Table of Contents
UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the
quarterly period ended March 31, 2010
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the
transition period from
to
Commission
file number: 001-33457
Pinnacle
Gas Resources, Inc.
(Exact
name of registrant as specified in its charter)
Delaware
|
|
30-0182582
|
(State or other
jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer
Identification No.)
|
|
|
|
1 E.
Alger Street
|
|
|
Sheridan,
WY
|
|
82801
|
(Address of principal
executive offices)
|
|
(Zip code)
|
(307)
673-9710
(Registrants telephone
number, including area code)
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
o
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 (§232.405 of this chapter) during the preceding 12 months (or
for such shorter period that the registrant was required to submit and post
such files). Yes
o
No
o
Indicate by check mark whether the registrant is a
large accelerated filer, an accelerated filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of large accelerated filer, accelerated
filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large Accelerated
Filer
o
|
|
Accelerated Filer
o
|
|
|
|
Non-Accelerated
Filer
o
|
|
Smaller reporting
company
x
|
Indicate by check mark whether the registrant is a
shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
o
No
x
30,319,792 shares of the registrants Common Stock
were outstanding as of May 14, 2010.
Table
of Contents
CAUTIONARY STATEMENT CONCERNING
FORWARD-LOOKING STATEMENTS
We are including the
following discussion to inform you of some of the risks and uncertainties that
can affect our company and to take advantage of the safe harbor protection
for forward-looking statements that applicable federal securities law affords.
Various statements in this quarterly report on Form 10-Q, including those
that express a belief, expectation, or intention, as well as those that are not
statements of historical fact, are forward-looking statements. These include
statements relating to such matters as:
·
our financial position or operating results;
·
projections and estimates concerning the timing and success of specific
projects;
·
our business strategy;
·
our budget;
·
the amount, nature and timing of capital expenditures;
·
the drilling of wells;
·
the development of natural gas and oil properties and commercial potential of
these properties;
·
the timing and amount of future production of natural gas and oil;
·
our operating costs and other expenses;
·
our estimated future net revenues from natural gas and oil reserves and the
present value thereof;
·
our cash flow and anticipated liquidity; and
·
our other plans and objectives
for future operations.
When we use the words believe,
intend, expect, may, should, anticipate, could, estimate, plan,
predict, project, their negatives, or other similar expressions, the
statements which include those words are usually forward-looking statements.
When we describe strategy that involves risks or uncertainties, we are making
forward-looking statements. The forward-looking statements in this quarterly
report on Form 10-Q speak only as of the date of this report. We disclaim
any obligation to update these statements unless required by securities law,
and we caution you not to rely on them unduly. We have based these
forward-looking statements on our current expectations and assumptions about
future events. While our management considers these expectations and
assumptions to be reasonable, they are inherently subject to significant
business, economic, competitive, regulatory and other risks, contingencies and
uncertainties, most of which are difficult to predict and many of which are
beyond our control. These risks, contingencies and uncertainties relate to,
among other matters, the following:
·
the availability of
capital;
·
fluctuations in the
commodity prices for natural gas and crude oil and their related effects, including
on cash flows and potential impairments of oil and gas properties;
·
regional price
differentials;
2
Table
of Contents
·
the extent of our
success in discovering, developing and producing reserves, including the risks
inherent in exploration and development drilling, well completion and
other development activities;
·
the lack of liquidity
of our equity securities;
·
the
substantial
capital
expenditures required for construction of pipelines and the drilling of wells
and the related need to fund such capital requirements through commercial banks
and/or public securities markets;
·
engineering, mechanical or
technological difficulties with operational equipment, in well completions and
workovers, and in drilling new wells;
·
the effects of government regulation and permitting and other legal
requirements;
·
the uncertainty inherent in estimating future natural gas and oil production or
reserves;
·
production variances from expectations;
·
our ability to develop and replace reserves;
·
operating hazards attendant to the natural gas and oil business, including
down-hole drilling and
completion risks that are generally not recoverable
from third parties or insurance;
·
potential mechanical failure or under-performance of significant wells;
·
environmental-related problems;
·
the availability and cost of materials and equipment;
·
our dependence upon key personnel;
·
our ability to find and retain skilled personnel;
·
delays in anticipated start-up dates;
·
disruptions of, capacity constraints in or other limitations on our or others
pipeline systems;
·
land issues and the costs associated with perfecting title for natural gas
rights in some of our properties;
·
our ability to effectively market our production;
·
competition from, and the strength and financial resources of, our competitors;
and
·
general economic conditions.
When you consider these
forward-looking statements, you should keep in mind these factors and the other
factors discussed under the Risk Factors sections of our annual report on Form 10-K
for the year ended December 31, 2009 and this quarterly report on Form 10-Q.
3
Table
of Contents
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PINNACLE
GAS RESOURCES, INC.
Balance Sheets
|
|
March 31,
2010
|
|
December 31,
2009
|
|
|
|
(unaudited)
|
|
(audited)
|
|
|
|
(in thousands, except
share and
per share data)
|
|
Assets
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
468
|
|
$
|
175
|
|
Receivables
|
|
|
|
|
|
Accrued gas
sales
|
|
1,326
|
|
1,240
|
|
Joint interest
receivables, net of $14 and $100, respectively, allowance for doubtful
accounts
|
|
1,508
|
|
1,207
|
|
Derivative
instruments
|
|
1,513
|
|
|
|
Inventory of
material held for exploration and development
|
|
56
|
|
229
|
|
Restricted
certificates of deposits
|
|
|
|
142
|
|
Prepaid expenses
|
|
77
|
|
134
|
|
Total current
assets
|
|
4,948
|
|
3,127
|
|
Property and
equipment, at cost, net of accumulated depreciation
|
|
724
|
|
1,055
|
|
Oil and gas
properties, using full cost accounting, net of accumulated depletion and
impairment
|
|
|
|
|
|
Proved
|
|
9,280
|
|
9,477
|
|
Unproved
|
|
49,082
|
|
48,700
|
|
Inventory of
material held for exploration and development
|
|
389
|
|
223
|
|
Deposits
|
|
57
|
|
76
|
|
Restricted
certificates of deposit
|
|
1,976
|
|
1,842
|
|
Total assets
|
|
$
|
66,456
|
|
$
|
64,500
|
|
Liabilities and Stockholders
Equity
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
Long term debt,
current
|
|
5,555
|
|
6,148
|
|
Derivative
instruments, current
|
|
|
|
1,375
|
|
Trade accounts
payable
|
|
9,809
|
|
9,058
|
|
Revenue
distribution payable
|
|
4,577
|
|
3,328
|
|
Drilling
prepayments from joint interest owners
|
|
61
|
|
63
|
|
Asset retirement
obligation, current
|
|
710
|
|
721
|
|
Accrued liabilities
|
|
3,406
|
|
3,090
|
|
Total current
liabilities
|
|
24,118
|
|
23,783
|
|
Asset retirement
obligation, non-current
|
|
2,249
|
|
2,216
|
|
Production
taxes, non-current
|
|
665
|
|
385
|
|
Long term debt,
non-current
|
|
748
|
|
743
|
|
Total
liabilities
|
|
27,780
|
|
27,127
|
|
Commitments and
contingencies
|
|
|
|
|
|
Stockholders
equity
|
|
|
|
|
|
Common stock,
$0.01 par value; 100,000,000 authorized and 30,320,525 and 30,108,023 shares
issued and outstanding at March 31, 2010 and December 31, 2009,
respectively
|
|
289
|
|
289
|
|
Additional
paid-in capital
|
|
151,879
|
|
151,725
|
|
Accumulated
deficit
|
|
(113,492
|
)
|
(114,641
|
)
|
Total
stockholders equity
|
|
38,676
|
|
37,373
|
|
Total
liabilities and stockholders equity
|
|
$
|
66,456
|
|
$
|
64,500
|
|
See Notes to Financial Statements (unaudited)
4
Table
of Contents
PINNACLE
GAS RESOURCES, INC.
