title opinion or review previously obtained
title opinions.
It is expected that prior to the commencement of any drilling operations, we
will conduct thorough title examination and perform curative work for
significant defects. To the extent title opinions or other investigations
reflect title defects on those properties, we are typically responsible for
curing any title defects at our expense. We generally will not commence
drilling operations on a property until we have cured any material title defects
on such property.
SEASONAL NATURE OF BUSINESS
Generally, but not always, the demand for natural gas decreases during the
spring and fall months and increases during the summer and winter months.
Seasonal anomalies such as mild winters or cool summers sometime lessen this
fluctuation. In addition, pipelines, utilities, local distribution companies
and industrial users utilize natural gas storage facilities and purchase some of
their anticipated winter requirements during the summer. This can also lessen
seasonal demand fluctuations.
Seasonal weather conditions and lease stipulations can limit our drilling and
producing activities and other natural gas operations in certain areas of the
Rocky Mountain region. These seasonal anomalies can pose challenges for meeting
our well drilling and recompletion objectives and can increase competition for
equipment, supplies, and personnel during the spring and summer months, which
could lead to shortages and increase costs or delay our operations.
PUBLIC POLICY AND GOVERNMENT REGULATION OF OIL AND GAS INDUSTRY
REGULATION OF THE OIL AND GAS INDUSTRY. The oil and natural gas industry is
extensively regulated by numerous federal, state and local authorities and is
under constant review for amendment or expansion, frequently increasing the
regulatory burden. Pursuant to public policy changes, numerous government
agencies have issued extensive laws and regulations binding on the oil and
natural gas industry and its individual members, some of which carry substantial
penalties for failure to comply. Although the regulatory burden on the gas
industry increases our cost of doing business and, consequently, affects our
profitability, these burdens generally do not affect us any differently or to
any greater or lesser extent than they affect other companies in the industry
with similar types, quantities and locations of production.
DRILLING AND PRODUCTION REGULATION. Our operations are subject to various types
of regulation at federal, state and local levels. These types of regulation
include requiring permits for the drilling of wells, drilling bonds and reports
concerning operations. Most states, and some counties and municipalities also
regulate one or more of the following:
- the location of wells;
- the method of drilling and casing wells;
- the rates of production;
- the surface use and restoration of properties upon which wells are drilled
and other third parties;
- wildlife management and protection;
- emissions and discharge permitting;
- the plugging and abandoning of wells; and
- notice to, and consultation with, surface and other third parties
Our operations are also subject to conservation regulations, including the size
and shape of drilling and spacing units or proration units governing the pooling
of natural gas properties. Some states allow forced pooling or integration of
tracts to facilitate exploration while other states rely on voluntary pooling of
lands and leases, which may make it more difficult to develop oil and gas
properties. In some instances, forced pooling or unitization may be implemented
by third parties and may reduce our interest in the unitized properties. In
addition, state conservation laws can establish maximum rates of production from
natural gas wells, and generally prohibit the venting or flaring of natural gas
and impose requirements regarding the ratability of production. These laws and
regulations may limit the amount of natural gas we can produce from our wells or
limit the number of wells or the locations at which we can drill.
Moreover, each state generally imposes a production or severance tax with
respect to the production and sale of natural gas within its jurisdiction.
Federal, state and local laws and regulations affect our business, including
those relating to protection of the environment, public health, and worker
safety. Substantial liabilities, including civil and criminal penalties may
result from the technical requirements of these laws and regulations. In
addition, certain laws impose strict liability for environmental remediation and
other costs. Changes in any of these laws and regulations could have a material
adverse effect on our business. In light of the many uncertainties with respect
to future laws and regulations, we cannot predict the overall effect of such
laws and regulations on our future operations. Nevertheless, the trend in
environmental regulation is to place more restrictions and controls on
activities that may affect the environment, and future expenditures for
environmental compliance or remediation may be substantially more than we
expect.
ENVIRONMENTAL MATTERS AND REGULATION
ENVIRONMENT. Our operations are subject to stringent federal, state and local
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection. Our operations are subject to
the same environmental laws and regulations as other companies in the oil and
gas exploration and production industry. These laws and regulations:
- require the acquisition of various permits before drilling commences;
- require the installation of expensive pollution control equipment;
- restrict the types, quantities and concentration of various substances
that can be released into the environment in connection with drilling and
production activities;
- limit or prohibit drilling activities on lands lying within
environmentally sensitive areas, wilderness, wetlands and other protected areas;
- require measures to prevent pollution from former operations, such as pit
closure and plugging of abandoned wells;
- impose substantial liabilities for pollution resulting from our
operations;
- with respect to operations affecting federal lands or leases, require time
consuming environmental analysis with uncertain outcomes; and
- exposure to litigation by environmental and other special interest groups.
These laws, rules and regulations may also restrict the rate of oil and natural
gas production below the rate that would otherwise be possible. The regulatory
burden on the oil and gas industry increases the cost and timing of doing
business and consequently affects profitability. Additionally, Congress and
federal and state agencies frequently revise the environmental laws and
regulations, and any changes that result in delay or more stringent and costly
permitting, waste handling, disposal and clean-up requirements for the oil and
gas industry could have a significant impact on our operating costs.
We believe that we substantially are in compliance with and have complied, with
all applicable environmental laws and regulations. We have made and will
continue to make expenditures in our efforts to comply with all environmental
regulations and requirements. We consider these a normal, recurring cost of our
ongoing operations and not an extraordinary cost of compliance with governmental
regulations. We believe that our continued compliance with existing
requirements have been accounted for and will not have a material adverse impact
on our financial condition and results of operations. However, we cannot
predict the passage of or quantify the potential
impact of any more stringent future laws and regulations at this time. For the
year ended December 31, 2010, we did not incur any material capital expenditures
for remediation or retrofit of pollution control equipment at any of our
facilities.
The environmental laws and regulations that could have a material impact on the
oil and natural gas exploration and production industry and our business are as
follows:
NATURAL GAS SALES AND TRANSPORTATION. Historically, federal legislation and
regulatory controls have affected the price of the natural gas we produce and
the manner in which we market our production. The Federal Energy Regulatory
Commission, or FERC, has jurisdiction over the transportation and sale or resale
of natural gas in interstate commerce by natural gas companies under the Natural
Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various
federal laws have been enacted that have resulted in the complete removal of all
price and non-price controls for sales of domestic natural gas sold in "first
sales," which include all of our sales of our own production.
FERC also regulates interstate natural gas transportation rates and service
conditions, which affects the marketing of natural gas that we produce, as well
as the revenues we receive for sales of our natural gas. Commencing in 1985,
FERC promulgated a series of orders, regulations and rule makings that
significantly fostered competition in the business of transporting and marketing
gas. Today, interstate pipeline companies are required to provide
nondiscriminatory transportation services to producers, marketers and other
shippers, regardless of whether such shippers are affiliated with an interstate
pipeline company. FERC's initiatives have led to the development of a
competitive, unregulated, open access market for gas purchases and sales that
permits all purchasers of gas to buy gas directly from third-party sellers other
than pipelines. However, the natural gas industry historically has been very
heavily regulated; therefore, we cannot guarantee that the less stringent
regulatory approach recently pursued by FERC and Congress will continue
indefinitely into the future, nor can we determine what effect, if any, future
regulatory changes might have on our natural gas-related activities.
Under FERC's current regulatory regime, transmission services must be provided
on an open-access, non-discriminatory basis at cost-based rates or at
market-based rates if the transportation market at issue is sufficiently
competitive. Gathering services, which occurs upstream of jurisdictional
transmission services, is regulated by state agencies. Although its policy is
still in flux, FERC recently has reclassified certain jurisdictional
transmission facilities as non-jurisdictional gathering facilities, which has
the tendency to increase our costs of transporting gas to point-of-sale
locations.
NATIONAL ENVIRONMENTAL POLICY ACT. Natural gas exploration and production
activities on federal lands are subject to the National Environmental Policy
Act, or NEPA. NEPA requires federal agencies, including the Departments of
Interior and Agriculture, to evaluate major agency actions having the potential
to significantly impact the environment. In the course of such evaluations, an
agency will have an environmental assessment prepared that assesses the
potential direct, indirect and cumulative impacts of a proposed project. This
process has the potential to delay the development of oil and natural gas
projects. Authorizations under NEPA also are subject to protest, appeal or
litigation, which can delay or halt projects.
WATER DISCHARGES. The Federal Water Pollution Control Act, also known as the
Clean Water Act, and analogous state laws impose restrictions and strict
controls regarding the discharge of pollutants, including produced waters and
other gas wastes, into waters of the United States. The discharge of pollutants
into regulated waters is prohibited, except in accordance with the terms of a
permit issued by the EPA or the state. We maintain all required discharge
permits necessary to conduct our operations, and we believe we are in
substantial compliance with the terms thereof. Obtaining permits has the
potential to delay the development of natural gas projects. These same
regulatory programs also limit the total volume of water that can be discharged,
hence limiting the rate of development.
AIR EMISSIONS. The Federal Clean Air Act, and associated state laws and
regulations, regulate emissions of various air pollutants through the issuance
of permits and the imposition of other requirements. In addition, the EPA has
developed, and continues to develop, stringent regulations governing emissions
of toxic air pollutants at specified sources. The EPA has recently deemed
carbon dioxide ("CO2") to be a public danger which presumably will lead to
regulation in a manner similar to other pollutants. The EPA now requires
reporting of greenhouse gases, CO2 and methane, from operations. We believe
that we are in compliance with all air emissions regulations and that we hold
all necessary and valid construction and operating permits for our operations.
Obtaining permits has the potential to delay the development of natural gas
projects.
CLIMATE CHANGE
In response to findings that emissions of carbon dioxide, methane and other GHGs
present an endangerment to public health and the environment because emissions
of such gases are contributing to warming of the earth's atmosphere and other
climatic changes, the EPA had adopted regulations under existing provisions of
the federal Clean Air Act that would require a reduction in emissions of GHGs,
from motor vehicles and, also, could trigger permit review for GHG emissions
from certain stationary sources, commencing when the motor vehicle standards
took effect on January 2, 2011.
The EPA published its final rule to address the permitting of GHG emissions from
stationary sources under the PSD and Title V permitting programs. This rule
"tailors" these permitting programs to apply to certain stationary sources of
GHG emissions in a multi-step process, with the largest sources first subject to
permitting. It is widely expected that facilities required to obtain PSD
permits for their GHG emissions also will be required to reduce those emissions
according to "best available control technology" standards for GHG that have yet
to be developed. With regards to the monitoring and reporting of GHGs, on
November 30, 2010, the EPA published a final rule expanding its existing GHG
emissions reporting rule published in October 2009 to include onshore oil and
natural gas production activities, which may include certain of our operations.
In addition, both houses of Congress have actively considered legislation to
reduce emissions of GHGs, and almost one-half of the states have already taken
legal measures to reduce emissions of GHGs, primarily through the planned
development of GHG emission inventories and/or regional GHG cap and trade
programs. The adoption and implementation of any legislation or regulations
imposing reporting obligations on, or limiting emissions of GHGs from, our
equipment and operations could require us to incur costs to reduce emissions of
GHGs associated with our operations or could adversely affect demand for the oil
and natural gas we produce. Finally, it should be noted that some scientists
have concluded that increasing concentrations of GHGs in the Earth's atmosphere
may produce climate changes that have significant physical effects, such as
increased frequency and severity of storms, floods and other climatic events; if
any such effects were to occur, they could have an adverse effect on our
exploration and production operations.
ENDANGERED SPECIES, WETLANDS AND DAMAGES TO NATURAL RESOURCES
Various state and federal statutes prohibit certain actions that adversely
affect endangered or threatened species and their habitat, migratory birds,
wetlands, and natural resources. These statutes include the Endangered Species
Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Were taking
of or harm to species or damages to wetlands, habitat, or natural resources
occur or may occur, government entities or at times private parties may act to
prevent oil and gas exploration or production or seek damages to species,
habitat, or natural resources resulting from filling or construction or releases
of oil, wastes, hazardous substances or other regulated materials.
OSHA AND OTHER LAWS AND REGULATIONS
We are subject to the requirements of the federal Occupational Safety and Health
Act ("OSHA") and comparable state statutes. The OSHA hazard communication
standard, the Emergency Planning and Community Right to Know Act and similar
state statutes require that we organize and/or disclose information about
hazardous materials stored, used or produced in our operations.
PRIVATE LAWSUITS
In addition to claims arising under state and federal statutes, where a release
or spill of hazardous substances, oil and gas or oil and gas wastes have
occurred, private parties or landowners may bring lawsuits against the Company
and could possibly delay the development of natural gas projects.
OFFICES
As of April 15, 2011, the Company is finishing 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 remained in the office space on a month to month lease while terms
for a new lease are being negotiated. We believe that our facilities are
adequate for our current operations.
INTELLECTUAL PROPERTY
The Company gained access to the ARID equipment and its proprietary usage
through its Agreement with Big Cat Energy. The tool and its technology allows
the Company to inject water from the production formation into alternate
formations thus dewatering the production zone and not incurring undesirable
excess water at the surface and related pumping costs. This allows the Company
to access properties which may have been previously undevelopable due to water
drainage issues or undevelopable due to high pumping and disposal costs. The
Company views this technology as an important economic and strategic advantage.
The Company does not otherwise hold patents on any of its processes.
EMPLOYEES
As of March 31, 2011, we had a total of four officers and we had 53 full time
equivalent employees located in Gillette, WY. We also contract for the services
of independent consultants involved in land, regulatory, accounting, financial
and other disciplines as needed. None of our employees are represented by labor
unions or covered by any collective bargaining agreement. We believe that our
relations with our employees are good.
WEBSITE AND AVAILABLE INFORMATION
We make available copies of our Annual Report, Annual Report on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to
those, and other reports filed with the Securities and Exchange Commission
("SEC") under "Investor Relations" on our website, www.highplainsgas.com, as
---------------------
soon as reasonably practicable after they are filed. Our website's content is
not intended to be incorporated by reference into this report or any other
report we file with the SEC. You may request a paper copy of materials we file
with the SEC by calling us at (307) 686-5030 or sending a request by mail to our
corporate secretary at our principal office at 3601 Southern Drive, Gillette, WY
82718. You may read and copy materials we file with the SEC on the SEC's
website at www.sec.gov, or at the SEC's Public Reference Room at 100 F Street,
-----------
NE, Washington, DC 20549. You may obtain information on the operation of the
Public Reference Room by calling (800) 732-0330.
FISCAL YEAR
On February 14, 2011, concurrent with the reverse merger, we changed our fiscal
year end to December 31 from what had previously been March 31. Accordingly,
our first, second, third and fourth quarters now end March 31, June 30,
September 30 and December 31, respectively.
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this
document, which are commonly used in the oil and gas industry:
BASIN-CENTERED GAS. A regional, abnormally pressured, gas-saturated accumulation
in low-permeability reservoirs lacking a down-dip water contact.
BCF. Billion cubic feet of natural gas.
BCFE. Billion cubic feet equivalent, determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids.
BTU OR BRITISH THERMAL UNIT. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
COALBED METHANE OR CBM. Natural gas formed as a byproduct of the coal formation
process, which is trapped in coal seams and can be produced into a pipeline.
COMPLETION. Installation of permanent equipment for production of oil and gas,
or, in the case of a dry well, to reporting to the appropriate authority that
the well has been abandoned.
DESORB. A physical process whereby gas molecules are liberated from a host rock,
such as a shale or coal reservoir, when the formation pressure is reduced.
DEVELOPED ACREAGE. The number of acres that are allocated or assignable to
productive wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of a natural gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
DRY HOLE OR DRY WELL. An exploratory, development, or extension well that proves
to be incapable of producing either oil or gas in sufficient quantities to
justify completion as an oil or gas well.
ENVIRONMENTAL ASSESSMENT OR EA. A study that can be required pursuant to federal
law prior to drilling a well.
ENVIRONMENTAL IMPACT STATEMENT OR EIS. A more detailed study that can be
required pursuant to federal law of the potential direct, indirect and
cumulative impacts of a project that may be made available for public review and
comment.
EXPLORATORY WELL. A well drilled to find a new field or to find a new reservoir
in a field previously found to be productive of oil or gas in another reservoir.
FIELD. An area consisting of either a single reservoir or multiple reservoirs,
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be, in
which a working interest is owned.
IDENTIFIED DRILLING LOCATIONS. Total gross locations specifically identified and
scheduled by management as an estimation of our multi-year drilling activities
on existing acreage. Our actual drilling activities may change depending on the
availability of capital, regulatory approvals, seasonal restrictions, natural
gas and oil prices, costs, drilling results and other factors.
MCF. Thousand cubic feet of natural gas.
MCF/D. Mcf per day.
MMBTU. Million British Thermal Units.
MMCF. Million cubic feet of natural gas.
MMCF/D. MMcf per day.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned in
gross acres or gross wells, as the case may be.
NET REVENUE INTEREST. An owner's interest in the revenues of a well after
deducting proceeds allocated to royalty and overriding interests.
PLUGGING AND ABANDONMENT. Refers to the sealing off of fluids in the strata
penetrated by a well so that the fluids from one stratum will not escape into
another or to the surface. Regulations of all states require plugging of
abandoned wells.
PRODUCTIVE WELL. An exploratory, development, or extension well that is not a
dry well.
PROSPECT. A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the
discovery of commercial hydrocarbons.
PROVED DEVELOPED RESERVES OR PDP. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
PROVED RESERVES. The quantities of oil, natural gas and natural gas liquids,
which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible-from a given date forward,
from know reservoirs, and under existing economic conditions, operating methods,
and government regulations.
PROVED UNDEVELOPED RESERVES OR PUD. Reserves of any category that are expected
to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion.
RECOMPLETION. The process of re-entering an existing wellbore that is either
producing or not producing and completing new reservoirs in an attempt to
establish or increase existing production.
RECORD OF DECISION OR ROD. A document that authorizes or denies the activity
analyzed by an Environmental Impact Statement and provides the basis for this
decision.
RESOURCE MANAGEMENT PLAN OR RMP. A document that describes the Bureau of Land
Management's intended uses of lands that are under its jurisdiction
RESERVOIR. A porous and permeable underground formation containing a natural
accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is separate from other reservoirs.
STRATIGRAPHIC PLAY. An oil or natural gas formation contained within an area
created by permeability and porosity changes characteristic of the alternating
rock layer that result from the sedimentation process.
STRUCTURAL PLAY. An accumulation of oil and gas in rock strata that has been
folded or faulted.
TCF. Trillion cubic feet (of gas)
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of natural gas and oil regardless of whether such acreage contains proved
reserves.
WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production and requires the owner to pay a share of the costs of
drilling and production operations.
ITEM 1A. RISK FACTORS
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Our business involves a high degree of risk. If any of the following risks, or
any risk described elsewhere in this Form 10-K, actually occurs, our business,
financial condition or results of operations could suffer. The risks described
below are not the only ones facing us. Additional risks not presently known to
us or that we currently consider immaterial also may adversely affect our
Company.
RISK FACTORS CONCERNING THE COMPANY'S BUSINESS AND OPERATIONS
NATURAL GAS PRICES ARE VOLATILE AND A DECLINE IN NATURAL GAS PRICES CAN
SIGNIFICANTLY AFFECT OUR FINANCIAL RESULTS AND IMPEDE OUR GROWTH.
Historically natural gas prices have been volatile and will likely continue to
be volatile in the future. U.S. natural gas prices in particular are
significantly influenced by weather and many other factors. Any significant or
extended decline in commodity prices would impact the Company's future financial
condition, revenue, operating result, cash flow, return on invested capital, and
rate of growth. The Company cannot predict the future price of natural gas
because of factors beyond its control, including but not limited to:
- changes in domestic and foreign supply of natural gas;
- changes in local, regional, national and global demand for natural gas;
- regional price differences resulting from available pipeline
transportation capacity or local demand;
- the level of imports of, and the price of, foreign natural gas;
- domestic and global economic conditions;
- domestic political developments;
- weather conditions;
- domestic and foreign government regulations and taxes;
- technological advances affecting energy consumption and energy supply;
- political instability or armed conflict in natural gas producing regions;
- conservation efforts;
- the price, availability and acceptance of other fuel sources and
alternative fuels;
- storage levels of natural gas;
- the quality of gas produced; and
- the development and supply of more competitive natural gas sources.
THE COMPANY MAY NOT BE ABLE TO ECONOMICALLY FIND AND DEVELOP NEW ECONOMIC
RESERVES.
The Company's profitability depends not only on prevailing prices for natural
gas, but also its ability to find, develop and acquire gas reserves that are
economically recoverable. Producing natural gas reservoirs are generally
characterized by declining production rates that vary depending on reservoir
characteristics. Because of the high-rate production decline profile of several
of the Company's producing areas, substantial capital expenditures are required
to find, develop and acquire gas reserves to replace those depleted by
production.