Statements of Operations
(unaudited)
|
|
Three Months Ended
March 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
(in thousands, except share and
per share data)
|
|
Revenues
|
|
|
|
|
|
Gas sales
|
|
$
|
2,846
|
|
$
|
2,766
|
|
Realized
gain/(loss) on derivatives
|
|
(466
|
)
|
1,457
|
|
Total revenues
|
|
2,380
|
|
4,223
|
|
Cost of revenues
and expenses
|
|
|
|
|
|
Lease operating
expenses
|
|
1,018
|
|
1,185
|
|
Production taxes
|
|
318
|
|
279
|
|
Marketing and
transportation
|
|
723
|
|
1,250
|
|
General and
administrative, net
|
|
1,407
|
|
1,031
|
|
Depreciation,
depletion, amortization and accretion
|
|
715
|
|
1,828
|
|
Impairment of
oil and gas properties
|
|
|
|
16,819
|
|
Total cost of
revenues and expenses
|
|
4,181
|
|
22,392
|
|
Operating loss
|
|
(1,801
|
)
|
(18,169
|
)
|
Other income
(expense)
|
|
|
|
|
|
Unrealized gain
on derivatives
|
|
2,888
|
|
571
|
|
Interest income
|
|
14
|
|
8
|
|
Other income
|
|
145
|
|
105
|
|
Interest expense
|
|
(97
|
)
|
(25
|
)
|
Total other
income
|
|
2,950
|
|
659
|
|
Net
income/(loss) before income taxes
|
|
1,149
|
|
(17,510
|
)
|
Income taxes
|
|
|
|
|
|
Net
income/(loss) attributable to common stockholders
|
|
1,149
|
|
(17,510
|
)
|
Basic and
diluted net income/(loss) per share
|
|
$
|
0.04
|
|
$
|
(0.60
|
)
|
Weighted average
shares outstanding basic
|
|
30,247,330
|
|
29,191,684
|
|
Weighted average
shares outstanding diluted
|
|
31,089,610
|
|
29,191,684
|
|
See Notes to Financial Statements (unaudited)
5
Table
of Contents
PINNACLE GAS RESOURCES, INC.
Statements of Cash Flows
(unaudited)
|
|
Three
Months Ended
March 31,
|
|
|
|
2010
|
|
2009
|
|
Cash flows from
operating activities
|
|
|
|
|
|
Net
income/(loss)
|
|
$
|
1,149
|
|
$
|
(17,510
|
)
|
Adjustments to
reconcile net loss to net cash provided by operating activities
|
|
|
|
|
|
Impairment of
oil and gas properties
|
|
|
|
16,819
|
|
Depreciation,
depletion, amortization and accretion
|
|
715
|
|
1,828
|
|
Gain on
derivatives
|
|
(2,422
|
)
|
(2,028
|
)
|
Stock-based
compensation
|
|
154
|
|
199
|
|
Changes in
assets and liabilities
|
|
|
|
|
|
Decrease
(increase) in receivables
|
|
(387
|
)
|
1,257
|
|
Decrease
(increase) in inventory of material held for exploration and development
|
|
173
|
|
(1
|
)
|
Asset retirement
obligation settled this period
|
|
(31
|
)
|
|
|
Decrease in
prepaid expenses
|
|
57
|
|
86
|
|
Increase in
trade accounts payable, accrued liabilities and production taxes
|
|
1,095
|
|
1,366
|
|
Increase
(decrease) in revenue distribution payable
|
|
1,249
|
|
(1,293
|
)
|
Net cash
provided by operating activities
|
|
1,752
|
|
723
|
|
Cash flows from
investing activities
|
|
|
|
|
|
Capital
expenditures exploration and production
|
|
(239
|
)
|
(1,398
|
)
|
Capital
expenditures property and equipment
|
|
(27
|
)
|
(1
|
)
|
Decrease
(increase) in purchase of restricted certificates of deposit and deposits
|
|
27
|
|
(5
|
)
|
Increase in
inventory held for exploration and development
|
|
(166
|
)
|
(4
|
)
|
Realized gain
(loss) on derivatives
|
|
(466
|
)
|
1,457
|
|
Net cash (used
in) / provided by investing activities
|
|
(871
|
)
|
49
|
|
Cash flows from
financing activities
|
|
|
|
|
|
Principal
payments on long term debt
|
|
(588
|
)
|
(1,007
|
)
|
Net cash used in
financing activities
|
|
(588
|
)
|
(1,007
|
)
|
Net
increase/(decrease) in cash and cash equivalents
|
|
293
|
|
(235
|
)
|
Cash and cash
equivalents at beginning of quarter
|
|
175
|
|
346
|
|
Cash and cash
equivalents at end of quarter
|
|
$
|
468
|
|
$
|
111
|
|
Noncash
investing and financing activities
|
|
|
|
|
|
Capital
expenditures included in trade accounts payable
|
|
$
|
6,659
|
|
$
|
6,951
|
|
Asset retirement
obligations included in oil and gas properties
|
|
1
|
|
|
|
Supplemental
cash flow information
|
|
|
|
|
|
Cash payments
for interest, net of amount capitalized
|
|
$
|
97
|
|
$
|
25
|
|
See Notes to Financial Statements (unaudited)
6
Table
of Contents
Statements of Stockholders Equity
|
|
Common
Stock
|
|
Additional
Paid-In
|
|
Accumulated
|
|
|
|
|
|
Shares
|
|
Amount
|
|
Capital
|
|
Deficit
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
30,108,023
|
|
$
|
289
|
|
$
|
151,725
|
|
$
|
(114,641
|
)
|
$
|
37,373
|
|
Issuance of restricted share
|
|
212,502
|
|
|
|
$
|
128
|
|
|
|
128
|
|
Stock-based compensation
|
|
|
|
|
|
26
|
|
|
|
26
|
|
Net income
|
|
|
|
|
|
|
|
1,149
|
|
1,149
|
|
Balance at March 31, 2010 (unaudited)
|
|
30,320,525
|
|
$
|
289
|
|
$
|
151,879
|
|
$
|
(113,492
|
)
|
$
|
38,676
|
|
See Notes to Financial
Statements (unaudited)
7
Table
of Contents
Notes to Financial Statements
Unaudited
Note 1 Organization and Nature of Operations
Pinnacle Gas
Resources, Inc. (the Company) was formed as a Delaware corporation in June 2003
through a contribution of cash by funds affiliated with DLJ Merchant Banking
and oil and gas reserves and leasehold interests by subsidiaries of Carrizo Oil &
Gas, Inc. and U.S. Energy Corporation.
The Companys
primary business is the exploration for, and the acquisition, development and
production of, coalbed methane natural gas in the United States. The Company is
also engaged in gas property operations and the construction of low pressure
gas collection systems which provide transportation for the Companys coalbed
methane production.
Due to the current economic and pricing environment,
the Company is actively marketing certain assets to raise additional capital
and is also reviewing alternatives for raising additional capital through
equity and debt financing, capital restructuring and possible mergers. The Company has executed hedges of its gas to
secure certain operating cash flow levels during the remainder of 2010. From January through
April 2010, the Company had 5,500 MMbtu per day hedged through fixed price
swaps at a weighted average price of $4.19 per MMbtu. From May through December 2010, the
Company has 5,500 MMbtu per day hedged through fixed price swaps at a weighted
average price of $5.08 per MMbtu. The Company has also implemented various cost
cutting measures, including reducing general and administrative costs through
staff reductions, wage and benefit cuts and a hiring freeze. The Company has
reduced lease operating expenses by renegotiating water disposal contracts,
reducing service costs and temporarily shutting-in marginal wells.
The Company continues to
communicate with key vendors to manage its obligations and payables. The
Company has entered into agreements with various vendors to make minimum
monthly payments ranging from $1,000 to $45,000 at interest rates between 2%
and 12% for the remainder of 2010. Management believes that appropriate steps,
including cost-cutting measures, are being taken to make operations sustainable
in the future.
On February 23, 2010,
the Company entered into an Agreement and Plan of Merger with Powder Holdings,
LLC, a Delaware limited liability company and Powder Acquisition Co., a
Delaware corporation and a direct, wholly owned subsidiary of Powder Holdings. Powder Holdings is controlled by an investor
group led by Scotia Waterous (USA) Inc. and includes certain members of the
Companys management team. On April 2, 2010, the Company filed a preliminary
proxy statement relating to the merger, with the U.S. Securities and Exchange Commission. Although the Company is pursuing various
alternatives to provide additional liquidity, there is no assurance of the
likelihood or timing of any of these transactions.
Note 2 Basis of Presentation
The accompanying
unaudited financial statements include the Companys proportionate share of
assets, liabilities, income and expenses from the properties in which the
Company has a participating interest.
The Company has no subsidiaries or affiliates with which intercompany
transactions are recorded.
The accompanying
financial statements are unaudited, and in the opinion of management, reflect
all adjustments that are necessary for a fair presentation of the financial
position and results of operations for the periods presented. All such adjustments are of a normal and
recurring nature. The following Notes describe only the material changes in
accounting policies, account details, or financial statement Notes during the
first three months of 2010. The results
for the three months ending March 31, 2010 are not necessarily indicative
of the results expected for the entire year.
These financial statements should be read in conjunction with the
audited financial statements and the summary of significant accounting policies
for prior years contained in the reports the Company files with the Securities
and Exchange Commission, which can be found on the Companys website at
www.pinnaclegas.com
.
Use of Estimates
The preparation of
the Companys financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amount of assets and
liabilities, 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 could differ from these estimates.
Significant estimates with regard to the Companys financial statements include
the estimated carrying value of unproved properties, the estimate of proved oil
and gas reserve volumes and the related present value of estimated future net
cash flows, the ceiling test applied to capitalized oil and gas properties, the
estimate of the timing and cost of the Companys future drilling activity,
8
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the estimated cost and
timing related to asset retirement obligations, the estimated fair value of derivative
assets and liabilities, the realizability of deferred tax assets, the estimates
of expenses and timing of exercise of stock options, accrual of operating costs
and capital expenditures and revenue.
Oil and Gas Properties
The Company utilizes the full cost method of
accounting for oil and gas producing activities. Under this method, all costs
associated with property acquisition, exploration and development, including
costs of unsuccessful exploration, costs of surrendered and abandoned leaseholds,
delay lease rentals and the fair value of estimated future costs of site
restoration, dismantlement and abandonment activities are capitalized within a
cost center. The Companys oil and gas properties are all located within the
United States, which constitutes a single cost center. The Company capitalizes
lease operating expenses associated with exploration and development of
unevaluated oil and gas properties. No gain or loss is recognized upon the sale
or abandonment of undeveloped or producing oil and gas properties unless the
sale represents a significant portion of gas properties and the gain
significantly alters the relationship between capitalized costs and proved gas
reserves of the cost center. Expenditures for maintenance and repairs are charged
to lease operating expense in the period incurred.
Depreciation, depletion and amortization of oil and
gas properties (DD&A) is computed on the unit-of-production method based
on proved reserves. Amortizable costs include estimates of future development
costs of proved undeveloped reserves and asset retirement obligations. The
Company invests in unevaluated oil and gas properties for the purpose of
exploration for proved reserves. The costs of such assets, including
exploration costs on properties where a determination of whether proved oil and
gas reserves will be established is still under evaluation, and any capitalized
interest and lease operating expenses are included in unproved oil and gas
properties at the lower of cost or estimated fair market value and are not
subject to amortization. On a quarterly basis, such costs are evaluated for
inclusion in the costs to be amortized resulting from the determination of
proved reserves, impairments, or reductions in value. To the extent that the
evaluation indicates these properties are impaired, the amount of the
impairment is added to the capitalized costs to be amortized. Abandonment of
unproved properties is accounted for as an adjustment to capitalized costs
related to proved oil and gas properties, with no losses recognized. The
Company recorded an impairment of unevaluated properties of $0 million and
$36.7 million for the three months ended March 31, 2010 and year ended December 31,
2009, respectively. Abandonment of unproved properties is also accounted for as
an adjustment to capitalized costs related to proved oil and gas properties. If
the adjustment to capitalized costs related to proved oil and gas properties
results in the capitalized costs exceeding the full cost ceiling limitations,
the excess must be charged to expense.
Substantially all of the remaining unproved properties
are expected to be developed and included in the amortization base over the
next three to five years, based on projected cash flow from operations combined
with raising additional capital. Salvage value is taken into account in
determining depletion rates and is based on the Companys estimate of the value
of equipment and supplies at the time the well is abandoned. The estimated
salvage value of equipment included in determining the depletion rate was $6.8
million and $7.2 million as of March 31, 2010 and 2009, respectively.
Under the full cost method of accounting rules,
capitalized costs less accumulated depletion and related deferred income taxes
may not exceed a ceiling value which is the sum of (1) the present
value discounted at 10% of estimated future net revenue using current costs and
first day of the month twelve month average CIG prices, including the effects
of derivative instruments designated as cash flow hedges but excluding the
future cash outflows associated with settling asset retirement obligations that
have been accrued on the balance sheet, less any related income tax effects;
plus (2) the cost of properties not being amortized, if any; plus (3) the
lower of costs or estimated fair value of unproved properties; less (4) the
income tax effects related to differences in the book to tax basis of oil and
gas properties. This is referred to as the full cost ceiling limitation. If
capitalized costs exceed the limit, the excess must be charged to expense. The
expense may not be reversed in future periods. At the end of each quarter, the
Company calculates the full cost ceiling limitation. At March 31, 2010,
the full cost ceiling limitation exceeded the capitalized cost of the Companys
oil and gas properties by approximately $4.1 million based on the first day of
the month, twelve month average CIG price of approximately $3.48 per Mcf.
Therefore, no impairment was taken for the quarter ended March 31, 2010.
An impairment of $16.8 million was taken for the quarter ended March 31,
2009 based on a natural gas price of $3.31 per Mcf.
Per Share Information
Basic earnings (loss) per share is computed by
dividing net income (loss) from continuing operations attributable to common
stock by the weighted average number of shares of common stock outstanding
during each period. Diluted earnings
9
Table
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per share are computed by adjusting the average number
of shares of common stock outstanding for the dilutive effect, if any, of
common stock equivalents such as stock options and warrants. For the three
months ended March 31, 2010, diluted net income per share was $0.04, and
basic net income per share was $0.04. During the three months ended March 31,
2009, 645,000 options were excluded because they were anti-dilutive.
(In thousands except per
share data)
|
|
For the Three
Months Ended
March 31,
|
|
|
|
2010
|
|
2009
|
|
Net
income/(loss)
|
|
$
|
1,149
|
|
$
|
(17,510
|
)
|
Common
shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
Historical
common shares outstanding at beginning of period
|
|
30,108
|
|
29,194
|
|
Weighted
average common shares issued
|
|
139
|
|
(2
|
)
|
Weighted
average common shares outstanding-basic
|
|
30,247
|
|
29,192
|
|
Effect
of dilution stock options
|
|
843
|
|
|
|
|
|
|
|
|
|
Weighted
average common shares outstanding-diluted
|
|
31,090
|
|
29,192
|
|
Net
income/(loss) per share-basic
|
|
$
|
.04
|
|
$
|
(.60
|
)
|
Net
income/(loss) per share-diluted
|
|
$
|
.04
|
|
$
|
(.60
|
)
|
Income Taxes
The Company uses the asset and liability method of
accounting for income taxes. Deferred tax assets and liabilities are recognized
for the expected future tax consequences of temporary differences between the
financial statement and tax bases of assets and liabilities. If appropriate,
deferred tax assets are reduced by a valuation allowance which reflects
expectations of the extent to which such assets will be realized. As of March 31,
2010 and December 31, 2009, the Company had recorded a full valuation
allowance for its net deferred tax asset.