GAS RESERVE ESTIMATES ARE IMPRECISE AND SUBJECT TO REVISION.
The Company proved natural gas reserve estimates are prepared annually by
independent reservoir-engineering consultants. Although the Company utilizes
reputable and reliable experts, gas reserve estimates are subject to numerous
uncertainties inherent in estimating quantities of proved reserves, projecting
future rates of production and timing of development expenditures. The accuracy
of these estimates depends on the quality of available data and on engineering
and geological interpretation and judgment. Reserve estimates are imprecise and
will change as additional information becomes available. Estimates of
economically recoverable reserves and future net cash flows prepared by
different engineers, or by the same engineers at different times, may vary
significantly. Results of subsequent drilling, testing and production may cause
either upward or downward revisions of previous estimates. In addition, the
estimation process also involves economic assumptions relating to commodity
prices, production costs, severance and other taxes, capital expenditures and
remediation costs. Actual results most likely will vary from the estimates.
Any significant variance from these assumptions could affect the recoverable
quantities of reserves attributable to any particular properties, the
classifications of reserves, the estimated future net cash flows from proved
reserves and the present value of those reserves.
SHORTAGES OF OILFIELD EQUIPMENT, SERVICES AND QUALIFIED PERSONNEL COULD IMPACT
RESULTS OF OPERATIONS.
The demand for qualified and experienced field personnel to drill wells and
conduct field operations, geologists, geophysicists, engineers and other
professionals in the oil and gas industry can fluctuate significantly, often in
correlation with natural gas and oil prices, causing periodic shortages. There
have also been regional shortages of drilling rigs and other equipment, as
demand for specialized rigs and equipment has increased along with the number of
wells being drilled. These factors also cause increases in costs for equipment,
services and personnel. These cost increases could impact profit margin, cash
flow and operating results or restrict the ability to drill wells and conduct
operations, especially during periods of lower natural gas and oil prices.
OPERATIONS INVOLVE NUMEROUS RISKS THAT MIGHT RESULT IN ACCIDENTS AND OTHER
OPERATING RISKS AND COSTS.
Drilling is a high-risk activity. Operating risks include: fire, explosions and
blow-outs; unexpected drilling conditions such as abnormally pressured
formations; abandonment costs; pipe, cement or casing failures; environmental
accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic
gases, brine or well fluids (including groundwater contamination). The Company
could incur substantial losses as a result of injury or loss of life; pollution
or other environmental damage; damage to or destruction of property and
equipment; regulatory investigation; fines or curtailment of operations; or
attorney's fees and other expenses incurred in the prosecution or defense of
litigation.
There are also inherent operating risks and hazards in the Company's gas and oil
production, gas gathering, processing, transportation and distribution
operations that could cause substantial financial losses. In addition, these
risks could result in loss of human life, significant damage to property,
environmental pollution, impairment of operations and substantial losses. The
location of pipelines near populated areas, including residential areas,
commercial business centers and industrial sites could increase the level of
damages resulting from these risks. Certain segments of the Company's pipelines
run through such areas. In spite of the Company's precautions, an event could
cause considerable harm to people or property, and could have a material adverse
effect on the financial position and results of operations, particularly if the
event is not fully covered by insurance.
As is customary in the natural gas industry, the Company maintains insurance
against some, but not all, of these potential risks and losses. The Company
cannot assure that insurance will continue to be available on acceptable terms
or will be adequate to cover these losses or liabilities. Losses and
liabilities arising from uninsured or underinsured events could have a material
adverse effect on the Company's financial condition and operations.
DISRUPTION OF, CAPACITY CONSTRAINTS IN, OR PROXIMITY TO PIPELINE SYSTEMS COULD
IMPACT RESULTS OF OPERATION.
The Company transports gas to market by utilizing pipelines principally owned by
third parties ,and to a limited degree, the Company. If pipelines do not exist
near producing wells, if pipeline capacity is limited or if pipeline capacity is
unexpectedly disrupted, gas sales could be reduced or shut in, reducing
profitability.
THE COMPANY IS SUBJECT TO COMPLEX REGULATIONS ON MANY LEVELS.
The Company is subject to federal, state and local environmental, health and
safety laws and regulations. Environmental laws and regulations are complex,
change frequently and tend to become more onerous over time. In addition to the
costs of compliance, substantial costs may be incurred to take corrective
actions at both owned and previously-owned facilities. Accidental spills and
leaks requiring cleanup may occur in the ordinary course of business. As
standards change, the Company may incur significant costs in cases where past
operations followed practices that were considered acceptable at the time but
now require remedial work to meet current standards. Failure to comply with
these laws and regulations may result in fines, significant costs for remedial
activities, or injunctions.
The Company must comply with numerous and complex regulations federal and state
regulations governing activities on federal and state lands, notably the
National Environmental Policy Act, the Endangered Species Act, the Clean Air
Act, and the National Historic Preservation Act and similar state laws. The
United States Fish and Wildlife Service may designate critical habitat areas for
certain listed threatened or endangered species. A critical habitat designation
could result in further material restrictions to federal land use and private
land use and could delay or prohibit land access or development. The listing of
certain species, such as the sage grouse, as threatened and endangered, could
have a material impact on the Company's operations in areas where such species
are found. The Clean Water Act and similar state laws regulate discharges of
storm water, wastewater, oil, and other pollutants to surface water bodies, such
as lakes, rivers, wetlands, and streams. Failure to obtain permits for such
discharges could result in civil and criminal penalties, orders to cease such
discharges, and other costs and damages. These laws also require the
preparation and implementation of Spill Prevention, Control, and Countermeasure
Plans in connection with on-site storage of significant quantities of oil.
Federal and state agencies frequently impose conditions on the Company's
activities. These restrictions have become more stringent over time and can
limit or prevent exploration and production on the Company's leaseholds.
Certain environmental groups oppose drilling on some federal and state leases.
These groups sometimes sue federal and state agencies for alleged procedural
violations in an attempt to stop, limit or delay natural gas development on
public lands.
Regulatory authorities, including but not limited to the Securities and Exchange
Commission, exercise considerable discretion in the timing and scope of permit
issuance and other needed regulatory approvals. Requirements imposed by these
authorities may be costly and time consuming and may result in delays in the
commencement or continuation of the Company's funding and exploration and
production and midstream field services operations. Further, the public may
comment on and otherwise engage in the permitting process, including through
intervention in the courts. Accordingly, needed permits may not be issued, or
if issued, may not be issued in a timely fashion, or may involve requirements
that restrict the Company's ability to conduct its operations or to do so
profitably.
THE COMPANY MAY BE EXPOSED TO CERTAIN REGULATORY AND FINANCIAL RISKS RELATED TO
CLIMATE CHANGE.
Federal and state courts and administrative agencies are considering the scope
and scale of climate-change regulation under various laws pertaining to the
environment, energy use and development, and greenhouse gas emissions. The
Company's ability to access and develop new natural gas reserves may be
restricted by climate-change regulation. There are bills pending in Congress
that would regulate greenhouse gas emissions through a cap-and-trade system
under which emitters would be required to buy allowances for offsets of
emissions of greenhouse gases. In addition, several of the states in which the
Company operates or may operate are considering various greenhouse gas
registration and reduction programs. Carbon dioxide regulation could increase
the price of natural gas, restrict access to or the use of natural gas, and/or
reduce natural gas demand. Federal, state and local governments may also pass
laws mandating the use of alternative energy sources, such as wind power and
solar energy, which may reduce demand for natural gas. While future
climate-change regulation is likely, it is too early to predict how this
regulation will affect the Company's business, operations or financial results.
It is uncertain whether the Company's operations and properties are exposed to
possible physical risks, such as severe weather patterns, due to climate change
as a result of man-made greenhouse gases. However, management does not believe
such physical risks are reasonably likely to have a material effect on the
company's financial condition or results of operations.
The Company may be unable to properly correct problems with "sour gas" that the
Company encounters in the Company's wells.
Western Gas Resources ("WGR") previously owned a portion the Dry Fork lease.
Upon drilling, WGR discovered a trace amount of hydrogen sulfide (H2S). Methane
containing H2S is considered sour, and without treatment, is unmarketable. The
Company owns certain treatment capability which the Company believes is
sufficient to treat the gas produced by Dry Fork. The Company plans to expand
the use of their gas treatment technology into additional production
opportunities and leases with predictable sour gas. Nevertheless, the Company
may not be able to properly treat this sour gas from the Dry Fork lease or any
other, which would negatively impact the Company profitability and future plans
for this area.
THE RECENT U.S. AND GLOBAL ECONOMIC RECESSION COULD HAVE A MATERIAL ADVERSE
EFFECT ON THE COMPANY'S BUSINESS AND OPERATIONS.
Any or all of the following may occur as a result if the recent crisis in the
global financial and securities markets returns:
- The Company may be unable to obtain additional debt or equity financing,
which would require the Company to limit the Company's capital expenditures and
other spending. This would lead to lower growth in the Company's production and
reserves than if the Company were able to spend more than the Company's cash
flow. Financing costs may significantly increase as lenders may be reluctant to
lend without receiving higher fees and spreads; and
- The economic slowdown has led and could continue to lead to lower demand
for oil and natural gas by individuals and industries, which in turn has may
result in lower prices for the oil and natural gas sold by the Company, lower
revenues and possibly losses.
THE COMPANY'S IDENTIFIED DRILLING LOCATION INVENTORIES ARE SCHEDULED OUT OVER
SEVERAL YEARS, MAKING THEM SUSCEPTIBLE TO UNCERTAINTIES THAT COULD MATERIALLY
ALTER THE OCCURRENCE OR TIMING OF THEIR DRILLING.
The Company's management has specifically identified and scheduled drilling
locations as an estimation of the Company's future multi-year drilling
activities on the Company's existing acreage. These identified drilling
locations represent a significant part of the Company's growth strategy. The
Company's ability to drill and develop these locations depends on a number of
uncertainties, including the availability of capital, seasonal conditions,
regulatory approvals, natural gas and oil prices, costs and drilling results.
Because of these uncertainties, the Company does not
know if the numerous potential drilling locations the Company has identified
will ever be drilled or if the Company will be able to produce natural gas or
oil from these or any other potential drilling locations. As such, the Company's
actual drilling activities may materially differ from those presently
identified, which could adversely affect the Company's business.
ALL OF THE COMPANY'S PRODUCING PROPERTIES ARE LOCATED IN THE BASIN, MAKING THE
COMPANY VULNERABLE TO RISKS ASSOCIATED WITH OPERATING IN ONE MAJOR GEOGRAPHIC
AREA.
The Company's operations have been focused on the Basin, which means the
Company's current producing properties and new drilling opportunities are
geographically concentrated in that area. Because the Company's operations are
not as diversified geographically as many of the Company's competitors, the
success of the Company's operations and the Company's profitability may be
disproportionately exposed to the effect of any regional events, including
fluctuations in prices of natural gas and oil produced from the wells in the
region, natural disasters, restrictive governmental regulations, transportation
capacity constraints, weather, curtailment of production or interruption of
transportation, and any resulting delays or interruptions of production from
existing or planned new wells.
SEASONAL WEATHER CONDITIONS AND LEASE STIPULATIONS ADVERSELY AFFECT THE
COMPANY'S ABILITY TO CONDUCT DRILLING ACTIVITIES IN SOME OF THE AREAS WHERE THE
COMPANY OPERATES.
Oil and natural gas operations in the Basin are adversely affected by seasonal
weather conditions and lease stipulations designed to protect various wildlife.
In certain areas on federal lands, drilling and other oil and natural gas
activities can only be conducted during limited times of the year. This limits
the Company's ability to operate in those areas and can intensify competition
during those times for drilling rigs, oil field equipment, services, supplies
and qualified personnel, which may lead to periodic shortages. These constraints
and the resulting shortages or high costs could delay the Company's operations
and materially increase the Company's operating and capital costs.
CERTAIN OF OUR LEASES IN THE POWDER RIVER BASIN ARE IN AREAS THAT MAY HAVE BEEN
PARTIALLY DEPLETED OR DRAINED BY OFFSET WELLS OR IMPACTED BY NEARBY COAL MINING
ACTIVITIES.
In the Powder River Basin, nearly all of our operations are in coalbed methane
plays, and our key project areas are located in areas that have been the most
active drilling areas in the Rocky Mountain region. As a result, many of our
leases are in areas that may have already been partially depleted or drained by
earlier offset drilling. This may inhibit our ability to find economically
recoverable quantities of natural gas in these areas.
PROPERTIES THAT THE COMPANY BUYS MAY NOT PRODUCE AS PROJECTED AND THE COMPANY
MAY BE UNABLE TO DETERMINE RESERVE POTENTIAL, IDENTIFY LIABILITIES ASSOCIATED
WITH THE PROPERTIES OR OBTAIN PROTECTION FROM SELLERS AGAINST THEM.
One of the Company's growth strategies is to capitalize on opportunistic
acquisitions of oil and natural gas reserves. However, the Company's reviews of
acquired properties are inherently incomplete, because it generally is not
feasible to review in depth every individual property involved in each
acquisition. Ordinarily, the Company will focus our review efforts on the higher
value properties and will sample the remaining properties for reserve potential.
However, even a detailed review of records and properties may not necessarily
reveal existing or potential problems, nor will it permit a buyer to become
sufficiently familiar with the properties to assess fully their deficiencies and
potential. Inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily
observable even when an inspection is undertaken. Even when problems are
identified, the Company often assumes certain environmental and other risks and
liabilities in connection with acquired properties.
COMPETITION IN THE NATURAL GAS INDUSTRY IS INTENSE, WHICH MAY ADVERSELY AFFECT
THE COMPANY'S ABILITY TO SUCCEED.
The natural gas industry is intensely competitive, and the Company competes with
other companies that have greater resources. Many of these companies not only
explore for and produce oil and natural gas, but also carry on refining
operations and market petroleum and other products on a regional, national or
worldwide basis. These companies may be able to pay more for productive oil and
natural gas properties and exploratory prospects or define, evaluate, bid for
and purchase a greater number of properties and prospects than the Company's
financial or human resources permit. In addition, these companies may have a
greater ability to continue exploration activities during periods of low oil and
natural gas market prices. The Company's larger competitors may be able to
absorb the burden of present and future federal, state, local and other laws and
regulations more easily than the Company can, which would adversely affect the
Company's competitive position. The Company's ability to acquire additional
properties and to discover reserves in the future will be dependent upon the
Company's ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. In addition, because the
Company has fewer financial and human resources than many companies in the
Company's industry, the Company may be at a disadvantage in bidding for
exploratory prospects and producing oil and natural gas properties.
POSSIBLE ADDITIONAL REGULATION RELATED TO GLOBAL WARMING AND CLIMATE CHANGE
COULD HAVE AN ADVERSE EFFECT ON THE COMPANY'S OPERATIONS AND DEMAND FOR OIL AND
GAS.
Recent scientific studies have suggested that emissions of certain gases,
commonly referred to as "greenhouse gases" including carbon dioxide and methane,
may be contributing to warming of the Earth's atmosphere. In response to such
studies, the U.S. Congress is actively considering legislation to reduce
emissions of greenhouse gases. In addition, several states have already taken
legal measures to reduce emissions of greenhouse gases. As a result of the U.S.
Supreme Court's decision on April 2, 2007 in Massachusetts, et al. v. EPA, the
EPA also may be required to regulate greenhouse gas emissions from mobile
sources (e.g., cars and trucks) even if Congress does not adopt new legislation
specifically addressing emissions of greenhouse gases. The EPA has initiated
rulemaking pertaining to greenhouse gases. Other nations have already agreed to
regulate emissions of greenhouse gases, pursuant to the United Nations Framework
Convention on Climate Change, also known as the "Kyoto Protocol," an
international treaty pursuant to which participating countries (not including
the United States) have agreed to reduce their emissions of greenhouse gases to
below 1990 levels by 2012. Passage of state or federal climate control
legislation or other regulatory initiatives or the adoption of regulations by
the EPA and analogous state agencies that restrict emissions of greenhouse gases
in areas in which the Company conducts business could have an adverse effect on
the Company's operations and demand for oil and gas.
HEDGING PRODUCTION MAY RESULT IN LOSSES OR A REDUCTION OF PROFITS.
From time to time, the Company may enter into hedging arrangements on a portion
of its natural gas and oil production to reduce its exposure to declines in the
prices of natural gas and oil. The value of these arrangements can be volatile
and can materially affect the Company's future reported financial results.
Hedging arrangements also expose the Company to risk of significant financial
loss in some circumstances including the following:
- There is a change in the expected differential between the underlying
price in the hedging agreement and actual prices received;
- Production is less than expected;
- Payments owed under derivative hedging contracts typically come due prior
to receipt of the hedged months production revenues; and
- The other party to the hedging contract defaults on its contract
obligations. In addition, these hedging arrangements can limit the benefit the
Company would receive from increases in the prices for natural gas.
Furthermore, if the Company chooses not to engage in hedging arrangements in the
future, it may be more adversely by changes in natural gas than its competitors
who engage in hedging arrangements.
RISK FACTORS CONCERNING INVESTMENT IN THE COMPANY:
THERE IS ONLY A LIMITED PUBLIC MARKET FOR SHARES OF THE COMPANY'S COMMON STOCK,
AND IF AN ACTIVE MARKET DOES NOT DEVELOP, INVESTORS MAY HAVE DIFFICULTY SELLING
THEIR SHARES AND BE SUBJECT TO PRICE VOLATILITY.
There is a limited public market for shares of the Company's common stock. The
Company cannot predict the extent to which investor interest will lead to the
development of an active trading market or how liquid that trading market might
become. If a trading market does not develop or is not sustained, it may be
difficult for investors to sell shares of the Company's common stock at a price
that is attractive. As a result, an investment in the Company's common stock
may be illiquid and investors may not be able to liquidate their investment
readily or at all when desired. In addition, the limited volume may cause
volatility in the market price of the Company's common stock.
AS A RESULT OF OUR REVERSE MERGER, HIGH PLAINS GAS, LLC BECAME A SUBSIDIARY OF A
COMPANY THAT IS SUBJECT TO THE REPORTING REQUIREMENTS OF FEDERAL SECURITIES
LAWS, WHICH IS EXPENSIVE AND DIVERTS RESOURCES FROM OTHER PROJECTS, THUS
IMPAIRING OUR ABILITY TO GROW.
As a result of the reverse merger, High Plains Gas, LLC became a subsidiary of a
public reporting company (High Plains Gas, Inc) and, accordingly, is subject to
the information and reporting requirements of the Securities Exchange Act of
1934, as amended (the "Exchange Act"). The costs of preparing and filing annual
and quarterly reports, proxy statements and other information with the SEC and
furnishing audited reports to stockholders will cause our expenses to be higher
than they would have been if we had remained privately held and did not
consummate the reverse merger.
It may be time consuming, difficult and costly for us to develop and implement
the internal controls and reporting procedures required by the Sarbanes-Oxley
Act. We may need to hire additional financial reporting, internal controls and
other finance personnel in order to develop and implement appropriate internal
controls and reporting procedures. If we are unable to comply with the internal
controls requirements of the Sarbaines-Oxley Act, then we may not be able to
obtain the independent registered public accountant certifications required by
such Act, which may preclude us from keeping our filings with the SEC current.
Non-current reporting companies are subject to various restrictions and
penalties.
MANAGEMENTS EVALUATION OF DISCLOSURE CONTROLS AND CONTROLS OVER FINANCIAL
REPORTING HAVE DISCLOSED A MATERIAL WEAKNESS IN OUR INTERNAL CONTROLS
As a result of their annual assessment, management has determined there are
material weaknesses in our internal controls in that we have not established an
audit committee and that our accounting functions lack segregation of duties and
knowledge of complex accounting matters.
PUBLIC COMPANY COMPLIANCE MAY MAKE IT MORE DIFFICULT FOR US TO ATTRACT AND
RETAIN OFFICERS AND DIRECTORS
The Sarbanes-Oxley Act and new rules subsequently implemented by the SEC have
required changes in corporate governance practices of public companies. As a
public company, we expect these new rules and regulations to increase our
compliance costs in 2011 and beyond and to make certain activities more time
consuming and costly. As a public company we also expect that these new rules
and regulations may make it more difficult and expensive for us to obtain
director and officer liability insurance in the future or we may be required to
accept reduced policy limits and coverage or incur substantially higher costs to
obtain the same or similar coverage. As a result, it may be more difficult for
us to attract and retain qualified persons to serve on our board of directors or
as executive officers.
BECAUSE WE BECAME PUBLIC BY MEANS OF A REVERSE MERGER, WE MAY NOT BE ABLE TO
ATTRACT THE ATTENTION OF MAJOR BROKERAGE FIRMS.