New Accounting Pronouncements
In September 2006,
the FASB issued accounting guidance related to fair value measurements and
related disclosures. This new guidance defines fair value, establishes a
framework for measuring fair value, and expands disclosures about fair value
measurements. The Company adopted this guidance on January 1, 2008, as
required for its financial assets and financial liabilities. However, the FASB
deferred the effective date of this guidance for one year as it relates to fair
value measurement requirements for nonfinancial assets and nonfinancial
liabilities that are not recognized or disclosed at fair value on a recurring
basis, which include, among others, those nonfinancial long-lived assets
measured at fair value for impairment assessment and asset retirement
obligations initially measured at fair value. Fair value used in the initial
recognition of asset retirement obligations is determined based on the present
value of expected future dismantlement costs incorporating the Companys
estimate of inputs used by industry participants when valuing similar
liabilities. Accordingly, the fair value is based on unobservable pricing
inputs and therefore, is considered a level 3 value input in the fair
value hierarchy.
In April 2009,
the FASB issued accounting guidance relating to determining fair value when the
volume and level of activity for the asset or liability have significantly
decreased and identifying transactions that are not orderly, which provides
additional guidance for estimating fair value. The Company has considered this
guidance provided in its determination of estimated fair values as of December 31,
2009.
In June 2009,
the Financial Accounting Standards Board (FASB) issued FASB Accounting
Standards Codification (Codification), as the single source of authoritative
US GAAP for all non-governmental entities, with the exception of the SEC
and its staff. The Codification, which became effective July 1, 2009,
changes the referencing and organization of accounting guidance and is
effective for interim and annual periods ending after September 15, 2009.
The
10
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Company adopted the
Codification on July 1, 2009 which provides for changes in references to
technical accounting literature in the accompanying financial statements, but
did not have a material impact on the Companys financial position, results of
operations or cash flows.
In June 2009,
the FASB issued new accounting guidance related to the accounting and
disclosures of subsequent events. This guidance incorporates the subsequent
events guidance contained in the auditing standards literature into
authoritative accounting literature.
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 FASB issued Accounting Standards Update (ASU) No. 2010-03 Oil and Gas
Reserve Estimation and Disclosure, which aligns the current oil and gas
reserve estimation and disclosure requirements with those of the SEC. As
discussed earlier, the Company follows the full-cost method of accounting for
which the SEC provides guidance. Among other things, the SEC and FASB
amendments replace the single-day, year-end pricing assumption with a
twelve-month average pricing assumption, revise certain definitions and allow
the use of certain technologies to establish reserves.
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 ceiling test calculation 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. In prior years, the Company used the
year-end price. The Company calculates depreciation, depletion and amortization
on a quarterly basis using estimated reserves as of the end of each quarter. As
a result, the new rules impacted the amount of depreciation, depletion and
amortization recorded for oil and gas properties and the ceiling test
calculation for the quarter ended December 31, 2009. In addition, under
the new guidance, subsequent price increases cannot be considered in the
ceiling test calculation.
The adoption of
the new rules is 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 financial statements. The Company does not believe that it
is practicable to estimate the effect of applying the new rules on net
loss or the amounts recorded for depreciation, depletion and amortization and
ceiling impairment for the year ended December 31, 2009.
The
Company adopted FASB ASC Update 2010-06, Fair Value Measurements and
Disclosures which amends ASC Update 2010-06 to require additional disclosures
concerning transfers between Levels 1 and 2, inputs and valuation techniques
used to value Level 2 and 3 measurements, and push down of previously
prescribed fair value disclosures to each class of asset and liability for
Levels 1, 2, and 3. These disclosures were effective for the Company for
the quarter ended March 31, 2010. The adoption of this
pronouncement did not have a material impact on the Companys consolidated
financial statements.
In
addition, ASC Update 2010-06 requires that purchases, sales, issuances, and
settlements for Level 3 measurements be disclosed. This portion of the
new authoritative guidance is effective for interim and annual reporting
periods beginning after December 15, 2010. As such, the Company will
apply this new authoritative guidance in the Companys March 31, 2011,
Quarterly Report on Form 10-Q. The adoption of ASC Update 2010-06
will not have a material impact on the Companys financial statements.
The
Company adopted FASB ASC Update 2010-09, Amendments to Certain Recognition and
Disclosure Requirements,
which
eliminates the requirement for SEC filers to disclose the date through which an
entity has evaluated subsequent events. ASU No. 2010-09 was
effective upon issuance and its adoption had no impact on the Companys financial
position, results of operations or cash flows.
Note 3
Asset Retirement Obligations
The Company
follows certain accounting provisions that apply to legal obligations
associated with the retirement of long-lived assets that result from the
acquisition, construction, development and/or the normal operation of a
long-lived asset. These provisions require the Company to recognize an
estimated liability for costs associated with the abandonment of its oil and
gas properties.
11
Table
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A liability for
the fair value of an asset retirement obligation with a corresponding increase
to the carrying value of the related long-lived asset is recorded at the time a
well is completed or acquired. The increased carrying value is depleted using
the units-of-production method, and the discounted liability is increased
through accretion over the remaining life of the respective oil and gas
properties.
The estimated
liability is based on historical gas industry experience in abandoning wells,
including estimated economic lives, external estimates as to the cost to
abandon the wells in the future and federal and state regulatory requirements.
The Companys liability is discounted using its best estimate of its
credit-adjusted risk-free rate. Revisions to the liability could occur due to
changes in estimated abandonment costs, changes in well economic lives or if
federal or state regulators enact new requirements regarding the abandonment of
wells.
The following is a
summary of the Companys asset retirement obligation activity for the three
months ended March 31, 2010 and 2009 (in thousands):
|
|
Three
Months Ended
March 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
(unaudited)
|
|
Beginning
balance asset retirement obligations
|
|
$
|
2,937
|
|
$
|
3,366
|
|
Additional
obligation added during the period
|
|
1
|
|
|
|
Obligations
settled during the period
|
|
(31
|
)
|
|
|
Accretion
expense
|
|
52
|
|
56
|
|
Ending balance
of asset retirement obligations
|
|
$
|
2,959
|
|
$
|
3,422
|
|
Note 4
Restricted Assets (Certificates of Deposit) and Deposits
Certificates of Deposit.
The Company holds
a certificate of deposit (CD), which expires in July 2010, totaling
$160,000. The CD is collateral for bonding required by the State of Wyoming,
the State of Montana and the Federal Bureau of Land Management. Because the
Company intends to renew the CD in order to maintain its bonding requirements,
the Company has included the CD in other non-current assets as of March 31,
2010. The issuer of the bonds has commenced litigation against the Company to
increase its collateral position, although this litigation has now been resolved
(see Note 9). Additionally, the Company holds two CDs for $604,000 and $964,000
which were issued in February 2006 and renewed annually. The $604,000 CD expired on February 14,
2010; a new CD in the amount of $513,000 was obtained on February 19, 2010
and will expire in February 2011.
The $964,000 CD expires in May, 2010. These CDs collateralize letters of
credit in favor of Powder River Energy Corporation, a local rural electric
association, in order to secure power lines to the Kirby, Deer Creek and Cabin
Creek areas. The Company has included these amounts in non-current assets as of
March 31, 2010 because the Company also intends to renew the CDs in order
to maintain power supply on a long-term basis.
In March 2010 the Company also posted a security deposit to Powder
River Energy Corp. of approximately $225,000 to collateralize electrical usage
in its Kirby, Deer Creek and Cabin Creek areas. In April 2007, the Company
issued a $1,000,000 letter of credit (LOC), which was collateralized by a CD
in favor of Bitter Creek Pipelines, LLC to secure the construction of a
high pressure pipeline and related compression facilities to the Companys Deer
Creek and Kirby areas. Bitter Creek Pipelines, LLC has drawn approximately
$858,000 on this LOC for compression services provided to the Company in the
third and fourth quarters of 2009. In January of 2010, Bitter Creek
Pipelines, LLC drew the remaining balance of the CD collateralizing this
LOC.