There are risks associated with High Plains Gas, LLC becoming public through a
"reverse merger." Securities analysts of major brokerage firms may not proved
coverage of us since there is no incentive to brokerage firms to recommend the
purchase of our common stock. No assurance can be given that brokerage firms
will, in the future, want to conduct any secondary offerings on behalf of our
post-reverse merger company.
THE COMPANY'S COMMON STOCK MAY BE DEEMED TO BE "PENNY STOCK," WHICH MAY MAKE IT
MORE DIFFICULT FOR INVESTORS TO SELL THEIR SHARES DUE TO SUITABILITY
REQUIREMENTS.
The sale price of the Company's common stock has been reported to date below
$5.00 per share. As such, the Company's common stock may be subject to
provisions of Section 15(g) and Rule 15g-9 of the Securities Exchange Act of
1934, as amended (the "Exchange Act"), commonly referred to as the "penny stock
rule." The SEC generally defines "penny stock" to be any equity security that
has a market price less than $5.00 per share, subject to exceptions with which
we may or may not comply.
Broker/dealers dealing in penny stocks are required to provide potential
investors with a document disclosing the risks of penny stocks. Moreover,
broker/dealers are required to determine whether an investment in a penny stock
is a suitable investment for a prospective investor. These requirements may
reduce the potential market for the Company's common stock by reducing the
number of potential investors, and may make it more difficult for investors in
the Company's common stock to sell shares to third parties or to otherwise
dispose of them. This could cause the stock price to decline.
FUTURE SALES BY THE COMPANY'S STOCKHOLDERS MAY ADVERSELY AFFECT THE COMPANY'S
STOCK PRICE AND THE COMPANY'S ABILITY TO RAISE FUNDS IN NEW STOCK OFFERINGS.
Sales of the Company's common stock in the public market could lower the market
price of the Company's common stock. Sales may also make it more difficult for
the Company to sell equity securities or equity-related securities in the future
at a time and price that the Company's management deems acceptable or at all.
THE COMPANY'S BOARD OF DIRECTORS MAY AUTHORIZE THE ISSUANCE OF ADDITIONAL SHARES
THAT MAY CAUSE DILUTION.
The Company's articles of incorporation permit the Company's board of directors,
without shareholder approval, to authorize the issuance of additional common
stock in connection with future equity offerings, acquisitions of securities or
other assets of companies. The shareholders and directors of Company in fact
have agreed to amend the Company's articles of incorporation to provide for a
total of 350,000,000 shares of authorized common stock.
The issuance of additional shares of the Company's common stock could be
dilutive to shareholders if they do not invest in future offerings. Moreover, to
the extent that the Company issues options or warrants to purchase the Company's
common stock in the future and those options or warrants are exercised or the
Company issues restricted stock, shareholders may experience further dilution.
Holders of shares of the Company's common stock have no preemptive rights that
entitle them to purchase their pro rata share of any offering of shares of any
class or series and investors in this offering may not be permitted to invest in
future issuances of the Company's common stock.
THE COMPANY HAS AUTHORIZED BUT UNISSUED PREFERRED STOCK, WHICH COULD AFFECT
RIGHTS OF HOLDERS OF THE COMPANY'S COMMON STOCK.
The Company's articles of incorporation authorize the issuance of preferred
stock with designations, rights and preferences determined from time to time by
its board of directors. Accordingly, the Company's board of directors is
empowered, without shareholder approval, to issue preferred stock with
dividends, liquidation, conversion, voting or
other rights that could adversely affect the voting power or other rights of the
holders of the Company's common stock. In addition, the preferred stock could
be issued as a method of discouraging a takeover attempt.
THE COMPANY DOES NOT EXPECT TO PAY DIVIDENDS ON THE COMPANY'S COMMON STOCK.
The Company does not expect to pay any cash dividends with respect to the
Company's common stock in the foreseeable future. The Company intends to retain
any earnings for use in the Company's business.
RISKS RELATED TO OUR NOTES, CONVERTIBLE NOTES AND CREDIT FACILITY
WE MAY NOT BE ABLE TO GENERATE ENOUGH CASH FLOW TO MEET OUR DEBT OBLIGATIONS,
INCLUDING OUR OBLIGATIONS AND COMMITMENTS UNDER OUR NOTES AND OUR REVOLVING
CREDIT FACILITY.
We expect our earnings and cash flow to vary significantly from year to year due
to the cyclical nature of our industry. As a result, the amount of debt that we
can manage in some periods may not be appropriate for us in other periods. In
addition, our future cash flow may be insufficient to meet our debt obligations
and commitments. Any insufficiency could negatively impact our business. A
range of economic, competitive, business, and industry factors will affect our
future financial performance, and, as a result, our ability to generate cash
flow from operations and to repay our debt, including the notes. Many of these
factors, such as oil and gas prices, economic and financial conditions in our
industry and the global economy or competitive initiatives of our competitors,
are beyond our control.
As of December 31, 2010, the total outstanding principal amount of our long term
indebtedness was approximately $6 million, and we had approximately $69 million
in additional borrowing capacity under our Credit Facility, which, if borrowed,
would be secured debt effectively senior to the Notes and Convertible Notes to
the extent of the value of the collateral securing that indebtedness. The
borrowing base is dependent on our proved reserves and hedge positions.
If we do not generate enough cash flow from operations to satisfy our debt
obligations, we may have to undertake alternative financing plans, such as:
- refinancing or restructuring our debt;
- selling assets;
- reducing or delaying capital investments; or
- seeking to raise additional capital.
However, any alternative financing plans that we undertake, if necessary, may
not allow us to meet our debt obligations. Our inability to generate sufficient
cash flow to satisfy our debt obligations, including our obligations under the
notes, or to obtain alternative financing, could materially and adversely affect
our business, financial condition, results of operations and prospects.
Our debt could have important consequences. For example, it could:
- increase our vulnerability to general adverse economic and industry
conditions;
- limit our ability to fund future capital expenditures and working capital
to engage in future acquisitions or development activities, or to otherwise
realize the value of our assets and opportunities fully because of the need to
dedicate a substantial portion of our cash flow from operations to payments of
interest and principal on our debt or to comply with any restrictive terms of
our debt;
- limit or flexibility in planning for, or reacting to, changes in our
business and the industry in which we operate;
- impair our ability to obtain additional financing in the future; and
- place us at a competitive disadvantage compared to our competitors that
have less debt.
RESTRICTIONS IN OUR EXISTING AND FUTURE DEBT AGREEMENTS COULD LIMIT OUR GROWTH
AND OUR ABILITY TO RESPOND TO CHANGING CONDITIONS.
Our Credit Facility contains a number of significant covenants in addition to
covenants restricting the incurrence of additional debt. Our Credit Facility
requires us, among other things, to maintain certain financial ratios and limit
our debt. These restrictions also limit our ability to obtain future financings
to withstand a future downturn in our business or the economy in general, or to
otherwise conduct necessary corporate activities. We may also be prevented from
taking advantage of business opportunities that arise because of the limitations
that the restrictive covenants under the indenture governing the notes and our
Credit Facility impose on us.
A breach of any covenant in our Credit Facility or the agreements and indentures
governing our other indebtedness would result in a default under that agreement
or indenture after any applicable grace periods. A default, if not waived,
could result in acceleration of the debt outstanding under the agreement and in
a default with respect to, and an acceleration of, the debt outstanding under
other debt agreements. The accelerated debt would become immediately due and
payable. Our financial statements report that we are not in compliance with the
restrictive covenants and, while the lender has not called the note, the credit
facility gives them the ability to do so.
OTHER RISKS
THE COMPANY RELIES ON KEY EXECUTIVE OFFICERS AND BOARD MEMBERS AND THEIR
KNOWLEDGE OF THE COMPANY'S BUSINESS AND TECHNICAL EXPERTISE WOULD BE DIFFICULT
TO REPLACE.
The Company is dependent on the Company's Board, executive officers and
management team. The Company does not have "key person" life insurance policies
for any of the Company's officers. The loss of the technical knowledge and
management and industry expertise of any of the Company's key personnel could
result in delays in product development, loss of customers and sales and
diversion of management resources, which could adversely affect the Company's
operating results.
IF THE COMPANY IS UNABLE TO HIRE ADDITIONAL QUALIFIED PERSONNEL, THE COMPANY'S
BUSINESS MAY BE UNABLE TO GROW.
The Company will need to hire significant numbers of additional qualified
personnel to operate the Company's operations. The Company's success will
depend to a significant degree on the quality and integrity of the Company's
work force. The Company competes for qualified individuals with numerous
companies, and the Company cannot be certain that the Company's search for
adequate numbers of qualified personnel will be successful.
THE COMPANY'S FUTURE CAPITAL NEEDS ARE UNCERTAIN.
The Company expects to incur substantial expenses for development, exploration,
testing, marketing and administrative overhead and the Company believes the
expansion of the Company's operations will require substantial additional
capital. The combined effect of the foregoing may prevent the Company from
achieving profitability for an extended period of time. If revenues do not
increase as rapidly as anticipated, or if exploration, drilling, and testing and
marketing require more funding than presently anticipated, the Company may be
required to seek additional financing.
THE COMPANY WILL TRY TO USE THE COMPANY'S STOCK TO FINANCE ACQUISITIONS.
As a key component of the Company's growth strategy, the Company intends to
acquire additional leaseholds, facilities and other assets. The Company
utilized stock as a finance vehicle for the acquisition of both the Marathon
Assets and the Huber Assets. When possible, the Company may try to use the
Company's stock as an acquisition currency in order to conserve the Company's
available cash resources for operational needs. Future acquisitions may give
rise to substantial charges for the impairment of goodwill and other intangible
assets that would materially and adversely affect the Company's reported
operating results.
Any future acquisitions will involve numerous business and financial risks,
including:
- Difficulties in integrating new operations, technologies, products and
staff;
- Diversion of management attention from other business concerns; and
- Cost and availability of acquisition financing.
The Company will need to be able to successfully integrate any businesses the
Company may acquire in the future, and the failure to do so could have a
material adverse effect on the Company's business, results of operations and
financial condition.
ACQUISITIONS BY THE COMPANY MAY HAVE UNDISCLOSED LIABILITIES AND THE COMPANY MAY
BE UNABLE TO INTEGRATE THESE BUSINESSES SUCCESSFULLY.
In connection with any acquisition made by the Company (including without
limitation the Marathon Acquisition described elsewhere in this report), there
may be liabilities that the Company fails to discover or is unable to discover,
including liabilities arising from non-compliance with environmental laws by
prior owners and for which the Company, as successor owner, may be responsible.
These liabilities could have an adverse impact on the Company's financial
condition, results of operations or liquidity. The Company often attempts to
minimize the Company's exposure to such liabilities by acquiring only specified
assets, by obtaining indemnification from each seller of the acquired companies
or by deferring payment of a portion of the purchase price as security for the
indemnification. However, the Company cannot assure you that the Company will be
successful in obtaining such indemnifications or that they will be enforceable,
collectible or sufficient in amount, scope or duration to fully offset any
undisclosed liabilities arising from the Company's acquisitions. Similarly, the
Company incurs capitalized costs associated with acquisitions, which if never
consummated would result in a charge to earnings.
Further, the Company cannot assure you that the Company will be able to
successfully integrate any acquisitions that the Company pursues or that such
acquisitions will perform as planned or prove to be beneficial to the Company's
operations and cash flow. Acquisitions involve numerous risks, including
difficulties in the assimilation of the acquired businesses, the diversion of
the Company's management's attention from other business concerns and potential
adverse effects on existing business relationships with current customers. The
consolidation of the Company's operations with the operations of acquired
companies, including the consolidation of systems, procedures, personnel and
facilities, the relocation of staff, and the achievement of anticipated cost
savings, economies of scale and other business efficiencies, presents
significant challenges to the Company's management, particularly if several
acquisitions occur at the same time. The Company's failure to successfully
integrate businesses the Company acquires could have an adverse effect on the
Company's liquidity, financial condition and results of operations.
THE COMPANY MAY INCUR MORE TAXES AND CERTAIN OF THE COMPANY'S PROJECTS MAY
BECOME UNECONOMIC IF CERTAIN FEDERAL INCOME TAX DEDUCTIONS CURRENTLY AVAILABLE
WITH RESPECT TO OIL AND GAS EXPLORATION AND DEVELOPMENT ARE ELIMINATED AS A
RESULT OF FUTURE LEGISLATION.
There are various proposals to eliminate certain key U.S. federal income tax
preferences currently available to oil and gas exploration and production
companies. These changes include (i) the repeal of the percentage depletion
allowance for oil and gas properties, (ii) the elimination of current deductions
for intangible drilling and development costs, (iii) the elimination of the
deduction for certain U.S. production activities, and (iv) an extension of the
amortization period for certain geological and geophysical expenditures.
It is unclear whether any of the foregoing changes will actually be enacted or
how soon any such changes could become effective. The passage of any legislation
as a result of the budget proposal or any other similar change in U.S. federal
income tax law could eliminate certain tax deductions that are currently
available with respect to oil and gas exploration and development. Any such
change could negatively impact the Company's financial condition and results of
operations by increasing the costs the Company incurs which would in turn make
it uneconomic to drill some prospects if commodity prices are not sufficiently
high, resulting in lower revenues and decreases in production and reserves.
ITEM 1B.UNRESOLVED STAFF COMMENTS
---------------------------------
Not applicable.
ITEM 2.PROPERTIES
-----------------
As of April 15, 2011, the Company is finishing 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 remained in the office space on a month to month lease while terms
for a new lease are being negotiated. We believe that our facilities are
adequate for our current operations.
ITEM 3.LEGAL PROCEEDINGS
------------------------
Although we are not party to any material current litigation, we may acquire
properties with or become a party to legal actions and proceedings from time to
time. We may be unable to estimate legal expenses or losses we may incur, or
damages we may recover in these actions, if any, and have not accrued potential
gains or losses in our financial statements. Expenses in connection with these
actions are recorded as they are incurred.
We believe we carry adequate liability insurance, directors' and officers'
insurance, casualty insurance, for owned or leased tangible assets, and other
insurance as needed to cover us against claims and lawsuits that occur in the
ordinary course of our business. However, an unfavorable resolution of any
substantial new matters, and/or our incurrence of legal fees and other costs to
defend or prosecute any of these actions may have a material adverse effect on
our consolidated financial position, results of operation and cash flows in a
particular period.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
------------------------------------------------------------
During the year ended December 31, 2010 there were no matters submitted to a
vote of the Company's stockholders.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
------- ------------------------------------------------------------------
AND ISSUER PURCHASES OF EQUITY SECURITIES
-----------------------------------------
MARKET FOR REGISTRANT'S COMMON EQUITY.
The Company's common stock is quoted in United States markets on the over the
counter bulletin board under the symbol "HPGS". There is no assurance that the
common stock will continue to be quoted or that any liquidity exists for the
Company's shareholders.
The market for the Company's common stock is limited, and can be volatile. The
following table sets forth the high and low closing prices relating to the
Company's common stock on a quarterly basis for the periods indicated as quoted
by the over the counter bulletin board stock market. These quotations reflect
inter-dealer prices without retail mark-up, mark-down, or commissions, and may
not reflect actual transactions. The numbers also reflect the forward 2 for 1
stock dividend effective December 15, 2010.
Quarter Ended High Bid Low Bid
March 31, 2009 $ 0.207 $ 0.042
June 30, 2009 $ 0.165 $ 0.039
September 30, 2009 $ 0.053 $ 0.010
December 31, 2009 $ 0.010 $ 0.002
March 31, 2010 $ 0.005 $ 0.002
June 30, 2010 $ 0.001 $ 0.003
September 30, 2010 $ 0.014 $ 0.001
December 31, 2010 $ 1.15 $ 0.25
March 31, 2011 $ 1.40 $ 0.99
Through April 15, 2011 $ 1.12 $ 1.02
HOLDERS. As of the date of this report, the Company had 87 shareholders of
record of certificates in physical form, which does not include shareholders
whose shares are held in street or nominee names.
As of the date of this report, the Company had 350,000,000 shares of common
stock authorized with approximately 166,523,602 shares issued and outstanding
and 20,000,000 shares of preferred stock authorized with no shares issued and
outstanding.
PENNY STOCK REGULATIONS. The Company's common stock is quoted in United States
markets by the Pink Sheets under the symbol "HPGS." The sale price of the
Company's common stock has consistently been reported below $5.00 per share. As
such, our common stock may be subject to provisions of Section 15(g) and Rule
15g-9 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"),
commonly referred to as the "penny stock rule."
Section 15(g) sets forth certain requirements for transactions in penny stocks,
and Rule 15g-9(d) incorporates the definition of "penny stock" that is found in
Rule 3a51-1 of the Exchange Act. The SEC generally defines "penny stock" to be
any equity security that has a market price less than $5.00 per share, subject
to certain exceptions. As long as the Company's common stock is deemed to be a
penny stock, trading in the shares will be subject to additional sales practice
requirements on broker-dealers who sell penny stocks to persons other than
established customers and accredited investors
DIVIDENDS. Other than a 2 for 1 forward stock dividend effectively December 15,
2010, the Company has not issued any dividends on the common stock to date, and
does not intend to issue any dividends on the common stock in the near future.
The Company currently intends to use all profits to further the growth and
development of the Company.
ITEM 6. SELECTED FINANCIAL DATA (1) (5)
DECEMBER 31, DECEMBER 31,
2010 2009
STATEMENT OF OPERATIONS SUMMARY:
Total revenues $ 2,611,969 $ 844,239
Net income (loss) (3) ($5,483,467) ($467,110)
Net income (loss) per share:
Basic ($4.72) N/A (6)
Assuming dilution N/A N/A (6)
Weighted average number of common shares
outstanding:
Basic 1,161,614 N/A (6)
Assuming dilution N/A N/A (6)
YEAR-END BALANCE SHEET SUMMARY:
-------------- --------------
Cash and cash equivalents $ 208,823 $ 45,426
Total assets 47,999,948 1,550,743
Total long-term obligations 15,972,728 350,478
Total shareholders' interest 19,596,212 (25,750)
(1) This summary should be read in conjunction with our Consolidated
Financial Statements and Notes thereto. All amounts in these notes are rounded
to thousands.
(2) The Company changed its fiscal year end from March 31 to December 31 as
a result of the reverse merger.
(3) 2010 includes $1,321,660 from oil and gas income.
(4) 2010 includes nonrecurring consulting fees of $532,187 and nonrecurring
expenses related to the reverse acquisition of $385,941. We also booked a
nonrecurring noncash expense for $3,169,313 related to issuance of discounted
shares and a nonrecurring expense of $1,495,000 related to bonuses paid out in
connection with two asset acquisitions.
(5) No cash dividends were declared or paid in any year presented.
(6) Prior to the reverse merger on October 18, 2010, High Plains Gas, LLC
the entity whose historical results are reported herein, was a Limited Liability
Company and thus no share data is available.
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
------------------------------------------------------------------------------
OF OPERATION
------------
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 Annual Report on Form 10-K, particularly in the "Cautionary
Note Regarding Forward-Looking Statements' sections and in "item 1A, Risk
Factors" 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 and 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 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, which will include investing in and profitably developing 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. Our management team
has significant experience acquiring and developing E&P assets in the Rocky
Mountains and has an extensive network of industry relationships in the region.
Through its solid foundation and experience, the Company intends to pursue
expansion plans across this 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 July 28, 2010, the Company entered into an agreement to acquire High Plains
Gas, LLC, a Wyoming limited liability company ("High Plains LLC") (the
"Reorganization Agreement). On September 13, 2010 the Company amended its
Articles of Incorporation to change its name to High Plains Gas, Inc. and
increase its authorized common stock to 250,000,000 shares. 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. Under the
Reorganization Agreement, shareholders and other parties representing what was
Northern Explorations retained 13,000,000 shares (pre-dividend) of the Company's
common stock and designees of High Plains LLC were issued 52,000,000 shares
(pre-dividend) of the Company's common stock.
The reorganization has been accounted for as a reverse merger and under the
accounting rules for a reverse merger, the historical financial statements and
results of operations of High Plains Gas, LLC became those of the Company.
As of September 30, 2010, the Company entered into agreements with Current
Energy Partners Corporation, a Delaware Corporation ("Current") and its wholly
owned subsidiary CEP M Purchase LLC ("CEP"). In accordance with the terms of the
agreements, the Company initially purchased a Convertible Note from Current for
the amount of $3,550,000 and also provided assistance with CEP's bonding
requirements. The proceeds from the Convertible Note as well as approximately
$6,000,000 in bank financing were used (described below) by Current through its
subsidiary CEP to purchase a significant resource base and land position from
Pennaco Energy, Inc. ("Pennaco"), a wholly owned subsidiary of Marathon Oil
Company. The assets consisted of Pennaco's "North & South Fairway" assets
located in the Basin. These properties encompass approximately 155,000 net
operated acres (the "Assets"). The acquisition included the operational
capacities including flow lines, transportation rights and production wells both
active and idle. The transaction did not transfer deep oil rights, but focused
upon mineral rights between the surface and depth above the base Tertiary
Paleocene Fort Union Formation generally above 2,500 feet. Under the original
agreement, the Company was appointed to perform the operating duties with
respect to the assets as specified in the underlying Purchase and Sale Agreement
executed on July 21, 2010 by and among Current, CEP and Pennaco (the "Pennaco
Agreement").
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, at $0.03 per
share for $600,000. The purchase price of $600,000 consisted of a combination
of $200,000 cash and 739,180 restricted shares of the Company valued at
$400,000. The Purchase Agreement also grants the Company warrants to purchase
an additional 10,000,000 shares of restricted common stock of Big Cat at $0.15
per share. If the Company exercised the warrants, it would own
30,000,000 shares of Big Cat's common stock or 40.6% of the Company. The
warrants have a term of five years from the effective date of the Purchase
Agreement. The number of warrants is to be adjusted in the event of a
reclassification, change, stock dividend, stock split, combination,
reorganization, merger or consolidation affecting the price or number of shares
issuable or exercisable under the warrants so as to maintain an approximately
equivalent number of shares and exercise price for the warrant holders before
and after such a transaction. Any such adjustment is to be made pursuant to
official notice from the Company in connection with the transaction. On the
closing of this transaction, Big Cat nominated Mark Hettinger, Chairman of the
Company, to Big Cat's Board of Directors.
During the fiscal quarter ended December 31, 2010, the Company entered into a
$75,000,000 credit facility with Amegy Bank of which $6,000,000 was borrowed to
finance the Marathon Acquisition.
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 December 31, 2010, the company operated 1726 producing
methane wells of which1043 methane wells were idle. The company was able to
bring 33 previously idle methane wells into production from November 19th thru
December 31st of 2010. The company expects to continue to bring methane wells
into production at a rate of roughly 30 per month throughout the next twelve
months.
The company has set a goal for the next twelve months of bringing an additional
1000 mcf/day of methane to point of sale each month. This goal is expected to
be achieved through rework of idle methane wells and well re-activation in the
fields purchased from Marathon Oil in November of 2010. The company may also
choose to drill new methane wells in order to increase production in fields in
which we have the right to do so.
In addition to day-to-day operation of the company's existing properties, the
company intends to grow both assets and revenue through acquisitions of
properties with existing production and upside potential through the development
of currently undeveloped and underdeveloped lease acreage. The company intends
to finance the acquisition of future properties through a combination of equity
financing and debt financing. The company believes that opportunities exist in
the marketplace for the acquisition of existing production with higher cost
structures relative to what the company believes is necessary for successful
operation of the properties. The company believes that because of the extended
reduction in the net price to producers for methane sold, properties with higher
cost structures are willing to sell existing production at purchase prices
favorable to High Plains Gas, and that High Plains Gas can operate these
properties at increased profit margins relative to other producers.
Though the company has no plans for instituting a drilling program at the
current time, the ownership of undeveloped acreage creates that potential that
the company may seek to begin a drilling program in the future. The purpose of
this drilling program would be to maintain or increase existing methane
production. Another purpose of this program may, at a future date, be to
develop and operate oil producing wells on acreage that the company holds, or
may hold, such rights. The extent of any drilling program for natural gas or
oil will be subject to permitting and capital available to fund such a program.
The company may choose to raise capital for a drilling program through both
equity and debt financing.
Because of our rapid growth through acquisitions, and the anticipated
development of our properties, our historical results of operations and
period-to-period comparisons of these results and certain financial data may not
be meaningful. In addition past results are not indicative of future results.
Our acquisitions and capital expenditures were financed with a combination of
funding from equity investments in our company, debt financing, our Credit
Facility and cash flow from operations.
Commodity prices, particularly in the Rocky Mountain region, are inherently
volatile and are influenced by many factors outside of our control. We plan our
activities and capital budget using what we believe to be conservative sales
price assumptions and our existing hedge position. Our strategic objective is
to hedge 40% to 60% of our
anticipated production on a forward 12-24 month basis. We focus our efforts on
increasing natural gas and oil reserves and production while controlling costs
at a level that is appropriate for long-term operations. Our future earnings
and cash flows are dependent on our ability to manage our revenues and overall
cost structure to a level that allows for profitable production.
Like all oil and gas exploration and production companies, we face the challenge
of natural production declines. As reservoir pressures are depleted, oil and
gas production from a typical well naturally decrease. Thus, an oil and gas
exploration and production company depletes part of its asset base with each
unit of oil or natural gas it produces. We attempt to overcome this natural
decline by drilling to find additional reserves and acquiring more reserves than
we produce. Our future growth will depend on our ability to continue to add
reserves in excess of production. We will maintain our focus on costs to add
reserves through drilling and acquisitions as well as the costs necessary to
produce such reserves. Our ability to add reserves through drilling is
dependent on our capital resources and can be limited by many factors, including
our ability to timely obtain drilling permits and regulatory approvals. The
permitting and approval process has been more difficult in recent years than in
the past due to more stringent rules, increased activism from environmental and
other groups, which as extended the time it takes us to receive permits, and
other necessary approvals. Because of our relatively small size and
concentrated property base, we can be disproportionately disadvantaged by delays
in obtaining or failing to obtain drilling approvals compared to companies with
larger or more dispersed property bases. As a result, we may be less able to
shift drilling activities to areas where permitting may be easier, and we have
fewer properties over which to spread the costs related to complying with these
regulations and the costs or foregone opportunities resulting from delays.
The Company obtains revenue by procuring, producing and marketing natural gas
(Methane) from the Powder River Basin (the "Basin") in Central Wyoming. The
Company's management team has significant experience acquiring and developing
E&P assets in the Rocky Mountains and has experience in cultivating industry
relationships. Through its solid foundation and experience in the region, the
Company intends to pursue expansion plans both within the Basin and across the
Rocky Mountain region.
Please note that unless otherwise indicated, the information in this report
gives effect to 1 for 1 dividend of the Common Stock effected on December 15,
2010, as well as the other historical stock dividends and splits.
RECENT DEVELOPMENTS
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 $1,500,000 in
"HPGS" common stock 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.
RESULTS OF OPERATIONS
The following table sets forth selected operating data for the periods
indicated:
YEAR ENDED DECEMBER 31, 2010 COMPARED TO YEAR ENDED DECEMBER 31, 2009
2010 2009
------------ -----------
REVENUES:
Gas and oil revenue $ 2,464,552 $ 520,620
Pipeline revenue 110,506 235,689
Other 36,911 87,930
------------ -----------
Total Revenue 2,611,969 844,239
============ -----------
COSTS AND EXPENSES
Lease operating expense and production taxes 3,230,426 613,873
General and administrative expense 3,288,816 210,454
Depreciation, depletion and amortization 1,306,617 432,051
Accretion of asset retirement obligation 65,979 2,139
------------ -----------
Total Costs and Expenses 7,891,838 1,258,517
============ -----------
OPERATING (LOSS) (5,023,905) (414,278)
============ -----------
OTHER INCOME (EXPENSE)
Other income 481,302 9,889
Gain on valuation of equity securities 1,935,234 --
Amortization of bond commitment
and financing fees (291,667) --
Commodity derivative adjustment (603,742) --
Interest (expense) (1,724,745) (62,721)
------------ -----------
Total Other Income (Expense) 203,618 (52,832)
------------ -----------
NET INCOME (LOSS) $(5,483,487) $ (467,110)
============ ===========
PRODUCTION REVENUES AND VOLUMES. Production revenues increased to $2,611,969
for the year ended December 31, 2010 from $844,239 million for the year ended
December 31, 2009 due to 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 749,461 Mcf for the year ended December 2010
from 201,831 Mcf for the year ended December 31, 2009. The increase was
primarily attributed to the Marathon Transaction.
HEDGING ACTIVITIES. As of December 31, 2010, approximately 40% of our natural
gas volumes were subject to financial hedges, which resulted in an increase in
natural gas revenues of $17,050 after settlements for all derivatives. In 2009,
the Company had no financial hedges in place. It is expected that as we
continue to increase production, we will have 40-60% of our natural gas volumes
subject to financial hedges.
COMMODITY DERIVATIVE GAIN (LOSS). The "Commodity derivative gain (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 settlement will be presented as realized gains and losses within
this same lime item.
The overall commodity derivative gain (loss) from was ($603,742) for the year
ended December 31, 2010. There were no commodity derivatives for the year ended
December 31, 2009. The loss was primarily due to the unrealized losses
resulting in the change in future natural gas contracts.
GAIN ON VALUATION OF EQUITY SECURITIES. As allowed by ASC 825-10, the Company
has elected to follow the fair value option for reprinting the securities
received from Big Cat Energy Corporation, thus the fair value adjustment of $1.9
million is reflected in 2010 operating results.
LEASE OPERATING EXPENSES. Lease operating expense increased to $3,230,426 in
2010 from $613,873 in 2009. The increase was primarily due to the Marathon
Transaction and expenditures during December 2010 to open previously shut-in
reserves.
GATHERING, TRANSPORTATION AND PROCESSING EXPENSE. Gathering, transportation and
processing expense increased to $605,009 in 2010 from $0 (a nominal amount) in
2009. The increase was primarily due to the Marathon Transaction. Although we
don't anticipate increases in our fixed demand charges, we may incur additional
costs from other pipelines in the future.
PRODUCTION TAX EXPENSE. Total production taxes increased to $43,402 in 2010
from $10,023 in 2009. The increase in production taxes is primarily related to
the Marathon Transaction. 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.
IMPAIRMENT DRY HOLE COSTS AND ABANDONMENT EXPENSES. Our impairment, dry hole
costs and abandonment expense is $0 for year ended December 31, 2010 and $0 for
year ended December 31, 2009.
We test for impairment of our properties based on estimates of proved reserves.
Proved oil and gas properties are reviewed for impairment whenever events or
circumstances indicate that the carrying amount may not be recoverable. We
estimate the future undiscounted cash flows of the affected properties to judge
the recoverability of the carrying amounts. Initially this analysis is based on
proved reserves. However, when we believe that a property contains oil and gas
reserves that do not meet the defined parameters of proved reserves, an
appropriately risk adjusted amount of these reserves may be included in the
impairment evaluation. These reserves are subject to much greater risk of
ultimate recovery.
An asset would be impaired if the undiscounted cash flows were less than its
carrying value. Impairments are measured by the amount by which the carrying
value exceeds its fair value. Impairment analysis is performed on an ongoing
basis. In addition to using estimates of oil and gas reserve volumes in
conducting impairment analysis, it is also necessary to estimate future oil and
gas prices and costs, considering all available evidence at the date of review.
The impairment evaluation triggers include a significant long-term decrease in
current and projected prices or reserve volumes, an accumulation of project
costs significantly in excess of the amount originally expected and historical
and current negative operating losses. Although we evaluate future oil and gas
prices as part of the impairment analysis, we do not view short-term decreases
in prices, even if significant, as impairment triggering events.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment of value, and a loss is recognized at the
time of the impairment by providing an impairment allowance. An asset would be
impaired if the undiscounted cash flows were less than its carrying value.
Impairments are measured by the amount by which the carrying value exceeds its
fair value. Because the Company uses the successful efforts method, the Company
assesses its properties individually for impairment, instead of on an aggregate
pool of costs.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A"). DD&A was $1,306,617 in 2010
compared to $432,051 in 2009. The increase in DD&A was attributed to increased
production levels during 2010 due to the Marathon Transaction.
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.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense
increased to $3,288,816 in 2010 from $210,454 in 2009. Non-cash stock-based
compensation totaled $1,052,683 for 2010 and $0 for 2009. Consulting and other
professional fees increased by $932,430 due to the Marathon 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 $1,724,745 in 2010 from
$62,721 in 2009 due to an increase in debt levels or approximately $14,600,000.
Net (loss) increased by ($5.0) million, from ($467,110) in 2009 to ($5,483,487)
in 2010.
CAPITAL RESOURCES AND LIQUIDITY
During 2010, the Company issued a total of 2,335,000 shares for a combination of
bond commitment fees, compensation, professional services and convertible debt.
Our primary sources of liquidity our formation has 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 ("CEPM), which was acquired 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 CEPM pursuant to a Security Agreement. Upon execution
of the Credit Agreement, CEPM utilized the $6,000,000 available under the Credit
Agreement as partial payment in the acquisition of the Marathon Assets.
As of year ended December 31, 2010, we had negative working capital of
($4,108,289) compared to $859,841 at year ended December 31, 2009. We will seek
additional sources of capital for the coming year. The negative working capital
at December 31, 2010 results from $6,000,000 debt classified as a current
liability due to debt covenant violations and from $352,579 of lines of credit
which are due within the next year.
During the year ended December 31, 2010 the Company completed a reverse merger
with Northern Exploration, as part of this merger the Company declared a 1 for
200 stock split which resulted in 498,601 shares issued and outstanding. In
conjunction with the merger, the Company issued 7,000,000 shares at $.016 and
5,501,400 shares at $.05 to convert $395,338 of debt into equity. In addition
the Company issued 52,000,000 shares (pre stock dividend referenced below) of
restricted common stock to the members of High Plains LLC for an 80% ownership
in the Company. On December 19,2010 the Company completed a one share for each
existing share stock dividend which increased all outstanding shares of the
Company.
On December 6, 2010, the Company declared a one share for each existing share
stock dividend to all holders of record on that date and issued 65,000,011
shares of common stock to its holders of record.
The Company has issued 5,360,000 shares of common stock at in private placements
to qualified investors.
The Company purchased approximately 35% of Big Cat for $200,000 cash and 729,180
shares of restricted common stock valued at $.69 per share and acquired the
remaining interest in CEP_M Purchase for a note payable of $1,500,000 and
22,500,000 shares of restricted common stock at $.69 per share during the year
ended December 31, 2010.
After the above referenced transactions, the Company had 160,934,202 shares
issued and outstanding at December 31, 2010
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 December 31, 2010 and 2009, 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 producing oil and gas
properties in 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 these 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 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 December 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
In June 2009, the FASB approved the FASB Accounting Standards Codification
("ASC"), which after its effective date of July 1, 2009 is the single source of
authoritative, nongovernmental U.S. Generally Accepted Accounting Principles
(GAAP). The Codification reorganizes all previous U.S. GAAP pronouncements into
roughly 90 accounting topics and displays all topics using consistent structure.
All existing standards that were used to create the Codification are now
superseded, replacing the previous references to specific Statements of
Financial Accounting Standards ("SFAS") with numbers used in the Codification's
structural organization. The adoption of this guidance did not have a material
impact on our financial statements. We have updated our disclosures accordingly.
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.
Recent changes to SEC Regulation S-K and S-X pertaining to Modernization of Oil
and Gas Reporting include changes to the price used to compute reserves, the
definition of reserves, the use of technology and the optional disclosure of
probable and possible reserves. The new regulations are effective for years
ending after December 15, 2009.
RELIANCE ON ONE REVENUE SOURCE
During the fiscal year ended December 31, 2010, we had 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, however, we intend to rely upon the sale of natural gas.
OPERATING LEASES
As of April 1, 2011, the Company is finishing 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
remained in the office space on a month to month lease while terms for a new
lease are being negotiated. We believe that our 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
A portion of our production is sold under certain contractual arrangements that
specify the delivery of a fixed and determinable quantity. 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 December 31, 2010 we were committed to deliver the
following fixed quantities of our natural gas production:
GROSS
PIPELINE SYSTEM / DELIVERABLE DELIVERIES
TYPE OF 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 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
-------------------------------------------------------------------
The primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks. The term "market risk" refers to the risk of loss arising from adverse
changes in natural gas and oil prices and interest rates. The disclosures are
not meant to be precise indicators of expected future losses, but rather
indicators of reasonably possible losses. This forward-looking information
provides indicators of how we view and manage our ongoing market risk exposures.
All of our market risk sensitive instruments were entered into for purposes
other than speculative trading.
COMMODITY PRICE RISK
Our primary market risk exposure is in the prices we receive for our production.
Realized pricing is primarily driven by the prevailing worldwide price for spot
market prices applicable to our U.S. natural gas production. Pricing for
natural gas has been volatile and unpredictable for several years, and we expect
this volatility to continue in the future. The prices we receive for future
production depend on many factors outside of our control, including volatility
in the differences between product prices at sales points and the applicable
index price.
We routinely enter into financial hedges relating to a portion of our projected
production revenue through various financial transactions that hedge future
prices received. If the applicable monthly price indices are different from the
realized pricing, we and the counterparty to the hedges would be required to
settle the difference. These financial hedging activities are intended to
support natural gas at targeted levels that provide an acceptable rate of return
and to manage our exposure to natural gas price fluctuations.
As of March 27, 2011, we have financial derivative instruments related to
natural gas in place for the following periods indicated. Further detail of
these hedges is summarized in the table presented under "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations."
For the year For the year
2011 2012
---- ----
Natural Gas (MMBtu) 66,000 50,500
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
----------------------------------------------------
The information required by this item is included below in "Item 15. Exhibits,
Financial Statement Schedules".
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
------------------------------------------------------------------------
FINANCIAL DISCLOSURES
---------------------
Engagement of new independent registered public accounting firm
Effective December 9, 2010 we engaged Eide Bailly LLP ("Eide Bailly")as our
independent registered public accounting firm with the approval of our board of
directors. Accordingly, we terminated Chang G. Park, CPA, the previous
auditor, effective December 9, 2010. Chang G. Park, CPA's report on the
financial statements as of and for the year ended March 31, 2009 and March 31,
2010 did not contain an adverse opinion or disclaimer of opinion and was not
modified as to uncertainty, audit scope, or accounting principles save and
except for a "going concern" qualification provided with the overall audit
opinion. Eide Bailly was not consulted on any matter relating accounting
principles to a specific transaction, either completed or proposed, the type of
an audit opinion that might be rendered on our financial statements or a
reportable event. From March 31, 2009 through the subsequent year ended March
31, 2010, and since that year end, there were no disagreements with Chang G.
Park, CPA on any matter of accounting principles or practices, financial
statement disclosure, or auditing scope procedure, which disagreements, if not
resolved to the satisfaction of Chang G. Park, CPA, would have caused Chang G.
Park, CPA, to make reference to the subject matter of the disagreement in its
reports on our consolidated financial statements for such periods. We provided
Chang G. Park, CPA with a copy of a current report on Form 8-K prior to its
filing with the SEC, and requested that they furnish us with a letter addressed
to the SEC stating whether they agree with the statements made in this Current
Report on Form 8-K, and if not, stating the aspects with which they do not
agree. A copy of the letter provided from Chang G. Park, CPA was filed as
Exhibit 16.1 to the Form 8-K dated December 9, 2010 and no disagreement was
reported
ITEM 9A(T).CONTROLS AND PROCEDURES
----------------------------------
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES AND REMEDIATION
As required by Rule 13(a)-15 under the Exchange Act, in connection with this
annual report on Form 10-K, under the direction of our Chief Executive Officer
and Chief Financial Officer, we have evaluated our disclosure controls and
procedures as of December 31, 2010, including the remedial actions discussed
below, and we have concluded that, as of December 31, 2010, our disclosure
controls and procedures were ineffective as discussed in greater detail below.
As of the date of this filing, we are still in the process of remediating such
material weaknesses in our internal controls and procedures.
It should be noted that while our management believes our disclosure controls
and procedures provide a reasonable level of assurance, they do not expect that
our disclosure controls and procedures or internal controls will prevent all
error and all fraud. A control system, no matter how well conceived or
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of a control
system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Because of the
inherent limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of fraud, if
any, within our company have been detected. These inherent limitations include
the realities that judgments in decision making can be faulty, and that
breakdowns can occur because of simple error or mistake. Additionally, controls
can be circumvented by the individual acts of some persons, by collusion of two
or more people, or by management override of the controls. The design of any
system of internal control is based in part upon certain assumptions about the
likelihood of future events, and there can be no assurance that any design will
succeed in achieving its stated goals under all potential future conditions.
Over time, controls may become inadequate because of changes in conditions, or
the degree of
compliance with the policies or procedures may deteriorate. Because of the
inherent limitations in a cost-effective control system, misstatements due to
error or fraud may occur and not be detected.
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).
Our management evaluated, under the supervision and with the participation of
our Chief Executive Officer, the effectiveness of our internal control over
financial reporting as of December 31, 2010.