Surety
Bonds.
From June 2009
through March 31, 2010, the Company posted idle well surety for
approximately $64,000 to the Wyoming Oil and Gas Conservation Commission. The
Commission has requested the Company make 18 monthly installments of
$12,777 for surety on wells that will need to be plugged by the Company. The
surety amount may be adjusted downward by the Commission if the Company
successfully plugs the proposed wells in question. In addition, the Company has
included a $50,000 payment for bonding requirements in the Companys Kirby
Montana area.
12
Table
of Contents
Deposits.
The Company has
included approximately $57,000 related to royalty payments in deposits. These
amounts are included in Deposits in the accompanying balance sheet at March 31,
2010.
Note 5 Derivatives
The Company has
elected not to designate its derivatives as cash flow hedges under
authoritative guidance prescribed by the FASB. These derivative instruments are
marked to market at the end of each reporting period and changes in the fair
value are recorded in the accompanying statements of operations. The aggregate
fair values of these contracts were estimated to be an asset totaling
$1,513,000 and an asset of $4,916,000 at March 31, 2010 and 2009, respectively.
The Company realized a hedging loss of $466,000 and a hedging gain of
$1,457,000 for the quarters ended March 31, 2010 and 2009, respectively. As a
result of the change in the fair value of the commodity derivatives, the
Company had an unrealized gain of $2,889,000 for the quarter ended March 31,
2010 and unrealized gain of $571,000 for the quarter ended March 31, 2009.
Unrealized and realized gains and losses are included in gains or losses on
derivatives in the statement of operations. As of March 31, 2010 and 2009, the
Company had natural gas hedges in place as follows:
Product and Type of Hedging Contract
|
|
MMbtu Per
Day
|
|
Fixed Price
Range
CIG Index Price
|
|
Time
Period
|
|
March 31,
2010 (unaudited)
|
|
|
|
|
|
|
|
Natural GasSwap
|
|
2,500
|
|
$
|
3.45
|
|
01/10-04/10
|
|
Natural GasSwap
|
|
2,000
|
|
$
|
4.48
|
|
01/10-12/10
|
|
Natural GasSwap
|
|
1,000
|
|
$
|
5.50
|
|
01/10-1210
|
|
Natural GasSwap
|
|
2,500
|
|
$
|
5.40
|
|
05/10-12/10
|
|
March 31,
2009 (unaudited)
|
|
|
|
|
|
|
|
Natural
GasCollar
|
|
2,000
|
|
$
|
6.50-$7.50
|
|
01/09-12/09
|
|
Natural
GasSwap
|
|
2,500
|
|
$
|
7.17
|
|
01/09-12/09
|
|
Natural
GasSwap
|
|
2,500
|
|
$
|
3.45
|
|
05/09-04/10
|
|
Natural
GasSwap
|
|
2,000
|
|
$
|
4.48
|
|
01/10-12/10
|
|
|
|
Location on
Consolidated Balance
Sheets
|
|
Fair Value at
March 31, 2010
|
|
|
|
|
|
(In thousands)
|
|
Derivative
Assets:
|
|
|
|
|
|
Natural
gas, commodity swaps
|
|
Current asset
|
|
$
|
1,513
|
|
|
|
|
|
|
|
Total
derivative assets
|
|
|
|
$
|
1,513
|
|
The Company is
exposed to credit risk to the extent of nonperformance by the counterparties in
the derivative contracts discussed above; however, the Company does not
anticipate such nonperformance.
Note 6 Stock Based Compensation
Options under Employee Option Plans
The
Company has adopted a stock incentive plan authorizing the grant of both
incentive and non-statutory stock options. All options allow for the purchase
of common stock at prices not less than the fair market value of such stock at
the date of grant. If the option holder owns more than 10% of the total
combined voting power of all classes of the Companys stock, the exercise price
cannot be less than 110% of the fair market value of such stock at the date of
grant.
13
Table
of Contents
Options
granted under the plan become vested as directed by the Companys Board of
Directors and generally expire seven or ten years after the date of grant,
unless the option holder owns more than 10% of the total combined voting power
of all classes of the Companys stock, in which case the non-statutory stock
options must be exercised within five years of the date of grant. At March 31,
2010, there were options to purchase 640,000 shares granted under the plan.
The options granted since
formation in June 2003 vest as follows:
Year 1
|
|
20
|
%
|
Year 2
|
|
30
|
%
|
Year 3
|
|
50
|
%
|
|
|
100
|
%
|
At March 31, 2010,
the Company had unvested options to purchase 12,500 shares with a weighted
average grant date fair value of $5,600. During the three months ended March 31,
2010, the Company did not grant any options to purchase common stock. The
Company will recognize compensation expense relating to nonvested options
granted after January 1, 2007 ratably over the next three years. The
Company recognized an expense of approximately $19,000 for the three months
ended March 31, 2010, based on the fair value of the vested options.
The following
table summarizes stock option activity for the three months ended March 31,
2010:
|
|
Number of
Shares
|
|
Weighted Average
Exercise Price
Per Share
|
|
Weighted
Average
Remaining
Contractual Life
|
|
Aggregate
Intrinsic value
|
|
Outstanding,
December 31, 2009
|
|
640,000
|
|
$
|
5.81
|
|
|
|
|
|
Canceled or
forfeited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding,
March 31, 2010 (unaudited)
|
|
640,000
|
|
$
|
5.81
|
|
2.08
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable,
March 31, 2010 (unaudited)
|
|
627,500
|
|
$
|
5.76
|
|
2.04
|
|
$
|
|
|
The following table summarizes information about stock
options outstanding at March 31, 2010:
|
|
Options Outstanding
|
|
Options Exercisable
|
|
Exercise Prices
|
|
Number of Shares
Outstanding
|
|
Weighted Average
Remaining
Contractual Life
|
|
Number
Exercisable
|
|
Weighted Average
Exercise Price
|
|
Fair Value
Determination
|
|
$4.00
|
|
137,500
|
|
0.5 years
|
|
137,500
|
|
$
|
4.00
|
|
Black-Scholes
(minimum value)
|
|
$4.80
|
|
265,000
|
|
2.0 years
|
|
265,000
|
|
$
|
4.80
|
|
Black-Scholes
(minimum value)
|
|
$5.20
|
|
112,500
|
|
2.8 years
|
|
112,500
|
|
$
|
5.20
|
|
Black-Scholes
|
|
$8.40
|
|
25,000
|
|
4.2 years
|
|
12,500
|
|
$
|
8.40
|
|
Black-Scholes
|
|
$11.00
|
|
100,000
|
|
3.2 years
|
|
100,000
|
|
$
|
11.00
|
|
Black-Scholes
|
|
|
|
640,000
|
|
|
|
627,500
|
|
|
|
|
|
Stock
Appreciation Rights under Stock Incentive Plan
The Company has adopted a stock incentive plan
authorizing the grant of Stock Appreciation Rights (SARs). A SAR confers on
the participant a right to receive, upon exercise, the excess of the fair
market value of a share of Common Stock on the date of the exercise over $1.00.
Such excess shall be paid in cash or common stock or a combination thereof to
the participant. On June 1, 2009, 202,280 SARs were granted and currently
outstanding as of March 31, 2010. The SARs granted since 2009 vest as
follows:
14
Table
of Contents
Year
1
|
|
33.33
|
%
|
Year
2
|
|
33.33
|
%
|
Year
3
|
|
33.34
|
%
|
|
|
100
|
%
|
As of March 31, 2010, the Company had
approximately $55,000 of unrecognized compensation expense related to nonvested
SAR awards.
The following table summarizes stock appreciation
activity for the three months ended March 31, 2010:
|
|
Shares
|
|
Weighted
Average Grant
Date Fair Value
|
|
Weighted
Average
Remaining
Contractual
Life
|
|
Outstanding as of
December 31, 2009
|
|
202,280
|
|
$
|
0.41
|
|
6.42
|
|
Granted
|
|
|
|
|
|
|
|
Canceled
or forfeited
|
|
|
|
|
|
|
|
Outstanding at
March 31, 2010 (unaudited)
|
|
202,280
|
|
$
|
0.41
|
|
6.17
|
|
During the three months ended March 31, 2010, the
Company recognized compensation expense of approximately $6,000 based on the fair
value of the vested shares using a Black-Scholes model.
Restricted
Stock
The Company has an incentive program whereby grants of
restricted stock have been awarded to members of the Board of Directors and
certain employees. Restrictions and vesting periods for the awards are
determined at the discretion of the Board of Directors and are set forth in the
award agreements.
The Company recognized a
compensation expense of approximately $128,000 for the quarter ended March 31,
2010 based on the fair value of the vested shares during that period.
A summary of the status and activity of the restricted
stock for the three months ended March 31, 2010 is presented
below.
|
|
Shares
|
|
Weighted Average
Grant Date
Fair Value
|
|
Unvested at
December 31, 2009
|
|
342,993
|
|
$
|
2.18
|
|
Granted
|
|
212,502
|
|
$
|
0.31
|
|
Vested
|
|
(215,002
|
)
|
$
|
0.43
|
|
Unvested at
March 31, 2010 (unaudited)
|
|
340,493
|
|
$
|
2.12
|
|
As of March 31,
2010, the Company had approximately $0.5 million of unrecognized share-based
compensation expense related to unvested stock awards, which is expected to be
amortized over the remaining vesting periods of three years.
Note 7
Line of Credit and Long Term Debt
Credit
Facility
Effective February 12,
2007, the Company entered into a credit facility which permits borrowings up to
the borrowing base as designated by the administrative agent. As of March 31,
2010 and December 31, 2009, the Company had $5.5 million and
$6.1 million, respectively, of debt outstanding under the facility. As
described below, the Company is currently unable to borrow additional amounts
under the credit facility due to covenant limitations and may be further
limited in the future based on borrowing base limitations.
15
Table of Contents
As of December 31,
2008, the borrowing base under the credit facility was approximately
$13.2 million. The borrowing base was subject to automatic reductions for approximately
$666,667 per month until it reached $10.5 million on April 1, 2009.
As of April 14, 2009, the borrowing base was further reduced to
$9.0 million, subject to automatic reductions of $500,000 per month until
it reached $6.5 million on October 1, 2009. As of October 20,
2009, the borrowing base was subject to automatic reductions of $200,000 per
month until it reaches maturity or until a redetermination is received.
The borrowing base
is determined on a semi-annual basis and at such other additional times, up to
twice yearly, as may be requested by either the Company or the administrative
agent and is determined by the administrative agent in accordance with
customary practices and standards for loans of a similar nature, although such
determination is at the administrative agents discretion as the credit
agreement does not provide a specific borrowing base formula.
Borrowings under
this credit facility may be used solely to acquire, explore or develop oil and
gas properties and for general corporate purposes. The credit facility matures June 15,
2010.
The Companys
obligations under the credit facility are secured by liens on (i) no less
than 90% of the net present value of the oil and gas to be produced from its
oil and gas properties that are included in the borrowing base determination,
calculated using a discount rate of 10% per annum and reserve estimates, prices
and production rates and costs, (ii) options to lease, seismic options,
permits, and records related to such properties, and (iii) seismic data.
Borrowings under
the Companys credit facility, as amended, bear interest either: (i) at
the greater of the one month London Interbank Offered Rate, or LIBOR, plus
1.00% or a domestic bank rate, plus in either case an applicable margin of 0.75%
to 1.75% based on utilization, or (ii) on a sliding scale from the one,
two, three or six month LIBOR, plus an applicable margin of 2.00% to 3.00%
based on utilization. The weighted average interest rate as of March 31,
2010 was 5.0%. The credit agreement provides for various fees, including a
quarterly commitment fee of 0.5% per annum and engineering fees to the
administrative agent in connection with a borrowing base determination. In
addition, the credit facility provided for an up front fee of $27,000, which
was paid on the closing date of the credit facility, and an additional
arrangement fee of 1% based on utilization. Borrowings under this credit
facility may be prepaid without premium or penalty, except on Eurodollar
advances.
The credit agreement, as
amended contains covenants that, among other things, restrict the Companys
ability, (subject to certain exceptions) to do the following:
·
incur liens;
·
incur debt;
·
make investments in other persons;
·
declare dividends or redeem or repurchase stock;
·
engage in mergers, acquisitions, consolidations and
asset sales or amend the Companys organizational documents;
·
enter into certain hedging arrangements;
·
amend material contracts; and
·
enter into related party transactions.
With regard to hedging
arrangements, the credit agreement provides that acceptable commodity hedging
arrangements cannot be greater than 80 to 85%, depending on the measurement
date, of the Companys monthly production from its hydrocarbon properties that
are used in the borrowing base determination and that the fixed or floor price
of the Companys hedging arrangements must be equal to or greater than the gas
price used by the lenders in determining the borrowing base.
The credit
agreement, as amended, also requires the Company satisfy certain affirmative
covenants, meet certain financial tests, maintain certain financial ratios and
make certain customary indemnifications to lenders and the
16
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administrative agent. The
financial covenants include requirements to maintain: (i) a ratio of
EBITDA to cash interest expense of not less than 3.00 to 1.00, (ii) a
ratio of current assets to current liabilities of not less than 1.00 to 1.00, (iii) a
total debt to annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) a
quarterly total senior debt to annualized EBITDA ratio equal to or less than
3.0 to 1.0, and (v) a total proved PV-10 value to total debt ratio of at
least 1.50 to 1.00.
The credit
agreement, as amended, contains customary events of default, including payment
defaults, covenant defaults, certain events of bankruptcy and insolvency,
defaults in the payment of other material debt, judgment defaults, breaches of
representations and warranties, loss of material permits and licenses and a
change in control. The credit agreement requires any wholly-owned subsidiaries
to guarantee the obligations under the credit agreement.
After an event of
default, the outstanding debt bears interest at the default rate under the
terms of the credit agreement. The default rate is (i) with respect to
principal, 2% over the otherwise applicable rate and (ii) with respect to
interest, fees and other amounts, the Base Rate (as defined in the credit
facility), plus the Applicable Margin (as defined in the credit agreement),
plus 2%. Any default interest is payable on demand. Failure to pay the default
interest when the administrative agent demands, would be another default. The
lenders remedies for defaults under the credit agreement are to terminate
further borrowings, accelerate the repayment of indebtedness and/or ultimately
foreclose on the collateral property.
Effective August 4,
2008, the Company and the administrative agent and lender entered into the
second amendment to the credit agreement (the second amendment). The second amendment
provided, among other things, for (i) an increase in the total quarterly
senior debt to annualized EBITDA ratio from 2.0 to 1.0, to 3.0 to 1.0, (ii) an
increase in interest at each utilization level for LIBOR borrowings, (iii) the
amendment of the utilization calculation to be determined as the greater of (x) the
percentage of credit exposure over the borrowing base or (y) the
percentage of credit exposure over three times EBITDA minus permitted
subordinated debt, and (iv) the payment of an amendment fee.
Effective December 31,
2008, the Company and the administrative agent and lender entered into the
third amendment to the credit agreement (the third amendment). In addition to
waiving compliance with the current ratio covenant as of December 31,
2008, the third amendment, among other things, required that immediately prior
to any additional borrowings under the credit agreement, the ratio of current
assets to current liabilities be not less than 1.00 to 1.00. As a result of
this new condition to additional borrowings, the Company is currently unable to
borrow additional amounts under the credit agreement. The third amendment also
increased the interest rate payable under the credit agreement to either (i) the
greater of the one month LIBOR plus 1.00% or a domestic bank rate, plus in
either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) a
sliding scale from the one, two, three or six month LIBOR, plus an applicable
margin of 2.00% to 3.00% based on utilization, and provided for the payment of
an amendment fee.