Based on its evaluation under the framework in Internal Control - Integrated
Framework, issued by the Committee of Sponsoring Organizations of the Treadway
Commission, our management concluded that our internal control over financial
reporting was not effective as of December 31, 2010, due to the existence of
significant deficiencies constituting material weaknesses, as described in
greater detail below. A material weakness is a control deficiency, or
combination of control deficiencies, such that there is a reasonable possibility
that a material misstatement of the annual or interim financial statements will
not be prevented or detected on a timely basis.
LIMITATIONS ON EFFECTIVENESS OF CONTROLS
Our Chief Executive Officer and Chief Financial Officer does not expect that our
disclosure controls or our internal control over financial reporting will
prevent all errors and all fraud. A control system, no matter how well
conceived and operated, can provide only reasonable, not absolute, assurance
that the objectives of the control system are met. Further, the design of a
control system must reflect the fact that there are resource constraints, and
the benefits of controls must be considered relative to their costs. Because of
the inherent limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of fraud, if
any, within our company have been detected. These inherent limitations include
the realities that judgments in decision-making can be faulty, and that
breakdowns can occur because of a simple error or mistake. Additional controls
can be circumvented by the individual acts of some persons, by collusion of two
or more people, or by management override of the controls. The design of any
system of controls also is based in part upon certain assumptions about the
likelihood of future events, and there can be no assurance that any design will
succeed in achieving its stated goals under all potential future conditions;
over time, controls may become inadequate because of changes in conditions, or
the degree of compliance with the policies or procedures may deteriorate.
Because of the inherent limitations in a cost-effective control system,
misstatements due to error or fraud may occur and not be detected.
MATERIAL WEAKNESSES IDENTIFIED
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 represent material weaknesses,
including:
i. Lack of audit committee. We currently have no 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 ended December 31, 2010, we had limited
staff that performed nearly all aspects of our financial reporting process,
including, but limited to access to the underlying accounting records and
systems, the ability to post and record journal entries and responsibility for
the preparation of financial statements. This creates 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 interim or annual 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 U.S. generally accepted
accounting principle matters. Management corrected any errors prior to the
release of our Company's December 31, 2010 consolidated financial statements.
PLAN FOR REMEDIATION OF MATERIAL WEAKNESSES
We intend to take appropriate and reasonable steps to make the necessary
improvements to remediate these deficiencies. We intend to consider the results
of our remediation efforts and related testing as part of our year-end 2011
assessment of the effectiveness of our internal control over financial
reporting.
We intend to undertake the below remediation measures to address the material
weaknesses described in this annual report at our earliest opportunity. Such
remediation activities include the following:
i. We continue to recruit additional independent board members to join our
board of directors and will consider the adoption of an audit committee at such
time that additional board members are retained.
ii. We intend to retain additional accounting personnel as well as
individuals qualified to assist in the preparation of our public filings and
assist in accounting matters and we intend to continue to update the
documentation of our internal control processes, including formal risk
assessment of our financial reporting processes.
CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
There were no changes in our internal control over financial reporting during
the quarter ended December 31, 2010 that have materially affected or are
reasonably likely to materially affect, our internal control over financial
reporting.
ITEM 9B. OTHER INFORMATION
--------------------------
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
---------------------------------------------------------------
DIRECTOR AND EXECUTIVE OFFICER SUMMARY
--------------------------------------
The following table sets forth the names, ages, and principal offices and
positions of the Company's current directors, executive officers, and persons
the Company considers to be significant employees. The Board of Directors
elects the Company's executive officers annually. the Company's directors serve
one-year terms or until their successors are elected, qualified and accept their
positions. The executive officers serve terms of one year or until their death,
resignation or removal by the Board of Directors. Other than Joseph Hettinger
who is the son of Mark D. Hettinger, there are no family relationships or
understandings between any of the directors and executive officers. In
addition, there was no arrangement or understanding between any executive
officer and any other person pursuant to which any person was selected as an
executive officer.
NAME OF DIRECTOR OR OFFICER AGE POSITION
--------------------------- --- ----------------------------------------------
Brent M. Cook 50 Chief Executive Officer
Mark D. Hettinger 51 Director, President and Chief Operating
Officer
Joseph Hettinger 29 Director and Chief Financial Officer
Brandon Hargett 39 Vice President Strategy & Business Development
Gary Davis Director
Cordell Fonnesbeck 63 Director
Alan Smith 71 Director
EXECUTIVE OFFICER AND DIRECTOR BIOS
Brent M. Cook, Chief Executive Officer
Mr. Cook has served as the Company's Chief Executive Officer since February 16,
2011. Prior to joining the Company, Mr. Cook served as CEO and a member of the
Board of Directors of Current Energy Partners Corporation, a privately held
Delaware Corporation. Current was held the acquiring entity of CEP-M Purchase,
LLC until it sold its interest for common stock in High Plains Gas, Inc.
Previous to Current Energy, Mr. Cook served as a director of Raser Technologies
Inc., a publicly traded energy technology company listed on the NYSE ("Raser"
NYSE:RZ) from October 2004 until August 2009 and as Raser's Chief Executive
Officer from January 2005 until August 2009. From 1996 to 2002, Mr. Cook served
in various positions at Headwaters Inc. (NYSE: HW), a large publicly-traded
energy technology company, including Chief Executive Officer, President, and
Chairman of the Board of Directors. Prior to his joining Headwaters Inc., Mr.
Cook was Director of Strategic Accounts, Utah Operations, at PacifiCorp, which
operates as a local electric utility in seven western states. Mr. Cook spent 12
years at PacifiCorp with specific expertise in transmission interconnection and
power sales agreements. Mr. Cook was also employed from 2002-2005 by AMP
Resources, a geothermal power generation company that later sold their projects
to ENEL, an Italian power generation company.
Mark D. Hettinger, Director, President and Chief Operating Officer
Mr. Hettinger has over 30 years of experience in oil and gas construction,
fabrication and process equipment. Mr. Hettinger founded Hettinger Welding in
1980 to provide welding and fabrication services to energy companies in Wyoming.
In October 2006, after 28 years as principal owner and CEO, Mr. Hettinger sold
Hettinger Welding. Mr. Hettinger's unique vision and professional ambition grew
Hettinger Welding to over 1,400 employees and a $200million plus dollar annual
market share, solidifying Hettinger Welding as one of the largest oil and gas
construction firms in the Western United States. In 2009, Mr. Hettinger retired
as CEO of Hettinger Welding to focus on oil and gas production and became
managing member of High Plains Gas, LLC, which was acquired by the Company in
connection with the Reorganization Agreement.
Joseph Hettinger, Director and Chief Financial Officer
Mr. Hettinger has over 10 years of experience in accounting and finance in the
banking and energy industries. Mr. Hettinger co-authored the internal control
structure for Sarbanes Oxley Sec. 404 for a publicly traded bank in 2004. In
2004, Mr. Hettinger co-founded Rocky Mountain Development Group, Inc. where he
served as the Vice President of Acquisitions and Finance through 2006. Mr.
Hettinger became a member of the Hettinger Companies in 2007 as the Southern
Wyoming Regional Manager and Director of Contract Administration. In 2008, Mr.
Hettinger managed oil and gas facility construction projects worth over $90
million dollars for the Hettinger Companies. Mr. Hettinger became a managing
member of High Plains Gas, LLC, which was acquired by the Company in connection
with the Reorganization Agreement.
Brandon Hargett, Vice President Strategy & Business Development
Mr. Hargett has over 11 years of corporate oil and gas finance and retail
investment management experience. Mr Hargett currently oversees business
development and acquisition evaluation at the Company. Prior to joining High
Plains Gas, Mr. Hargett served as COO of Current Energy where he was
instrumental in negotiating and closing the acquisition of the"North & South
Fairway" assets of Marathon Oil Corporation (NYSE:MRO) located in the Powder
River Basin. Prior to joining Current Energy, Mr Hargett has served as
President of Mirus Capital Investment Advisors, which focused on retail
investment management. Mr. Hargett graduated with a Bachelors of Science in
Health and an M.B.A. from the University of Utah.
Gary Davis, Director
Mr. Davis is the President and Founder of Kahuna Ventures LLC, formed in 1999, a
natural gas processing, treating and project-consulting firm, and has well over
32 years in the natural gas space. Kahuna Ventures currently has 40 employees,
including 20 engineers and 7 field construction managers or inspectors.
Previous to founding Kahuna, Mr. Davis worked at Western Gas Resources, Inc. for
over 14 years. Mr. Davis' tenure included holding such positions as Corporate
Controller, Sr. Vice President of Engineering & Production, Environmental and
Safety, Vice President of Southern Region and Vice President of Engineering &
Environmental. During Mr. Davis' time with Western Gas, he assisted in growing
a 50-employee company into a major independent mid-stream corporation with over
950 employees and a gross income in excess of $1 billion. Mr. Davis has
extensive experience in all project functions including due diligence, site and
right of way acquisition, legal, environmental and permitting, safety and
operations. Mr. Davis has a B.S. degree from the Colorado School of Mines (CSM)
in Chemical and Petroleum Refining Engineering.
Cordell Fonnesbeck, Director
Mr. Fonnesbeck is the owner and founder of his own public accounting firm,
Cordell Fonnesbeck, CPA, P.C. since 1991 and has been a member of the American
Institute of Certified Public Accountants (AICPA) since 1974. Mr. Fonnesbeck
resides in Casper, Wyoming and has been a Certified Public Accountant with over
39 years of public
accounting experience. Mr. Fonnesbeck established his Casper, Wyoming CPA firm
in 1991 and prior to that was in partnership with three other CPAs. Mr.
Fonnesbeck's practice consists mainly of assisting small to medium size
businesses and individuals throughout Wyoming and the Intermountain West in the
areas of tax compliance, tax planning and accounting services. This practice
includes several energy and related industry clients in the Powder River Basin
area of Wyoming. From 2005 - 2009, Mr. Fonnesbeck was the accountant for High
Plains Gas, LLC, which was the predecessor to High Plains Gas, Inc. Mr.
Fonnesbeck serves on the Board of Directors for a Private Charitable Foundation
located in Casper. Mr. Fonnesbeck received his bachelor of science degree in
business and accounting from Utah State University in 1972.
Alan R. Smith, Director
Mr. Smith began his career in the energy industry in 1966 and has been an
exploration geologist, geological consultant, exploration manager, division
manager, business development manager (international), and V.P. of international
development for such companies as Amoco Production Co., Mountain Fuel Supply Co.
(Questar), Lear Petroleum, Davis Oil Co., Inexco Oil Co., and Pennzoil
Exploration and Development Co., in both domestic and international capacities.
From 1998 to 2003 Mr. Smith was Vice President, International Business
Development, for EEX Corporation, where he oversaw the evaluation of exploration
and production projects in Asia and Australasia. Mr. Smith has developed and
managed many relationships with government oil companies in Indonesia, Brunei
and New Zealand. Mr. Smith holds a Bachelor of Science (1966) and Master of
Science (1968) in Geology from Brigham Young University and is a Certified
Petroleum Geologist with the American Association of Petroleum Geologists and is
a Registered Professional Geologist in the State of Wyoming
Director Independence
WE HAVE DETERMINED THAT MR. GARY DAVIS, MR. CORDELL FONNESBECK AND MR. ALAN R.
SMITH ARE INDEPENDENT DIRECTORS OF THE COMPANY IN ACCORDANCE WITH APPLICABLE SEC
DEFINITIONS. FOR PURPOSES OF A FINANCIAL EXPERT OF THE BOARD WE HAVE DETERMINED
THAT MR. FONNESBECK AS A CPA MAINTAINS THAT EXPERTISE.
Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 (the "Exchange Act")
requires our directors and officers, and persons who own more than ten percent
of the Common Stock to file reports of ownership and changes in ownership with
the Securities and Exchange Commission ("SEC"). SEC regulations require
reporting persons to furnish us with copies of all Section 16(a) forms they
file.
Based solely on our review of the copies of the Forms 3, 4 and 5 and amendments
thereto furnished to us by the persons required to make such filings during
fiscal 2010 and our own records, we believe that all Section 16(a) filing
requirements for our officers and directors were complied with on a timely
basis.
Corporate Governance
The Company's Corporate Governance Principles and Corporate Code of Conduct
(covering all employees and directors), as well as the Certificate of
Incorporation and the By-Laws are all available on our website at
www.highplainsgas.com.
---------------------
MEETINGS AND ATTENDANCE
During the fiscal year ended December 31, 2010, the board of directors met 11
times. In 2010, all directors attended at least 75% of all meetings of the
board of directors served after becoming a member of the board.
Relationships Among Directors or Executive Officers
Other than Joseph Hettinger who is the son of Mark D. Hettinger, there are no
family relationships among any of our directors or executive officers.
Compensation Committee Interlocks and Insider Participation
No interlocking relationship exists between any member of our board of directors
and any member of the board of directors of any other company, nor has such
interlocking relationship existed in the past.
ITEM 11. EXECUTIVE COMPENSATION
-------------------------------
SUMMARY COMPENSATION
The following table summarizes the total compensation awarded to, earned by or
paid by us for services rendered by the named executive officers that served
during the fiscal years 2010 and 2009.
NAME AND OPTION ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS AWARDS COMPENSATION TOTAL
--------------------------- ---- ------ ----- ------ ------------ -----
Current Executive Officers:
Brent M. Cook,
Chief Executive Officer 2010
Mark D. Hettinger,
Chairman of the Board 2010
of Directors and
Chief Operating Officer 2009
Joseph Hettinger, 2010
Chief Financial Officer
and Director 2009
Brandon Hargett,
Vice President Strategy
and Business Development 2010
COMPENSATION DISCUSSION AND ANALYSIS
The Company does not have a standing compensation committee. The Company's
board of directors as a whole makes the decisions as to employee benefit
programs and officer and employee compensation. The primary objectives of the
Company's executive compensation programs are to:
- attract, retain and motivate skilled and knowledgeable individuals;
- ensure that compensation is aligned with the Company's corporate
strategies and business objectives;
- promote the achievement of key strategic and financial performance
measures by linking short-term and long-term cash and equity incentives to the
achievement of measurable corporate and individual performance goals; and
- align executives' incentives with the creation of stockholder value.
To achieve these objectives, the Company's board of directors evaluates the
Company's executive compensation program with the objective of setting
compensation at levels they believe will allow the Company to attract and retain
qualified executives. In addition, a portion of each executive's overall
compensation is tied to key strategic, financial and operational goals set by
the Company's board of directors. The Company also generally provides a portion
of the Company's executive compensation in the form of options that vest over
time, which the Company believes helps the Company retain the Company's
executives and align their interests with those of the Company's stockholders by
allowing the executives to participate in the Company's longer term success as
reflected in asset growth and stock price appreciation.
NAMED EXECUTIVE OFFICERS
The following table identifies the Company's principal executive officer, the
Company's principal financial officer and the Company's most highly paid
executive officers, who, for purposes of this Compensation Disclosure and
Analysis only, are referred to herein as the "Named Executive Officers."
Name Corporate Office(s)
----------------- --------------------------------------
Brent M. Cook Chief Executive Officer
Mark D. Hettinger President and Chief Operating Officer
Joseph Hettinger Chief Financial Officer
Vice President of Strategy and
Brandon Hargett Business Development
COMPONENTS OF THE COMPANY'S EXECUTIVE COMPENSATION PROGRAM
The primary elements of the Company's executive compensation program will be
base salaries and equity grant incentive awards, although the board of directors
has the authority to award cash bonuses, benefits and other forms of
compensation as it sees fit. The Company currently does not have any equity
plan in place.
The Company does not have any formal or informal policy or target for allocating
compensation between short-term and long-term compensation, between cash and
non-cash compensation or among the different forms of non-cash compensation.
Instead, the Company has determined subjectively on a case-by-case basis the
appropriate level and mix of the various compensation components. Similarly,
the Company does not rely on benchmarking against the Company's competitors in
making compensation related decisions.
BASE SALARIES
Base salaries will be used to recognize the experience, skills, knowledge and
responsibilities required of the Company's Named Executive Officers. Base
salary, and other components of compensation, may be evaluated by the Company's
board of directors for adjustment based on an assessment of the individual's
performance and compensation trends in the Company's industry.
EQUITY AWARDS
The Company's stock option award program will be the primary vehicle for
offering long-term incentives to the Company's executives. To date, the Company
has not issued any equity awards. The Company intends the Company's equity
awards to executives to generally be made in the form of common stock or
warrants. The Company believes that equity grants in the form of warrants
provide the Company's executives with a direct link to the Company's long-term
performance, create an ownership culture, and align the interests of the
Company's executives and the Company's stockholders.
CASH BONUSES
The Company's board of directors has the discretion to award cash bonuses based
on the Company's financial performance and individual objectives. The corporate
financial performance measures (revenues and profits) will be given the greatest
weight in this bonus analysis. The Company has not yet granted any cash bonuses
to any named executive officers.
BENEFITS AND OTHER COMPENSATION
The Company's Named Executive Officers are permitted to participate in such
health care, disability insurance, bonus and other employee benefits plans as
may be in effect with the Company from time to time to the extent the executive
is eligible under the terms of those plans. As of the date of this Memorandum,
with exception to health care, the Company has not implemented any such employee
benefit plans.
EXECUTIVE COMPENSATION AGREEMENTS
As discussed above, the Company has agreed to pay the Named Executive Officers
an annual salary. Base salary may be increased from time to time with the
approval of the board of directors. The following table summarizes the agreed
annual salary of each of the Named Executive Officers:
Summary Annual Salary
Name Annual Salary
--------------- --------------
Brent Cook $ 175,000
Mark Hettinger $ 175,000
Joe Hettinger $ 150,000
Brandon Hargett $ 80,000
GRANTS OF PLAN-BASED AWARDS TABLE FOR FISCAL YEAR 2010
The Company's 2010 Employee and Consultant Stock Option Plan provides for the
issuance of up to 12,000,000 options to purchase common stock. The options may
either be qualified or unqualified, but the plan requires that the exercise
price reflect then current market price. No options under that plan have been
issued. During fiscal 2010, the Company did not grant any equity awards under
any equity award plan.
OPTION EXERCISES FOR FISCAL 2010
During fiscal 2010, none of the Named Executive Officers exercised options.
NONQUALIFIED DEFERRED COMPENSATION
The Company currently offers no defined contribution or other plan that provides
for the deferral of compensation on a basis that is not tax-qualified to any of
the Company's employees, including the Named Executive Officers.
COMPENSATION OF DIRECTORS
The Company intends to use a combination of cash and equity-based compensation
to attract and retain candidates to serve on the Company's board of directors.
The Company will not compensate directors who are also the Company's employees
for their service on the Company's board of directors. The Company did not
provide any compensation to any member of the Company's Board of Directors,
other than as employees, for the fiscal year ended December 31, 2010.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Company does not currently have a standing Compensation Committee. The
Company's entire board of directors participated in deliberations concerning
executive officer compensation.
EMPLOYMENT, SEVERANCE AND CHANGE OF CONTROL ARRANGEMENTS
Mark D. Hettinger
Mark D. Hettinger signed an employment agreement with the Company effective
January 1, 2011. The agreement provides for employment for a period of one year
from the effective date, ending at the close of business on December 31, 2011.
The agreement is automatically renewed if neither party provides notice 60 days
prior to termination. The agreement states that the Company employs Mr.
Hettinger as its Chairman of the Board, and that he reports to the Company's
Board of Directors. The agreement established his starting annual base salary
at $175,000, subject to reviews and increases at the sole discretion of the
Board.
If Mr. Hettinger resigns his employment for good reason, or the Company
terminates his employment without cause, he will be entitled to receive all
accrued but unpaid salary and benefits through the date of termination plus
three months' severance of his base salary. In the event Mr. Hettinger resigns
from the Company without good reason, or if the Company terminates his
employment with cause, the Company has no liability to him except to pay his
base compensation and any accrued benefits through his last day worked, and he
will not be entitled to receive severance or other benefits.
Brent M. Cook
Brent M. Cook signed an employment agreement with the Company effective January
1, 2011. The agreement provides for employment for a period of one year from
the effective date, ending at the close of business on December 31, 2011. The
agreement is automatically renewed if neither party provides notice 60 days
prior to termination. The agreement states that the Company employs Mr. Cook as
its Chief Executive Officer, and that he reports to the Company's Board of
Directors. The agreement established his starting annual base salary at
$175,000, subject to reviews and increases at the sole discretion of the Board.
If Mr. Cook resigns his employment for good reason, or the Company
terminates his employment without cause, he will be entitled to receive all
accrued but unpaid salary and benefits through the date of termination plus
three months' severance of his base salary. In the event Mr. Cook resigns from
the Company without good reason, or if the Company terminates his employment
with cause, the Company has no liability to him except to pay his base
compensation and any accrued benefits through his last day worked, and he will
not be entitled to receive severance or other benefits.
Joseph Hettinger
Joseph Hettinger signed an employment agreement with the Company effective
January 1, 2011. The agreement provides for employment for a period of one year
from the effective date, ending at the close of business on December 31, 2011.
The agreement is automatically renewed if neither party provides notice 60 days
prior to termination. The agreement states that the Company employs Mr.
Hettinger as its Chief Financial Officer, and that he reports to the Company's
Board of Directors. The agreement established his starting annual base salary
at $150,000, subject to reviews and increases at the sole discretion of the
Board.
If Mr. Hettinger resigns his employment for good reason, or the Company
terminates his employment without cause, he will be entitled to receive all
accrued but unpaid salary and benefits through the date of termination plus
three months' severance of his base salary. In the event Mr. Hettinger resigns
from the Company without good reason, or if the Company terminates his
employment with cause, the Company has no liability to him except to pay his
base compensation and any accrued benefits through his last day worked, and he
will not be entitled to receive severance or other benefits.
Brandon Hargett
Brandon Hargett signed an employment agreement with the Company effective
January 1, 2011. The agreement provides for employment for a period of one year
from the effective date, ending at the close of business on December 31, 2011.
The agreement is automatically renewed if neither party provides notice 60 days
prior to termination. The agreement states that the Company employs Mr. Hargett
as an employee in business development and that he reports to the Chief
Executive Officer. The agreement established his starting annual base salary at
$80,000, subject to reviews and increases at the sole discretion of the Board.
If Mr. Hargett resigns his employment for good reason, or the Company
terminates his employment without cause, he will be entitled to receive all
accrued but unpaid salary and benefits through the date of termination plus
three months' severance of his base salary. In the event Mr. Hargett resigns
from the Company without good reason, or if the Company terminates his
employment with cause, the Company has no liability to him except to pay his
base compensation and any accrued benefits through his last day worked, and he
will not be entitled to receive severance or other benefits.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
---------------------------------------------------------------------------
RELATED STOCKHOLDER MATTERS
---------------------------
The following table shows the beneficial ownership of the Company's common stock
as of April 15, 2011. The table shows the amount of shares owned by each person
known to the Company who will own beneficially more than five percent of the
outstanding shares of any class of the Company's stock, based on the number of
shares outstanding assuming completion of the reorganization; each of the
Company's Directors and Executive Officers; and all of its Directors and
Executive Officers as a group.
NAME OF NUMBER OF SHARES PERCENT OF SHARES
PERSON OR GROUP BENEFICIALLY OWNED(1) BENEFICIALLY OWNED(2)
Mark D. Hettinger,
Chief Operating Officer
and Director 47,840,000 28.7%
Joseph Hettinger,
Chief Financial Officer
and Director 40,300,000 24.2%
Brent M. Cook,
Chief Executive Officer 22,500,000(3) 13.5%
Brandon Hargett,
Vice President of
Strategy and Business
Development 22,500,000(3) 13.5%
Gary Davis, Director 0 *
Cordell Fonnesbeck,
Director 0 *
Alan R. Smith, Director 0 *
Fletcher International, Ltd. 10,000,000(4) 5.7%
All Directors and
Officers as a Group 110,640,000 66.4%
* Less than 0.1%
(1) Pursuant to Rule 13d-3 under the Securities Exchange Act of 1934, involving
the determination of beneficial owners of securities, a beneficial owner of
securities is a person who directly or indirectly, through any contract,
arrangement, understanding, relationship or otherwise has, or shares, voting
power and/or investment power with respect to the securities, and any person who
has the right to acquire beneficial ownership of the security within sixty days
through means including the exercise of any option, warrant or conversion of a
security.
(2) The percentage of shares owned is based on approximately 166,523,602 shares
of common stock outstanding as of April 15, 2011. Also reflects a one for one
stock dividend effective December 16, 2010. Where the beneficially owned shares
of any individual or group in the following table includes any options,
warrants, or other rights to purchase shares, the percentage of shares owned
includes such shares as if the right to purchase had been duly exercised.
(3) Reflects 22,500,000 shares held by Current Energy Corporation, of which Mr.
Cook and Mr. Hargett may be deemed to be beneficial owners.
(4) Reflects the maximum number of shares issuable to Fletcher International
Corporation pursuant to a warrant to purchase up to $5,000,000 in shares issued
on March 3, 2011. The warrant exercise price is the lesser of $1.25 per share
or the volume weighted average market price for the prior calendar month (with a
minimum exercise price of $0.50 per share).
ITEM 13. CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
------------------------------------------------------------------------------
We have adopted a written policy for the review and approval of related party
transactions which is defined as a sale or purchase of property, supplies or
services to or from any director or officer of the company, members of a
director's or officer's family, or entities in which any of these persons is a
director, officer or owner of 5% or more that that entity's interests. Our
policy requires prior approval by both a majority of our Board of Directors and
a majority of our disinterested directors who are not employees of the company.
INDEBTEDNESS TO RELATED PARTIES. The Company currently has payables due to Mark
D. Hettinger, Chairman and Chief Operating Officer, Joseph Hettinger, Chief
Financial Officer and Director, Jerri Hettinger, and Mike Hettinger, as of
December 31, 2010 totaling $6,112,782 of principal and $111,498 accrued interest
payable as of December 3rd, 2010.
OTHER TRANSACTIONS
Because of the remote location of the Company's headquarters, the Company
periodically utilizes an airplane owned by Mark D. Hettinger for business
related travel. Mr. Hettinger is reimbursed all costs associated with
utilization of such airplane. For the fiscal year ended December 31, 2010,
those expenses totaled $63,200.
On December 31, 2010, Mike Hettinger converted a note payable from the Company
for $550,000 into 1,100,000 shares of common stock.
CURRENT TRANSACTION
Brent M. Cook and Brandon Hargett, officers of the Company, are principals of
Current Energy Corporation. As described elsewhere in this report, Current
received 22,500,000 common shares and will receive $1,500,000 in repayment of a
promissory note in connection with the sale to the Company of the Marathon
Assets
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
-----------------------------------------------
INDEPENDENT PUBLIC ACCOUNTANTS
Effective December 9, 2010 we engaged Eide Bailly, LLP ("Eide Bailly")as our
independent registered public accounting firm. Our predecessor's independent
registered public accounting firm was Chang G. Park, CPA's ("Park"), although
Park has not provided services to us.
Fees Billed by Principal Accountants - The following table presents fees for
professional services paid to Eide Bailly and Park during the years ended
December 31, 2010 and 2009:
DECEMBER 31, DECEMBER 31,
2010 2009
------------ ------------
Audit fees 0 0
Tax fees 0 0
Audit related fees 0 0
------------ ------------
TOTAL - EIDE BAILLY 0 0
============ ============
DECEMBER 31, DECEMBER 31,
2010 2009
------------ ------------
Audit fees 0 0
Tax fees 0 0
Audit related fees 0 0
------------ ------------
TOTAL - PARK 0 0
============ ============
AUDIT COMMITTEE PRE-APPROVAL OF SERVICES OF PRINCIPAL ACCOUNTANTS
When appointed, the Company's Audit Committee will have the sole authority and
responsibility to select, evaluate, determine the compensation of, and, where
appropriate, replace the independent auditor. After determining that providing
the non-audit services is compatible with maintaining the auditor's
independence, the Audit Committee will pre-approve all audits and permitted
non-audit services to be performed by the independent auditor, except for de
minimus amounts. If it is not practical for the Audit Committee will meet to
approve fees for permitted non-audit services.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
---------------------------------------------------
(a) List of financial statements and schedules.
The following consolidated financial statements of High Plains Gas, Inc. and
Subsidiaries are included herein by reference to the pages listed in "Item 8.
Financial Statements and Supplementary Data":
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2010 and 2009
Consolidated Statements of Operations for the years ended December 31, 2010 and
2009
Consolidated Statements of Changes in Shareholders' Equity for the years ended
December 31, 2010 and 2009
Consolidated Statements of Cash Flows for the years ended December 31, 2010 and
2009
Notes to Consolidated Financial Statements
(b) List of exhibits: See Exhibit Index immediately preceding exhibits.
ITEM 8. FINANCIAL STATEMENTS.
FINANCIAL STATEMENTS
INDEX
FINANCIAL STATEMENTS DECEMBER 31, 2010 AND DECEMBER 31, 2009
Report of Independent Registered Public Accounting Firm F-1
Consolidated Balance Sheets F-2
Consolidated Statements of Operations F-3
Consolidated Statements of Cash Flows F-4
Consolidated Statements of Changes in Shareholders' Equity F-5
Notes to Consolidated Financial Statements F-6
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
to be filed by amendment
HIGH PLAINS GAS, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2010 AND 2009
2010 2009
------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 208,823 $ 45,426
Certificates of deposit 200,000 175,000
Accounts receivable 1,114,335 119,786
Investment in equity securities,
at fair value 2,645,108 --
Deferred financing fees 196,238 --
Bond commitment fees 2,469,914 --
Prepaid and other 143,741 25,962
------------ ------------
Total current assets 6,978,159 366,174
------------ ------------
OIL AND GAS PROPERTIES-using successful
efforts method 42,755,317 3,060,535
Less accumulated depletion,
depreciation and amortization (3,174,836) (1,897,893)
------------ ------------
Oil and Gas Properties-net 39,580,481 1,162,642
------------ ------------
PROPERTY, PLANT AND EQUIPMENT-NET 1,316,307 19,905
OTHER ASSETS 125,000 2,022
------------ ------------
TOTAL ASSETS $47,999,948 $ 1,550,743
============ ============
LIABILITIES AND STOCKHOLDERS'
EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities $ 4,416,745 $ 276,688
Accounts payable-related parties -- 30,196
Current portion-term debt 1,661,685 119,131
Current portion - lines of credit 6,352,579 800,000
------------ ------------
Total current liabilities 12,431,009 1,226,015
NOTES PAYABLE - RELATED PARTIES 6,033,666 --
DEBT OBLIGATIONS - LINES OF CREDIT,
NET OF CURRENT 162,624 317,432
DEBT OBLIGATIONS - TERM DEBT,
NET OF CURRENT 943,065 --
COMMODITY DERIVATIVE 603,742 --
ASSET RETIREMENT OBLIGATION 8,229,630 33,046
------------ ------------
Total liabilities 28,403,736 1,576,493
------------ ------------
STOCKHOLDERS' EQUITY:
Common stock-$.001 par value: 250,000,000
shares authorized; 160,934,202 shares
and 0 shares issued and outstanding, respectively 160,934 130,000
Additional paid in capital 25,256,500 181,985
Accumulated income (loss) (5,821,222) (337,735)
------------ ------------
Total shareholders' equity 19,596,212 (25,750)
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 47,999,948 $ 1,550,743
============ ============
See accompanying notes to financial statement
HIGH PLAINS GAS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009
2010 2009
------------- -----------
REVENUES:
Gas and oil revenue $ 2,464,552 $ 520,620
Pipeline revenue 110,506 235,689
Other 36,911 87,930
------------- -----------
Total Revenue 2,611,969 844,239
============= -----------
COSTS AND EXPENSES
Lease operating expense and production taxes 3,230,426 613,873
General and administrative expense 3,288,816 210,454
Depreciation, depletion and amortization 1,306,617 432,051
Accretion of asset retirement obligation 65,979 2,139
------------- -----------
Total Costs and Expenses 7,891,838 1,755,470
============= -----------
OPERATING (LOSS) (5,279,869) (414,278)
============= -----------
OTHER INCOME (EXPENSE)
Other income 481,302 9,889
Gain on valuation of equity securities 1,935,234 --
Amortization of bond commitment and
financing fees (291,667) --
Commodity derivative adjustment (603,742) --
Interest (expense) (1,724,745) (62,721)
------------- -----------
Total Other Income (Expense) 203,618 (52,832)
------------- -----------
NET INCOME (LOSS) $ (5,483,487) $ (467,110)
============= ===========
Net income (loss) per share $ (0.04) N/A
Weighted average number of common shares
outstanding-basic and diluted 132,963,461 0
See accompanying notes to financial statements
HIGH PLAINS GAS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOW
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009
2010 2009
------------ ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $(5,483,487) $(467,110)
Adjustments to reconcile net loss to
net cash provided by operating activities:
Depletion, depreciation and amortization 1,664,263 434,190
Derivative fair value 603,742 0
Stock based compensation 1,282,783 --
Gain on sale of assets (401,000) --
Gain on fair value of securities (1,935,234) --
Changes in operating assets and liabilities:
Accounts receivable (994,549) (17,333)
Certificate of deposit -- --
Prepaid and other assets (117,779) (6,614)
Payables and accrued liabilities 4,114,290 63,645
------------ ----------
Net cash (used in) operating activities (1,266,971) 6,628
------------ ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (7,280,160) (349,896)
Purchase of equipment (1,302,303) --
Proceeds from sale of assets (401,000) --
Purchase bond (350,000) --
------------ ----------
Net cash provided by (used in)
investing activities (8,531,463) (349,896)
------------ ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from related party debt 4,905,385 193,986
Proceeds from line of credit 661,148 220,000
Payment on line of credit (945,945) (100,102)
Member contributions 678,220
Redemptions of members (134,000)
Stock issued for cash 2,680,100
Payment of financing fees (71,075)
Proceeds from debt 2,700,000
Payment on debt (531,813)
Net cash provided by financing activities 9,942,020 313,884
------------ ----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 163,397 (29,384)
CASH AND EQUIVALENTS, at beginning
of period 45,426 74,810
------------ ----------
CASH AND EQUIVALENTS, at end of period $ 208,823 $ 45,426
============ ==========
See accompanying notes to financial statements
HIGH PLAINS GAS, INC.
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS'S EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2010 AND 2009
Common Stock
------------ ----------- Additional RETAINED
Par value Paid-in EARNINGS
Shares $ .001 Capital (Deficit) Total
------------ ----------- ------------ ------------ ------------
BALANCES, NORTHERN EXPLORATION, INC,
BEGINNING BALANCES 99,720,000 $ 99,720 $ (99,720) $ -- $ --
Reverse stock split (99,221,400) (99,221) 99,221 -- --
(964,063) 12,501,400 12,501 (12,501) -- --
------------ ----------- ------------ ------------ ------------
SUBTOTAL 13,000,000 13,000 (13,000) -- --
Shares issued in recapitalization 52,000,000 52,000 65,999 129,375 247,374
Shares issued to CEDE 11 -- -- -- --
Stock dividend 65,000,011 65,000 (65,000) -- --
Contributed Capital -- -- 193,986 -- 193,986
Net (loss) -- -- -- (467,110) (467,110)
------------ ----------- ------------ ------------ ------------
BALANCES, DECEMBER 31, 2009 130,000,022 130,000 181,985 (337,735) (25,750)
Contributed capital -- -- 678,220 -- 678,220
Redemption of certain members -- -- (134,000) -- (134,000)
Warrants issued - compensation -- -- 228,290 -- 228,290
Warrants issued - bond commitment fee -- -- 443,897 -- 443,897
Stock issued as bonus with convertible note 10,000 10 6,490 -- 6,500
Stock issued for bond commitment fee 800,000 800 519,200 -- 520,000
Stock issued for cash 200,000 200 99,900 -- 100,100
Stock issued as bonus with
convertible note 55,000 55 41,195 -- 41,250
Value of beneficial conversion feature of convertible note -- -- 50,000 -- 50,000
Stock and warrants issued for cash 800,000 800 399,200 400,000
Stock issued for cash 4,360,000 4,360 2,175,640 -- 2,180,000
Stock issued for legal services 80,000 80 57,520 -- 57,600
Warrants issued - compensation -- -- 125,739 -- 125,739
Detachable warrants issued with debt -- -- 725,765 -- 725,765
Stock issued for acquisition of CEP-M 22,500,000 22,500 17,415,000 -- 17,437,500
Stock issued to Big Cat Energy Corporation 739,180 739 509,295 -- 510,034
Stock issued to American
Capital Ventures 250,000 250 172,250 -- 172,500
Stock issued as bonus with
convertible note 40,000 40 38,360 -- 38,400
Value of beneficial conversion
feature of convertible note -- -- 275,000 -- 275,000
Stock issued for note conversion 1,100,000 1,100 548,900 -- 550,000
Warrants issued - compensation -- -- 698,654 -- 698,654
Net (loss) -- -- -- (5,483,487) (5,483,487)
------------ ----------- ------------ ------------ ------------
BALANCE DECEMBER 31, 2010 160,934,202 $ 160,934 $25,256,500 $(5,821,222) $19,596,212
============ =========== ============ ============ ============
See accompanying notes to financial statements
HIGH PLAINS GAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND NATURE OF OPERATIONS:
-------------------------------------
High Plains Gas, Inc. ("High Plains," "Company," "we," "our," or "us") was
originally incorporated in Nevada as Northern Explorations, Ltd. ("Northern
Explorations") on November 17, 2004. From its inception, the Company was
engaged in the business of exploration of natural resource properties in the
United States. After the effective date of its registration statement filed
with the Securities and Exchange Commission (February 14, 2006), the Company
commenced quotation on the Over-the-Counter Bulletin Board under the symbol
"NXPN."
On September 13, 2010 the Company amended its Articles of Incorporation to
change its name to High Plains Gas, Inc. We also completed a 1 for 200 reverse
split of the common stock and increased the authorized common stock to
250,000,000 shares. In April 2011, we increased our authorized common stock to
350,000,000 shares.
On September 30, 2010 the Company entered into an Operations and Convertible
Note Purchase Agreement ("Agreement") with Current Energy Partners Corporation
("CEP"), a Delaware corporation and its wholly owned subsidiary CEP-M Purchase
LLC (CEP-M). Under terms of the Agreement, the Company purchased a convertible
note from CEP with the proceeds to be used by CEP to acquire a significant
resource base and land position from Pennaco Energy, Inc., a wholly owned
subsidiary of Marathon Oil Company. On October 31, 2010 the Company entered
into an agreement with CEP pursuant to which the Company acquired a 49% interest
in CEP-M. On November 19, 2010 the convertible note was converted into a 51%
membership interest in CEP-M, giving the Company effective control of 100% of
CEP-M.
On October 18, 2010, the Company pursuant to a reorganization agreement with
High Plains Gas LLC issued 52,000,000 shares to nine individuals representing
100% of the membership of High Plains Gas, LLC and as a result High Plains Gas,
LLC became a wholly owned subsidiary of the Company. Also under the
reorganization agreement, shareholders and other parties representing what was
Northern Explorations retained approximately 13,000,000 shares of the Company's
common stock.
The reorganization has been accounted for as a reverse merger and under the
accounting rules for a reverse merger, the historical financial statements and
results of operations of High Plains Gas, LLC became those of the Company.
The trading symbol has been changed to "HPGS" to more accurately reflect the
Company's new identity.
High Plains is a natural gas and petroleum exploration, development and
production company, engaged in locating and developing hydrocarbon resources,
primarily distressed and/or orphaned oil and gas projects 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 be methane reserves with prospective acreage potential to the Niobrara
Shale, Mowry Shale and Muddy formations.
The Company's operations and plans for expansion are dependent upon continued
equity or debt financing.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
------------------------------------------
Basis of Presentation
The consolidated financial statements include High Plains and its wholly owned
subsidiaries, High Plains Gas, LLC and CEP-M. All significant intercompany
transactions have been eliminated in consolidation.
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.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, amounts held in banks and highly
liquid investments purchased with an original maturity of three months or less.
Business Segment Information
The Company has evaluated how it is organized and managed and has identified
only one operating segment, which is the exploration and production of natural
gas, natural gas liquids and crude oil. The Company considers its gathering and
marketing functions as ancillary to its oil and gas producing activities. All
of the Company's operations and assets are located in the United States, and all
of its revenues are attributable to United States customers.
Concentration of Credit Risk
The Company's cash equivalents are exposed to concentrations of credit risk.
The Company manages and controls this risk by placing these funds with major
financial institutions.
The Company's accounts receivable result from (1) oil and natural gas sales to
oil and intrastate pipeline companies and (2) billings to joint working interest
partners in properties operated by the Company. The Company's trade and accrued
production receivables are disbursed among various customers and purchasers and
most of the Company's significant purchasers are large companies with solid
credit ratings. If customers are considered a credit risk, letters of credit are
the primary security obtained to support the extension of credit however no
letters of credit were held at either December 31, 2010 or 2009. For most joint
working interest partners, the Company may have the right of offset against
related oil and natural gas revenues. The joint interest working partner
receivables are not collateralized and to date the Company has had minimal bad
debts. No allowance for uncollectible receivables has been recorded at December
31, 2010 and 2009.