On April 14,
2009, the Company and the administrative agent entered into the fourth
amendment to the credit agreement which reduced the borrowing base as described
above and waived compliance with the current ratio financial covenant as of December 31,
2008 and March 31, 2009 and with the restrictive covenants related to
accounts payable, permitted liens and permitted debt until the current ratio
financial covenant and next borrowing base redetermination, subject to certain
financial caps. On August 19, 2009, the lenders waived compliance with the
current ratio financial covenant under the credit agreement for the period
ending August 26, 2009 and the quarter ending June 30, 2009.
On August 26,
2009, the Company entered into a fifth amendment to the credit agreement which
provided a waiver of the current ratio covenant through October 26, 2009
and for the quarter ending June 30, 2009. The fifth amendment to the
credit agreement also extended restrictive covenants related to accounts
payable, permitted liens and permitted debt, until October 26, 2009,
subject to certain financial caps.
On October 20,
2009, the Company and the Lenders executed the sixth amendment to the credit
agreement. This amendment established the Borrowing Base for the following
amounts in the following applicable periods:
December 1,
2009 through December 31, 2009
|
|
$
|
6,300,000
|
|
January 1,
2010 through January 31, 2010
|
|
$
|
6,100,000
|
|
February 1,
2010 through February 28, 2010
|
|
$
|
5,900,000
|
|
March 1,
2010 through March 31, 2010
|
|
$
|
5,700,000
|
|
April 1,
2010 through April 30, 2010
|
|
$
|
5,500,000
|
|
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Each Calendar
month thereafter commenced May 1, 2010; the Borrowing Base for the
preceding calendar month reduced by $200,000.
On October 26,
2009, the lenders provided a waiver effectively extending the terms of the
fifth amendment to the credit agreement through November 16, 2009. On November 16,
2009, the lenders provided an additional waiver effectively extending the terms
of the fifth amendment to the credit agreement through November 23, 2009.
On November 23,
2009, the lenders provided an additional waiver extending the terms of the
fifth amendment to the credit agreement through December 1, 2009 and for
the quarter ended December 31, 2009.
On December 1,
2009 the lenders provided an additional waiver extending the terms of the fifth
amendment to the credit agreement through January 5, 2010.
On January 5,
2010 the lenders provided an additional waiver extending the terms of the fifth
amendment to the credit agreement through January 12, 2010.
On January 13,
2010, the Company entered into a seventh amendment and waiver to credit
agreement (
waiver agreement
)
with the lenders party thereto. The waiver agreement provided that the lenders
would waive (i) its compliance with certain restrictions based on the
current ratio in the credit agreement, (ii) certain requirements
pertaining to the aging of certain accounts payable, and (iii) certain
restrictions regarding the amount of liens the Company has. Default remedies
available to the lenders under the credit agreement include acceleration of all
principal and interest amounts due under the credit agreement. The waiver
agreement extends the waiver period for these items until the earlier of June 15,
2010 and the date of any default arising out of a breach or non-compliance with
the credit agreement not expressly waived in the waiver agreement or a breach
of the waiver agreement.
In addition, the
waiver agreement amends the definition of Final Maturity Date under the
credit agreement to the earlier of (i) June 15, 2010 or (ii) the
date that is thirty days following the earlier of (A) the date the merger
is withdrawn or terminated in whole or in part or (B) the date that the
lenders have been advised that the merger will not proceed.
Office
Building Loan.
On November 15,
2005, the Company entered into a mortgage loan secured by its office building
in Sheridan, Wyoming in the aggregate principal amount of $829,000. The
promissory note provides for monthly payments of principal and interest in the
initial amount of $6,400 and unpaid principal that bore interest at 6.875%
until November 15, 2008, currently bears interest at a variable base rate
plus 0.5% and will bear interest at 18% upon a default. The variable base rate
is based on the lenders base rate. The maturity date of this mortgage is November 15,
2015, at which time a principal and interest payment of $520,800 will become
due. As of March 31, 2010, the Company had $725,000 outstanding in
principal on this mortgage. On November 15, 2008, the interest rate on the
mortgage loan changed from a fixed rate of 6.875% to a variable rate. As of March 31,
2010, the variable rate was 4.0%.
Note 8
Fair Value Measurements
Effective January 1,
2008, the Company adopted the authoritative guidance that applies to all
financial assets and liabilities required to be measured and reported on a fair
value basis. Beginning January 1, 2009, the Company also applied the
guidance to non-financial assets and liabilities measured at fair value on a
nonrecurring basis, including proved oil and gas properties and other
long-lived assets and asset retirement obligations initially measured at fair
value. The guidance defines fair value as the price that would be received to
sell an asset or paid to transfer a liability (an exit price) in an orderly
transaction between market participants at the measurement date. The guidance
establishes a hierarchy for inputs used in measuring fair value that maximizes
the use of observable inputs and minimizes the use of unobservable inputs by
requiring that the most observable inputs be used when available. Observable
inputs are inputs that market participants would use in pricing the asset or
liability developed based on market data obtained from sources independent of
the Company. Unobservable inputs are inputs that reflect the Companys
assumptions of what market participants would use in pricing the asset or
liability based on the best information available in the circumstances. The
financial and nonfinancial assets and liabilities are classified based on the
lowest level of input that is significant to the fair value measurement. The
hierarchy is broken down into three levels based on the reliability of the
inputs as follows:
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·
Level 1Quoted prices in active markets for identical assets or
liabilities;
·
Level 2Quoted prices in active markets for similar assets and
liabilities, that are observable for the asset or liability; or
·
Level 3Unobservable pricing inputs that are generally less
observable from objective sources, such as discounted cash flow models or
valuations.
The following is a
listing of the Companys assets and liabilities required to be measured at fair
value on a recurring basis and where they are classified within the hierarchy
as of March 31, 2010 (in thousands):
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Oil and gas
derivative instruments
|
|
$
|
|
|
$
|
1,513
|
|
$
|
|
|
$
|
1,513
|
|
Total
|
|
$
|
|
|
$
|
1,513
|
|
$
|
|
|
$
|
1,513
|
|
As of March 31,
2010, the Companys derivative financial instruments are comprised of four
natural gas swap agreements. The fair values of the swap agreements are
determined based primarily on inputs that are derived from observable data at
commonly quoted intervals for the full term of the derivatives and are
therefore considered Level 2 in the fair value hierarchy.
The Company adopted FASB
ASC Update 2010-06, Fair Value Measurements and Disclosures which amends ASC
Update 2010-06 to require additional disclosures concerning transfers between
Levels 1 and 2, inputs and valuation techniques used to value Level 2 and 3
measurements, and push down of previously prescribed fair value disclosures to
each class of asset and liability for Levels 1, 2, and 3. The Company
determines the fair value of these swap contracts under the income approach
using a discounted cash flow model. The
valuation model requires a variety of inputs, including contractual terms,
projected gas market prices, discount rate, and credit risk adjustments, as appropriate. The Company has consistently applied this
valuation technique in all periods presented and believes it has obtained the
most accurate information available for the types of derivative instruments it
holds. These disclosures were effective for the Company for the quarter ended March 31, 2010.
The adoption of this pronouncement did not have a material impact on the
Companys consolidated financial statements.
The Companys
estimate of the fair value of derivative financial instruments includes
consideration of the counterpartys credit worthiness, the Companys credit
worthiness, and the time value of money. The consideration of these factors
results in an estimated exit-price for each derivative asset or liability under
a market place participants view.