Significant Customers
The following table provides the percentage of revenue derived from oil and
natural gas sales to the Company's top three customers (the customers in each
year are not necessarily the same from year to year):
Years ended
December 31,
2010 2009
----- -----
Customer A 50% 100%
Customer B 46% %
Customer C 4% %
Oil and Natural Gas Properties
High Plains follows the successful efforts method of accounting for its
investments in oil and natural gas properties. The Company uses the successful
efforts method of accounting for oil and natural gas producing activities. Costs
to acquire mineral interests in oil and gas properties, to drill and equip
exploratory wells that find proved reserves, to drill and equip development
wells and related asset retirement costs are capitalized. Costs to drill
exploratory wells that do not find proved reserves, geological and geophysical
costs, and costs of carrying and retaining unproved properties are expensed.
The unit-of-production method of depreciation, depletion, and amortization of
oil and gas properties under the successful efforts method of accounting is
applied pursuant to the simple multiplication of units produced by the costs per
unit on a field by field basis. Leasehold cost per unit is calculated by
dividing the total cost by the estimated total proved oil and gas reserves
associated with that field. Well cost per unit is calculated by dividing the
total cost by the estimated total proved developed oil and gas reserves
associated with that field. The volumes or units produced and asset costs are
known and while the proved reserves have a high probability of recoverability,
they are based on estimates that are subject to some variability. Depletion
expense was $1,306,617 and $432,051 during 2010 and 2009, respectively.
We test for impairment of our properties based on estimates of proved reserves.
Proved oil and gas properties are reviewed for impairment whenever events or
circumstances indicate that the carrying amount may not be recoverable. We
estimate the future undiscounted cash flows of the affected properties to judge
the recoverability of the carrying amounts. Initially this analysis is based on
proved reserves. However, when we believe that a property contains oil and gas
reserves that do not meet the defined parameters of proved reserves, an
appropriately risk adjusted amount of these reserves may be included in the
impairment evaluation. These reserves are subject to much greater risk of
ultimate recovery. An asset would be impaired if the undiscounted cash flows
were less than its carrying value. Impairments are measured by the amount by
which the carrying value exceeds its fair value.
Impairment analysis is performed on an ongoing basis. In addition to using
estimates of oil and gas reserve volumes in conducting impairment analysis, it
is also necessary to estimate future oil and gas prices and costs, considering
all available evidence at the date of review. The impairment evaluation triggers
include a significant long-term decrease in current and projected prices or
reserve volumes, an accumulation of project costs significantly in excess of the
amount originally expected and historical and current negative operating losses.
Although we evaluate future oil and gas prices as part of the impairment
analysis, we do not view short-term decreases in prices, even if significant, as
impairment triggering events.
Unproved property costs not subject to amortization consist primarily of
leasehold costs related to unproved areas. Costs are transferred into the
amortization base on an ongoing basis as the properties are evaluated and proved
reserves are established or impairment is determined. Costs of dry holes are
expensed immediately upon determination that the well is unsuccessful. The
Company will continue to evaluate these properties and costs which will be
transferred into the amortization base as the undeveloped areas are tested. The
Company did not transfer any unproved costs to the amortization base during 2010
or 2009.
During 2010 and 2009, 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:
YEAR ENDED DECEMBER 31,
2010 2009
------------- --------------
Proved oil and gas properties $402,755,318 $ 3,060,535
Accumulated DD&A (3,174,836) (1,865,531)
Net capitalized costs $ 39,580,482 $ 1,195,004
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 for each of the years are
shown below:
YEAR ENDED DECEMBER 31,
2010 2009
----------- -------------
Unproved property costs $ - $ -
Exploration costs - -
Acquisition costs 321,203
Development costs 354,251
ARO Costs - -
----------- -------------
Total operations $ - $ 675,454
=========== =============
Asset retirement obligation (non-cash) $ - $ -
Equipment and Depreciation
Property and equipment is stated and cost and is depreciated using the
straight-line method over estimated useful lives of 5 to 10 years.
2010 2009
----------- ---------
Transportation and vehicles $ 607,422 $ 24,796
Equipment and other 582,698 23,625
Computers and software 155,862 --
----------- ---------
1,345,982 48,421
Less Depreciation (29,674) (14,258)
----------- ---------
$1,316,308 $ 34,163
=========== =========
Depreciation expense was $15,416 and $6,833 during 2010 and 2009, respectively.
Bond Commitment Fees
Fees paid to secure commitments from lenders and to secure bonding arrangements
with the State and other local government entities are capitalized and amortized
on a straight-line basis over the expected term of the arrangement. Fees paid
during 2010 to shareholders totaled $2,469,914 and amortization of these fees is
over a 12-month period. Amortization during 2010 totaled $291,667.
Deferred Financing Fees
Deferred loan costs are amortized over the estimated lives of the related
obligations or, in certain circumstances, accelerated if the obligation is
refinanced. Amortization is calculated using the straight-line method which
approximates the effective interest method.
Derivative Financial Instruments
The Company enters into derivative contracts, primarily swap contracts, to hedge
future natural gas production in order to mitigate the risk of market price
fluctuations. All derivative instruments are recorded on the balance sheet at
fair value. All of the Company's derivative counterparties are financial
institutions. If the derivative does not qualify as a hedge or is not
designated as a hedge, the gain or loss on the derivative is recognized
currently in earnings as a component of financing costs and other. There are no
derivative contracts entered into during 2010 that qualify as hedges. There
were no derivative contracts in place during 2009.
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 December
31, 2010 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 December 31, 2010 and 2009 were not
significant.
Asset Retirement Obligation
The Company follows the provisions of ASC 410, Asset Retirement and
Environmental Obligations (ARO). The estimated fair value of the future costs
associated with dismantlement, abandonment and restoration of oil and gas
properties are recorded when incurred, generally upon acquisition or completion
of a well. The net estimated costs are discounted to present values using a
risk adjusted rate over the estimated
economic life of the oil and gas properties. Such costs are capitalized as part
of the related asset. The asset is depleted on the units-of-production method.
The associated liability is classified in other long-term liabilities in the
accompanying balance sheet. The liability is periodically adjusted to reflect
(1) new liabilities incurred, (2) liabilities settled during the period, (3)
accretion expense, and (4) revisions to estimated future cash flow requirements.
The accretion expense is recorded as a component of depreciation, depletion and
amortization expense in the accompanying statements of operations.
Income Taxes
Deferred income tax assets and liabilities are recognized for the future income
tax consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective income
tax bases. Deferred income tax assets and liabilities are measured using enacted
tax rates expected to apply to taxable income in the years in which those
temporary differences are expected to be recovered or settled. The effect on
deferred income tax assets and liabilities of a change in income tax rates is
recognized in income in the period that includes the enactment date. The
measurement of deferred income tax assets is reduced, if necessary, by a
valuation allowance if management believes that it is more likely than not that
some portion or all of the net deferred tax assets will not be fully realized on
future income tax returns. The ultimate realization of deferred tax assets is
dependent upon the generation of future taxable income during the periods in
which those temporary differences become deductible. Management considers the
scheduled reversal of deferred tax liabilities, available taxes in carryback
periods, projected future taxable income and tax planning strategies in making
this assessment.
In June 2006, the FASB issued an interpretation related to the existing
accounting for income tax guidance regarding how tax benefits claimed or
expected to be claimed on a tax return should be recorded in the financial
statements. Under this guidance, the Company may recognize the tax benefit from
an uncertain tax position only if it is more likely than not that the tax
position will be sustained on examination by the taxing authorities based on the
technical merits of the position. The tax benefits recognized in the financial
statements from such a position should be measured based on the largest benefit
that has a greater than fifty percent likelihood of being realized upon ultimate
settlement.
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 December 31, 2010 and 2009.
The Company is 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.
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.
Environmental
The Company is subject to extensive federal, state and local environmental laws
and regulations. These laws and regulations, which regularly change, regulate
the discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future economic benefit.
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for expenditures
of a non-capital nature are recorded when environmental assessment and/or
remediation is probable and the costs can be reasonably estimated. Such
liabilities are generally recorded at their undiscounted amounts unless the
amount and timing of payments is fixed or reliably determinable. The Company
believes that it is in material compliance with existing laws and regulations.
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 December 31 2010 and 2009 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 they were anti-dilutive.
Other Comprehensive Income
The Company does not have any material items of other comprehensive income for
the years ended December 31, 2010 and 2009. Therefore, total comprehensive
income (loss) is the same as net income (loss) for these periods.
Stock-Based Compensation
Stock-based compensation is measured at the grant date based on the value of the
awards and is 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.
Recently Issued Accounting Standards
In December 2008, the Securities and Exchange Commission ("SEC") revised its
requirements for oil and gas reserves estimation and disclosures and related
definitions to align them with current practices and changes in technology. In
January 2010, the Financial Accounting Standards Board ("FASB") aligned the
current oil and gas reserve estimation and disclosure requirements with those of
the SEC. Among other things, the SEC and FASB amendments replace the
single-day, year-end pricing assumption with a twelve-month average pricing
assumption with respect to reserve calculations, revise certain definitions and
allow the use of certain technologies to establish reserves. The updated
requirements are to be applied prospectively as a change in accounting principle
that is inseparable from a change in accounting estimate and are effective for
entities with annual reporting periods ending on or after December 31, 2009.
Thus, as of December 31, 2009, the Company changed its method of determining the
quantities of oil and gas reserves which impacted the amount recorded for
depreciation, depletion and amortization and the impairment evaluation for oil
and gas properties. Under the new rules, the Company prepared its oil and gas
reserve estimates as of December 31, 2009 using the average,
first-day-of-the-month price during the 12-month period ending December 31,
2009. The adoption of the new
rules was considered a change in accounting principle inseparable from a change
in accounting estimate. The Company does not believe that provisions of the new
guidance, other than pricing, significantly impacted the reserve estimates or
consolidated financial statements. The Company does not believe that it is
practicable to estimate the effect of applying the new rules on net loss, loss
per share or the amount recorded for depreciation, depletion and amortization
and the impairment evaluation for the year ended December 31, 2009.
In June 2009, the FASB issued Accounting Standards Update ("ASU") 2009-01,
Generally Accepted Accounting Principles. ASU 2009-01 established the FASB
Accounting Standards Codification ("Codification") which became the source of
authoritative accounting principles recognized by the FASB to be applied to
nongovernmental entities. On the effective date, the Codification superseded
all then-existing non-SEC accounting and reporting standards. ASU 2009-01 was
effective for interim or annual periods ending after September 30, 2009. We
adopted ASU 2009-01 for the interim period ended September 30, 2009 and adoption
had no impact on our operating results, financial position or cash flows.
In August 2009, the FASB issued ASU 2009-05, Fair Value Measurements and
Disclosures, which provides guidance on the fair value measurement of
liabilities. The update also provides clarification for circumstances in which a
quoted price in an active market for the identical liability is not available.
ASU 2009-05 was effective for interim and annual periods beginning after August
26, 2009. We adopted this provision for the year ended December 31, 2009 and
adoption had no impact on our operating results, financial position or cash
flows.
In January 2010, guidance for fair value measurements and disclosure was updated
to require additional disclosures related to transfers in and out of level 1 and
2 fair value measurements and enhanced detail in the level 3 reconciliation. The
guidance was amended to clarify the level of disaggregation required for assets
and liabilities and the disclosures required for inputs and valuation techniques
used to measure the fair value of assets and liabilities that fall in either
level 2 or level 3. The updated guidance was effective for the Company's year
beginning January 1, 2010, with the exception of the level 3 disaggregation
which will be effective for the Company's first reporting period beginning
January 1, 2011. The adoption had no impact on the Company's consolidated
financial position, results of operations or cash flows.
We have reviewed all recently issued, but not yet effective, accounting
pronouncements and do not believe the future adoption of any such pronouncements
may be expected to cause a material impact on our financial condition or the
results of our operations.
3. ACQUISITIONS AND SALES OF PROPERTIES:
-------------------------------------
Grams and Mills acquisition:
During April 2010, High Plains purchased oil and gas leases along with personal
property in 45 producing methane wells and mineral interests (the Grams and
Mills gas fields located in Campbell County, Wyoming) from an unrelated third
party for $625,000. The Company paid $150,000 in cash on the closing date and
the remaining balance of $475,000 is financed through the seller. These
properties are adjacent to fields already owned and operated by the Company, and
are subject to the terms and conditions of record regarding overriding royalties
and other interests. The seller also reserved a one-third interest in all
minerals below the Fort Union Oil Formation or 3,000 feet below the surface,
whichever is deeper. The seller also retained its ownership interest in an 8"
pipeline that crosses in part the properties being transferred.
Marathon Oil acquisition:
During November 2010, the Company purchased all of the North and South Fairway
gas fields from Pennaco Energy, a subsidiary of Marathon Oil, which included gas
leases along with personal property in 1,614 producing or idled methane wells
(located in Campbell, Johnson and Sheridan Counties, Wyoming). The Company paid
an adjusted purchase price of $30,654,813 for these assets. The gas fields
included in this sale are located in the following Wyoming Counties: Campbell,
Johnson, and Sheridan. The net leased acreage for the North and South Fairway
assets is approximately 133,000 acres.
The Marathon Oil asset acquisition qualifies as a business combination, and
therefore, the Company was required to estimate the fair value of the assets
acquired and liabilities assumed as of the acquisition date to record the
acquisition. Fair value is defined as the price that would be received to sell
an asset or paid to transfer a liability in an orderly transaction between
market participants at the measurement date.
The fair value of the acquired properties was determined based upon numerous
inputs, many of which were unobservable (which are defined as Level 3 inputs).
The significant inputs used in estimating the fair value were: (1) NYMEX natural
gas futures prices (observable), (2) projections of the estimated quantities of
natural gas reserves, (3) projections regarding rates and timing of production,
(4) projections regarding amounts and timing of future development and
abandonment costs, (5) projections regarding the amounts and timing of operating
costs and property taxes, (6) estimated risk adjusted discount rates and (7)
estimated inflation rates. The fair value of the acquisition was assigned to the
assets acquired and liabilities assumed as follows: $8.3 million to proved
properties, $11.9 million to unevaluated properties, and $10.4 million to
operating equipment. Because the estimated fair value and purchase price were
equivalent, the Company did not record goodwill or a gain related to the
acquisition.
Alpha sales:
During 2009, the Company sold the gas interest in the CH Davis #1 well for
$25,000.
During 2010, the Company received cash of $401,271 resulting from the conveyance
of all future rights to the four Eagle Butte wells and the conveyance of all
future rights to the CH Davis #1 well.
4. 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 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.
5. RELATED PARTY TRANSACTIONS:
--------------------------
2009: The Company reimbursed officers for the purchase of fixed asset additions
and other business expenses totaling $228,833. As of December 31, 2009, a total
of $473 was owed to an officer.
2010: The Company reimbursed officers for the purchase of fixed asset additions
and other business expenses totaling $229,627. As of December 31, 2010, a total
of $89,188 was owed to a related entity.
The Company transacts business with a shareholder for purchase of drilling tools
and performance of contract-based accounting services. The 2010 services
totaled $155,520 and had not been paid as of December 31, 2010.
Two officers paid loan origination fees on behalf of the Company totaling
$71,075 during 2010.
Two officers have provided personal guarantees on the Amegy Line of Credit. The
Company has valued this guarantee at $2,193,897.
See Note 12 for details of related party debt instruments.
6. 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. The fair
value of the shares was $.09 per share as of the date of transaction, or
$1,800,000. The Company also received 10,000,000 warrants that are exercisable
for 5 years at a price of $0.15 that were valued at $654,430 at the date of
transaction. The purchase price consisted of a combination of $200,000 cash and
739,180 restricted common shares of the Company valued at $510,034 for a total
value expended of $710,034.
As allowed by 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. The effect of this election is a gain of $1,744,396,
calculated as the difference between the fair value of securities received
($1,800,000 and $654,270) and the value expended ($710,034) for an initial gain
recognized in the income statement of $1,744,396.
As of December 31, 2010 the fair value of the securities remains at $.09 per
share, or $1,800,000. The fair value of the warrants has increased to $845,108
and the increase of $190,838 has been recognized in the income statement. Total
gain recognized for 2010 due to the election of fair value accounting is
$1,935,234.
7. CERTIFICATES OF DEPOSIT
-----------------------
The Company maintains certificates of deposits that have been established for
the purpose of assuring maintenance and administration of a performance bond
which secures certain plugging and abandonment
obligations assumed by the Company on its federal leases. At December 31, 2010
and 2009, the outstanding amount totaled $200,000 and $175,000, respectively.
8. SHAREHOLDER EQUITY:
------------------
As discussed in Note 1, the reorganization has been accounted for as a reverse
merger, and thus the equity structure of the predecessor entity becomes part of
the equity structure of High Plains Gas, LLC, wholly owned subsidiary of High
Plains Gas, Inc., and effectively the surviving entity.
Effectively, during 2010, the predecessor entity completed a 1 for 200 reverse
split of the issued and outstanding common shares, $.001 par value.
Effectively during 2010, the predecessor entity issued 52,000,000 common shares
to nine individuals representing 100% of the membership of High Plains Gas, LLC
and, as a result, High Plains Gas, LLC became a wholly owned subsidiary of High
Plains Gas, Inc.
During 2010, the Company issued a stock dividend of 1 for 1 share of common
stock then outstanding. A total of 65,000,011 shares were issued.
During 2009, member contributions in High Plains LLC totaled $193,986.
On January 1, 2010, five members of High Plains LLC were bought out and their
shares redeemed. The members collectively held 50 units for 47.5% ownership.
High Plains LLC gave up several oil and gas leases and cash totaling $134,000.
The leases had no recorded value as they were undeveloped, unproved and had not
been evaluated. No reserves were assigned to the leases in the 2009 reserve
study.
On January 1, 2010, member contributions in High Plains Gas, LLC totaled
$678,220.
During 2010, warrants were issued as compensation and valued at $1,052,683.
Warrants were also issued in payment for bond commitment fees and valued at
$443,897.
A promissory note was converted into 55,000 common shares valued at $41,250.
Common shares totaling 800,000 shares were issued in payment of bond commitment
fees and valued at $520,000.
During 2010, a total of 330,000 shares were issued in payment for various
corporate services valued at $230,100.
As discussed in Note 6, 739,180 common shares were issued to Big Cat Energy
Corporation at a value of $510,034.
Warrants were issued with corporate debt and valued at $725,765.
Common shares totaling 4,460,000 were issued for cash of $2,680,100.
On November 24, 2010, the Company purchased the remaining 49% of CEP-M Purchase
by issuing 22,500,000 shares of restricted common stock at $0.775 per shares and
giving Current Energy Partners a note for $1,500,000.
On December 31, 2010, Mike Hettinger, converted a note payable from the Company
for $550,000 into 1,100,000 shares of restricted common stock. The conversion
included a beneficial conversion feature valued at $275,000 and 40,000 shares of
common stock valued at $38,400.
2010
----------
Expected warrant term 2.5 to 5
- years years
.42 to
Risk-free interest rate 2.01%
Dividend Yield 0
Volatility 106%
Shares granted 4,136,420
Exercise Price 0.50
Weighted Average
remaining term 4.88
Weighted
Weighted Avg
Avg Remaining Aggregate
Number of Exercise Contractual Fair
Shares Price Term Value
---------- --------- ------------ -------------
Warrants outstanding
- January 1, 2010
Granted during period 4,136,420 $ 0.50 $ 4.88 $2,410,594.43
Exercised during period
Forfeited during period
Expired during period
---------- --------- ------------ -------------
Warrants outstanding
- December 31, 2010 4,136,420 $ 0.50 $ 4.88 $2,410,594.43
========== ========= ============ =============
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.
9. 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 December 31, 2010.
10. DEBT FINANCING - LINES OF CREDIT
--------------------------------
On October 12, 2006, the Company entered into an agreement with First Interstate
Bank for a line of credit of up to $800,000 with a maturity date of October 12,
2009. The line of credit is secured by assignments to oil
and gas production, and all inventory and account receivable and equipment. On
October 22, 2008 the agreement was modified and with a new interest rate of
9.25% and new maturity date of December 7, 2009. On December 7, 2009 the
agreement was modified to reflect a new interest rate of 6.0% per annum and a
new maturity date of October 12, 2010. The line of credit was fully paid-off
and retired in January 2010.
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, 2010. 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 account receivable
and equipment. As of December 31, 2010 the outstanding principal balance was
$125,000.
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 December 31,
2010 the outstanding principal balance was $6,000,000.
The credit facility is subject to restrictive covenants and as of December 31,
2010, the Company is not in compliance with certain of the 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 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 December 31, 2010 the outstanding principal balance was $390,202.
2010 2009
---------- --------
Total outstanding principal $6,515,203 $800,000
Current portion 6,352,579 800,000
---------- --------
Long-term portion of lines of credit $ 162,624 $ --
========== ========
Outstanding balances are due:
2011 $6,352,579
2012 162,624
2013 --
----------
$6,515,203
==========
11. DEBT FINANCING - TERM DEBT
--------------------------
On November 7, 2007, the Company entered in a term loan agreement with First
Interstate Bank of $653,250 with a maturity date of July 7, 2013. Payments are
due monthly of $12,000 which include interest at 8.25% per annum. The agreement
is secured by production and certain oil and gas assets. On May 13, 2008, the
agreement was modified to reflect a new interest rate of 6.5% per annum. The
loan was fully paid-off and retired in January 2010.
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 December 31, 2010 the outstanding
principal balance was $1,067,225.
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 December 31, 2010 the outstanding
principal balance is $37,525.
On November 23, 2010, the Company entered into a term loan agreement with CEP-M
with a maturity date of January 31, 2012. The note does not bear interest and
is unsecured. As of December 31, 2010 the outstanding principal balances is
$1,500,000.
2010 2009
---------- --------
Total outstanding principal $2,604,750 $436,563
Current portion 1,661,685 191,131
---------- --------
Long-term portion of term debt $ 943,065 $317,432
========== ========
Outstanding balances are due:
2011 $1,661,685
2012 170,122
2013 760,740
2014 9,830
2015 2,373
----------
$2,604,750
==========
12. DEBT FINANCING - RELATED PARTY DEBT
-----------------------------------
Mark Hettinger - During 2010 the Company entered into various loan agreements
with Mark Hettinger totaling $4,942,591. The loans are due on demand along with
interest at a rate of 15.0% per annum. No payments were made on these notes
during 2010 and interest totaling $102,719 has been accrued as of December 31,
2010.
Joe Hettinger - During 2010 the Company entered into various loan agreements
with Joe Hettinger totaling $417,194. The loans are due on demand along with
interest at a rate of 15.0% per annum. No payments were made on these notes
during 2010 and interest totaling $7,080 has been accrued as of December 31,
2010.
Mike Hettinger - During 2010 the Company entered into a loan agreement with Mike
Hettinger for $200,000. The loan is due on demand along with interest at a rate
of 10.0% per annum. No payments were made on this note during 2010 and interest
totaling $1,699 has been accrued as of December 30, 2010.
Mike Hettinger - During 2010, the Company entered into a convertible note
agreement with Mike Hettinger totaling $550,000. The convertible note is due on
December 31, 2010 along with interest at a rate of 10% per annum. The
conversion feature in the convertible note is considered to be a beneficial
conversion feature. We have accounted for the beneficial conversion feature in
accordance with ASC Topic 470, Liabilities. We accounted for a portion of the
proceeds, $275,000, from the convertible note which related to the intrinsic
value of the beneficial conversion feature by allocating that amount to
additional paid in capital. As described in Note 8, the convertible note was
converted into 40,000 shares of common stock.
During 2010, the Company entered into a convertible note agreement with an
individual totaling $100,000. The convertible note is due on December 31, 2010
along with interest at a rate of 10% per annum. The conversion feature in the
convertible note is considered to be a beneficial conversion feature. We have
accounted for a portion of the proceeds, $50,000, from the convertible note
which related to the intrinsic value of the beneficial conversion feature by
allocating that amount to additional paid in capital. As described in Note 8,
the convertible note was converted into 10,000 shares of common stock.
Accrued wages and compensation - During 2010 the Company accrued unpaid wages
and compensation to various related parties totaling $325,000. The amounts are
due on demand and do not include interest. No payments were made on the accrued
amounts during 2010.
Principal due to related parties was $5,963,900 and $0 and accrued interest was
$111,498 and $0 as of December 31, 2010 and 2009, respectively.
13. INCOME TAXES (NOT YET REVIEWED:
------------------------------
Deferred tax assets (liabilities) are comprised of the following:
December 31
-----------------------
2010 * 2009 *
------------- ------
Current deferred tax assets:
Fair Value Securities
Noncurrent deferred tax assets: $ (677,332)
Oil and gas property and equipment $ 566,429
Stock based compensation $ 368,439
Net operating loss $ 1,873,894
-------------
Total deferred tax assets $ 2,131,428
Valuation allowance $ (2,131,428)
-------------
$ -
=============
A reconciliation of our effective tax rate to the federal statutory tax rate of
35% is as follows:
December 31,
-----------------------
2010 * 2009 *
------------- ------
Expected benefit at federal statutory rate (35%)
State taxes net of federal benefit --
Permanent differences --
Change in valuation allowance 35%
-------------
-
=============
*Until October 18, 2010, the Company was operated as a Limited Liability
Company. As such, all income and losses were reported directly by the members
and thus there is no corporate tax effect until October 18, 2010.
The federal net operating loss (NOL) carry forward of approximately $8,590,000
as of December 31, 2010 begins to expire in 2030. Internal Revenue Code Section
382 places a limitation on the amount of taxable income which can be offset by
NOL carryforwards after a change in control (generally greater than 50% change
in ownership) of a loss corporation. Generally, after a change in control, a
loss corporation cannot
deduct NOL carryforwards in excess of the Section 382 limitation. Due to these
"change in ownership" provisions, utilization of NOL carryforwards may be
subject to an annual limitation regarding their utilization against taxable
income in future periods. We have not performed a Section 382 analysis.
However, if performed, Section 382 may be found to limit potential future
utilization of our NOL carryforwards.
We have established a full valuation allowance against the deferred tax assets
because, based on the weight of available evidence including our continued
operating losses, it is more likely than not that all of the deferred tax assets
will not be realized. Because of the full valuation allowance, no income tax
expense or benefit is reflected on the statement of operations.
14. FAIR VALUE MEASUREMENT AND DISCLOSURE
-------------------------------------
The Company has adopted ASC 820, Fair Market Measurement and Disclosures
including the application of the statement to non-recurring, non-financial
assets and liabilities. The adoption of ASC 820 did not have a material impact
on the Company's fair value measurements. ASC 820 defines fair value as the
price that would be received to sell an asset or paid to transfer a liability in
the principal or most advantageous market for the asset or liability in an
orderly transaction between market participants at the measurement date. ASC 820
establishes a fair value hierarchy, which prioritizes the inputs used in
measuring fair value into three broad levels as follows:
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.
Level 3- Unobservable inputs based on the Company's own assumptions,
The Company has elected the fair value option for reporting its investment in
securities available for sale, because the Company believes this option presents
a more realistic measure of value that may be realized by the Company if these
assets are disposed of in the ordinary course of business. The assets available
for sale consist of 20,000,000 restricted common stock of Big Cat Energy
Corporation, approximately 29.6%. It is the Company's policy to report
investments at their fair value in the balance sheet.
ASC 820 requires the use of observable market data if such data is available
without undue cost and effect.
Fair Value Measurements at Reporting Date Using
Quoted Prices
in Active Significant
Markets for Other Significant
Identical Observable Unobservable
December 31, Assets Inputs Inputs
Description 2010 (Level 1) (Level 2) (Level 3)
Securities available
for sale $ 1,800,000 $ 1,800,000 $ --- $ ---
Warrants issued w/
securities 845,108 --- --- 845,108
Total $ 2,645,108 $ 1,800,000 $ 0 $ 845,108
============= ============== ============ =============
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 table
Balance, January 1, 2010 $ -
Issued value of warrants $ 845,108
-----------
Balance, December 31, 2010 $845,108.00
There were no assets measured at fair value as of December 31, 2009.
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.
15. ASSET RETIREMENT OBLIGATION
---------------------------
Changes in the Company's asset retirement obligations were as follows:
YEAR ENDED DECEMBER 31,
2010 2009
----------- -------------
Asset retirement obligations, beginning of year $ 33,046 $ 30,907
Liabilities related to acquisitions 8,096,822 --
Revisions in estimated liabilities 39,505 --
Accretion expense 60,257 2,139
----------- -------------
Asset retirement obligations, end of year $ 8,229,630 $ 33,046
=========== =============
16. 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:
A portion of our production is sold under certain contractual arrangements that
specify the delivery of a fixed and determinable quantity. 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 December 31, 2010 we were committed to
deliver the following fixed quantities of our natural gas production:
GROSS
PIPELINE SYSTEM / DELIVERABLE DELIVERIES
TYPE OF ARRANGEMENT LOCATION MARKET (MMBTU/D) TERM
------------------- ----------------- --------------- ----------- -------------
Firm Transport WIC Medicine Bow Rocky Mountains 15,000 07/10 -11/15
Kinder Morgan
Firm Transport Trailblazer Rocky Mountains 22,500 07/10 - 05/12
Firm Transport Copano Fort Union Rocky 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.
17. SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED):
-------------------------------------------------
There are numerous uncertainties inherent in estimating quantities of proved
crude oil and natural gas reserves. Crude oil and natural gas reserve
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be precisely measured. The accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.
The Company retained Mire & Associates, independent third-party reserve
engineers, to perform an independent evaluation of proved, possible and probable
reserves as of December 31, 2009. Results of drilling, testing and production
subsequent to the date of the estimates may justify revision of such estimates.
Accordingly, reserve estimates are often different from the quantities of crude
oil and natural gas that are ultimately recovered. All of the Company's reserves
are located in the United States.
RESERVES
Total reserves are classified by degree of proof as proved, probable, or
possible. These classifications are in accordance with the reserves definitions
of Rules 4-10(a) (1)-(32) of Regulation S-X of the SEC. Reserves are judged to
be economically producible in future years from known reservoirs under existing
economic and operating conditions and assuming continuation of current
regulatory practices using conventional production methods and equipment. A
description of reserve classifications are as follows:
OIL GAS Total
(BARRELS) (MCF) MCFE
--------------------------------- --------- ----------- -----------
PROVED RESERVES
Balance - January 1, 2009 755,140 755,140
Revisions of previous estimates ( 72,552) ( 72,552)
Extensions, discoveries and -
other additions - -
Production (151,028) (151,028)
Purchase (sales) of minerals 5,020 4,390 34,510
Balance - December 31, 2009 5,020 535,950 566,070
Revisions of previous estimates (3,627) (163,582) (185,356)
Extensions, discoveries and
other additions - - -
Production (1,391) (741,115) (729,461)
Purchase (sales) of minerals 14,594,149 14,594,148
Balance - December 31, 2010 14,245,401 14,245,401
Proved oil and gas reserves-Proved oil and gas reserves are those quantities of
oil and gas which by analysis of geoscience and engineering data can be
estimated with reasonable certainty to be economically producible-from a given
date forward, from known reservoirs and under existing economic conditions,
operating methods and government regulation-prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods
are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the
project within a reasonable time.
Probable reserves-Probable reserves are those additional reserves that are less
certain to be recovered than proved reserves but which, together with proved
reserves, are as likely as not to be recovered. When deterministic methods are
used, it is as likely as not that actual remaining quantities recovered will
exceed the sum of estimated proved plus probable reserves. 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 reserves
estimates. As of December 31, 2010, Company does not have any probable
reserves.
Possible reserves-Possible reserves are those additional reserves that are less
certain to be recovered than probable reserves. When deterministic methods are
used, the total quantities ultimately recovered from a project have a low
probability of exceeding proved plus probable plus possible reserves. When
probabilistic methods are used, there should be at least a 10% probability that
the total quantities ultimately recovered will equal or exceed the proved plus
probable plus possible reserves estimates. As of December 31, 2010, the
Company does not have any possible reserves.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 2009 and 2008 in accordance with FASB ASC 932-Disclosures
about Oil and Gas Producing Activities which requires the use of a 10% discount
rate. This information is not the fair market value, nor does it represent the
expected present value of future cash flows of the Company's proved oil and gas
reserves.
2010 2009
------------- ----------
STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES
Future cash inflows $ 44,984,100 $2,198,840
Future production costs (20,289,800) 1,682,790
Future development costs (3,225,300) 135,800
Future income tax expenses - -
Future net cash flows 21,469,000 380,250
10% annual discount for
estimated timing of cash flows 4,606,400 33,140
Standardized measure of
discounted future cash flows
at the end of the year 16,862,600 347,110
SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS
Principal changes in the aggregate standardized measure of discounted future net
cash flows attributable to the Company's proved crude oil and natural gas
reserves, as required by FASB ASC 932-235, at year end are set forth in the
table below:
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED
FUTURE NET CASH FLOWS RELATING TO 2010 2009
------------ -----------
PROVED OIL AND GAS RESERVES
Standardized measure of discounted future net
cash flows at the beginning of the year $ 347,110 $ 731,610
Net changes in prices and production costs 45,591 (366,475)
Changes in estimated future development costs - -
Sales of oil and gas produced, net of production
Costs - (101,451)
Extensions, discoveries and improved recovery
less related costs 17,249,708 -
Purchases (sales) of minerals in place (113,659) 166,560
Revisions of previous quantity estimates (192,114) (192,114)
Net change in income taxes - -
Accretion of discount 34,711 108,980
Change in timing and other 435,069 -
------------ -----------
Standardized measure of discounted future net
cash flows at the end of the year $16,862,600 $ 347,110
============ ===========
18. SUBSEQUENT EVENTS:
------------------
Pursuant to FASB ASC 855, management has evaluated all events and transactions
that occurred from January 1, 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 $1,500,000. The transaction is scheduled to
close in April 2011.
On February 3, 2011, the Company executed an agreement with Stephens, Inc.
("Stephens") pursuant to which Stephens agreed to be the Company's exclusive
financial advisor in connection with a private offering of equity securities of
the Company. Stephens may also perform other investment banking services. In
consideration for their services, Stephens will receive a $15,000 retainer and
be entitled to 6.5% of the gross proceeds of the offering as an offering fee. In
addition, Stephens will receive warrants covering that number of securities
equal to 105 of the total value of securities actually sold in the offering,
exercisable for five years at an exercise price of 110% of the price of the
securities sold in the offering. The agreement is for a term of six months,
terminable at any time by either party upon 30 days written notice.
On February 24, 2011, the Company executed 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.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
HIGH PLAINS GAS, INC.
(the registrant)
By /s/ Brent M. Cook
------------------
Brent M. Cook
Chief Executive Officer
(Principal Executive Officer)
By /s/ Joseph M. Hettinger
------------------------
Joseph M. Hettinger
Chief Financial Officer
(Principal Financial and Accounting Officer)
Date: April 15, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
NAME TITLE ) DATE
)
/s/ Mark D. Hettinger Chairman ) April 15, 2011
----------------------
Mark D. Hettinger )
)
/s/ Joseph Hettinger Director ) April 15, 2011
----------------------
Joseph Hettinger )
)
/s/ Gary Davis Director ) April 15, 2011
----------------------
Gary Davis )
)
/s/ Cordell Fonnesbeck Director ) April 15, 2011
----------------------
Cordell Fonnesbeck )
)
/s/ Alan R. Smith Director April 15, 2011
----------------------
Alan R. Smith
EXHIBIT INDEX
Exhibit
No. Description
--- -----------
3.1 Articles of Incorporation; filed with the Registrant's Registration
Statement on Form SB-2,
May 19, 2005
3.2 Bylaws; filed with the Registrant's Registration Statement on Form
SB-2, May 19, 2005
3.3 Amended Articles of Incorporation - changing name from Northern
Explorations, Ltd. to High Plains Gas, Inc.; filed October 6, 2010 on Form 8-K
3.4 Unofficial restated certificate of incorporation of the registrant
as amended to date filed (on April 1, 1998) as Exhibit 4.1 to registrant's
Registration Statement on Form S-8, File Number 333-49095 and hereby
incorporated by reference.
3.5 By-laws of the registrant as amended effective October 14, 2005,
filed (on December 12, 2005) as Exhibit 3.2 to registrant's Quarterly Report on
Form 10-Q for the quarterly period ended October 31, 2005, and hereby
incorporated by reference.
3.6 Certificate of Amendment to Articles of Incorporation increasing
authorized common stock to 250,000,000 shares and including a class of
20,000,000 shares of Preferred Stock; filed on Form 8-K March 15, 2011
4.1 High Plains Gas, Inc. 2011 Employee and Consultant Stock Option
Plan; filed with Registration Statement on Form S-8 March 11, 2011
10.1 Reorganization Agreement - between Northern Explorations, Ltd.,
("NXPN") a Nevada Corporation, and High Plains Gas, LLC, a Wyoming limited
liability company ("HPG"), dated July 28, 2010; filed with the Registrant's
Current Report on Form 8-K, August 8, 2010 as Exhibit 10.1
10.2 Amendment to the Reorganization Agreement - dated July 28, 2010,
made and entered into as of September 13, 2010, by and between High Plains Gas,
LLC, a Wyoming limited liability company ("HPG"), and Northern Explorations,
LTD., In ("NXPN") a Nevada Corporation; filed on Form 8-K, October 6, 2010
10.3 Agreement - Installment or Single Payment Note, Between High
Plains Gas, LLC and U.S. Bank, dated January 20,2010 as amended; filed on Form
8-K October 22, 2010
10.4 Agreement - Mortgage Security Agreement, Financing statement and
Assignment of Production, Between High Plains Gas, LLC and Jim's Water Service,
Inc.: April 6, 2010. ; filed on Form 8-K October 22, 2010
10.5 Agreement - Master Agreement Regarding Redemption of Membership
Units By High Plains Gas, LLC, Formation of M&H Resources, LLC, And Distribution
And Assignment Of Certain Interests in Specific Oil and Gas Leases (the
"Agreement"), effective May 5, 2010; between High Plains Gas, LLC ("HPG"), its
Members. ; filed on Form 8-K October 22, 2010
10.6 Agreement - Settlement and Well Buyout Agreement, Financing
statement and Assignment of Production, between High Plains Gas, LLC and Alpha
Wyoming Land Company, LLC; dated December 9, 2010; filed on Form 8-K October
22, 2010
10.7 Amended and Restated Operations and Convertible Note Purchase
Agreement dated as of September 30, 2010 by and among High Plains Gas, LLC,
Current Energy Partners Corporation and CEP-M Purchase, LLC; filed on Form 8-K
November 22, 2010
10.8 Option Agreement dated October 31, 2010 by and between High Plains
Gas, LLC, and Current Energy Partners Corporation; filed on Form 8-K November
22, 2010
10.9 Purchase and Sale Agreement among Current Energy Partners
Corporation, CEP M Purchase LLC and Pennaco Energy, Inc. dated July 25, 2010;
filed on Form 8-K December 1, 2010
10.10 Amendment dated November 24, 2010 to Option Agreement dated
October 31, 2010 by and between High Plains Gas, LLC, and Current Energy
Partners Corporation; filed on Form 8-K December 1, 2010
10.11 Purchase and Sale Agreement dated December 10, 2010 by and
among High Plains Gas, LLC and Duramax Holdings, LLC; filed on Form 8-K
December 14, 2010
10.12 Stock Purchase Agreement dated December 8, 2010 by and among High
Plains Gas, LLC and Big Cat Energy Corporation; filed on Form 8-K December 15,
2010
10.13 Agreement between Fletcher International, Ltd. and High Plains
Gas, Inc. dated as of February 24, 2011; filed on Form 8-K March 1, 2011
10.14 Warrant Certificate for Warrants to Purchase Shares of Common
Stock of High Plains Gas, Inc. issued to Fletcher International, Ltd. on
February 24, 2011; filed on Form 8-K March 1, 2011
10.15 Purchase and Sale Agreement between J.M. Huber Corporation and
High Plains Gas, Inc. dated February 2, 2011; filed on Form 8-K March 15, 2011
10.16 Credit Agreement between CEP-M Purchase, LLC, Amegy Bank National
Association as Administrative Agent and Letter of Credit Issuer, and signatory
lenders, dated November 19, 2010; filed on Form 8-K March 24, 2011
10.17 Promissory Note issued by CEP-M Purchase, LLC to Amegy Bank
National Association dated November 19, 2010; filed on Form 8-K March 24, 2011
10.18 Security Agreement by CEP-M Purchase, LLC in favor of Amegy Bank
National Association as Collateral Agent dated November 19, 2010; filed on Form
8-K March 24, 2011
10.19 Mortgage, Security Agreement, Financing Statement and Assignment
of Production from CEP-M Purchase, LLC to Amegy Bank National Association as
Collateral Agent effective November 19, 2010; filed on Form 8-K March 24, 2011
10.20^ Employment Agreement between the Company and Mark D. Hettinger
dated as of January 1, 2011.
10.21^ Employment Agreement between the Company and Brent M. Cook dated
as of January 1, 2011.
10.22^ Employment Agreement between the Company and Joseph Hettinger
dated as of January 1, 2011.
10.23^ Employment Agreement between the Company and Brandon Hargett
dated as of January 1, 2011.
21^ Subsidiaries of registrant.
31.1^ Certification of the Chief Executive Officer pursuant to Section
302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a) or Rule 15d-14(a)).
31.2^ Certification of the Chief Financial Officer pursuant to Section
302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a) or Rule 15d-14(a)).
32.1+ Certification by the Chief Executive Officer of High Plains Gas,
Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350).
32.2+ Certification by the Chief Financial Officer of High Plains Gas,
Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350).
^ to be filed by amendment
+ Furnished herewith