Note 9
Commitments and Contingencies
Operating
Lease
Upon purchase of
the building in August 2005, the Company was assigned the lease agreements
for existing tenants in the building. The leases expire from January 2010
to January 2013. Future minimum lease income under noncancelable operating
leases is as follows:
Year Ending December 31,
|
|
|
|
2010
|
|
$
|
79,000
|
|
2011
|
|
60,000
|
|
2012
|
|
44,000
|
|
2013
|
|
44,000
|
|
Total
minimum lease payments
|
|
$
|
227,000
|
|
Gas Gathering Contracts
The Company has entered
into gas gathering and compression agreements with service providers in order
to compress and transport its gas to the point of sale. Compression agreements
and gathering agreements are based on a fee per
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Mcf either compressed or
gathered. The Company accounts for these fees as a marketing and transportation
expense. The Company does not pay or charge marketing fees associated with the
movement and sale of natural gas.
Litigation
From time to time,
the Company is subject to legal proceedings and claims that arise in the
ordinary course of its business. In addition, like other natural gas and oil
producers and marketers, the Companys operations are subject to extensive and
rapidly changing federal and state environmental, health and safety and other
laws and regulations governing air emissions, wastewater discharges, and solid
and hazardous waste management activities. As a result, it is extremely
difficult to reasonably quantify future environmental and regulatory related
expenditures.
The following
represent legal actions in which the Company is involved. No assurance can be
given that these legal actions will be resolved in the Companys favor.
However, the Companys management believes, based on its experiences to date,
that these matters will not have a material adverse impact on the Companys
business, financial position or results of operations.
The Company,
together with the State of Montana, the Montana Department of Environmental
Quality, the Montana Board of Oil and Gas Conservation and the Department of
Natural Resources, were named as defendants in a lawsuit (Civil Cause No. DV-05-27)
filed on May 19, 2005 in the Montana 22nd Judicial District Court,
Bighorn County by Diamond Cross Properties, LLC relating to the Coal Creek
POD. The plaintiff is a surface owner with properties located in Big Horn
County and Rosebud County, Montana where the Company has a lease for
approximately 10,300 acres, serves as operator and owns a working interest in
the minerals under lease. The plaintiff sought to permanently enjoin the State
of Montana and its administrative bodies from issuing licenses or permits, or authorizing
the removal of ground water from under the plaintiffs ranch. In addition, the
plaintiff further sought to preliminarily and permanently enjoin the Company on
the basis that the Companys operations lacked adequate safeguards required
under the Montana state constitution. On August 25, 2005, the district
judge issued an order denying without prejudice the application for temporary
restraining order and preliminary injunction requested by the plaintiff. The
case was appealed by the plaintiff to the Montana Supreme Court. On November 16,
2005, the Montana Supreme Court issued an order that denied enjoining the Coal
Creek POD, and subsequently, the Montana Supreme Court remanded the case back
to the district court for a decision on the merits.
The Company,
together with the defendants above, was also named as defendants in a related
lawsuit (Civil Cause No. DV-05-70) filed on September 21, 2005 in the
Montana 22nd Judicial District Court, Bighorn County by Diamond Cross
Properties, LLC relating to the Dietz POD. The plaintiff sought similar
relief as in the Coal Creek POD suit. The two cases were combined.
On July 14,
2008, the district court issued a summary judgment order in the combined case,
and the order was subsequently entered as a judgment on August 15, 2008.
As a result, the Company has continued its operations in the two project areas.
To date, there has been no appeal by the plaintiff.
In April and September 2005,
the U.S. Bureau of Land Management in Miles City, Montana issued suspensions of
operations for the majority of the Companys federal leases in Montana. The
suspensions were issued based upon a court order issued on April 5, 2005
by the U.S. District Court of Montana that required the BLM to complete a
Supplemental Environmental Impact Statement (SEIS) to address phased
development of coal bed natural gas. The U.S. Ninth Circuit Court of Appeals
also issued an order on May 31, 2005 which enjoined the BLM from approving
coal bed natural gas production projects in the Powder River Basin of Montana.
Both of these actions placed limitations on lease development until completion
of the SEIS.
The 2005
injunction was lifted by the Ninth Circuit Court of Appeals on October 29,
2007. The record of decision (ROD) for the SEIS was signed by the BLM on December 30,
2008 and went into effect on January 14, 2009. The Suspension of
Operations and Production for the suspended leases was terminated effective February 1,
2009. The Company has received letters from the BLM with amended lease terms of
the affected leases. Leases that were suspended have been placed back into an
active lease status with the primary term increasing for approximately three to
five years based on the time period the leases were in suspension.
On July 6,
2009, the Company filed suit (Cause No. DV09-35) against Big Sky
Energy LLC and Quaneco L.L.C., in the Twenty-Second Judicial District
Court, Big Horn County, Montana alleging claims for breach of contract, breach
of
20
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implied covenant of good
faith and fair dealing, tortuous interference with business, tortuous
interference with contractual relations and slander of title. The Company is
amending the complaint to add a foreclosure action against Big Sky
Energy LLCs and Quaneco L.L.C.s collective interest in the developed
properties in Montana for non payment of invoices in the amount of $298,689.
The Company will
continue to vigorously pursue payment of the amounts owed including interest
and attorneys fees along with foreclosure proceedings and any other rights and
remedies available to us pursuant to the Joint Operating Agreement dated June 23,
2003, as amended.
The Company was
named as a defendant in litigation brought by RLI Insurance Company (Civil
Cause No. 09-CV-157-J) filed in United States District Court for the
District of Wyoming on July 6, 2009. The complaint alleges that the
Company failed to provide $1,439,360 in additional collateral requested by
plaintiff to secure certain bonds issued by plaintiff on behalf of the Company.
Plaintiff seeks the additional bond collateral plus attorneys fees and costs.
On March 18, 2010, Pinnacle Gas Resources, Inc. and RLI Insurance Company
entered into a Tolling Agreement. The agreement stipulates that the parties
agree to drop all claims and counter claims in the litigation captioned RLI
Insurance Company v. Pinnacle Gas Resources, Inc., Case No. 09-CV-157-J
(D. Wyo.), without prejudice. The agreement further stipulates that each party
will extend the period within which either party may institute a claim,
counterclaim, action or proceeding up to and including June 16, 2010. The
agreement also obligates The Company to continue to solicit market quotes for
the purpose of replacing all bonds or bonding relationships which exist between
the Company and RLI Insurance Company.
Two putative
stockholder class action lawsuits related to the Merger have been filed in the
Delaware Court of Chancery since the announcement of the execution of the
Merger Agreement described in our Proxy Statement filed April 2,
2010. On March 24, 2010, the Delaware Court of Chancery entered an order
consolidating the two actions under the caption
In re Pinnacle Gas Resources Shareholder Litigation,
C.A. No. 5313-CC
(Del. Ch.) and appointing co-lead counsel.
The consolidated
complaint generally alleges that our directors breached their fiduciary duties
by, among other things, taking actions designed to deter higher offers from
other potential acquirers and failing to maximize the value of Pinnacle to its
stockholders. In addition, the lawsuit alleges that DLJ, as a controlling
stockholder of Pinnacle, violated fiduciary duties to Pinnacle stock holders
and that Powder and Merger Sub aided and abetted the alleged breaches of
fiduciary duties by the other defendants. The lawsuit seeks, among other
relief, injunctive relief prohibiting the Merger, and costs of the action
including reasonable attorneys fees.
The Company believes that
these lawsuits are without merit and intends to vigorously defend against them.
Regulations
The Companys oil
and gas operations are subject to various federal, state and local laws and
regulations. The Company could incur significant expense to comply with the new
or existing laws and non-compliance could have a material adverse effect on the
Companys operations.
Environmental
The Company
produces significant amounts of water from its wells. If future wells produce
water of a lesser quality than allowed under state laws or if water is produced
at rates greater than the Company can dispose of, the Company could incur
additional costs to dispose of the water.
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Note 10
Recent Developments
NASDAQ Delisting
On March 16,
2010, The NASDAQ Stock Market notified the Company of its failure to comply
with Listing Rule 5450(a)(1). This rule subjects a companys stock to
delisting on the NASDAQ exchange if its stock price closes below $1 over the
previous 30 consecutive business days and then, after notification, fails
to regain compliance within the subsequent 180 days. Accordingly, unless
the Company appealed this determination, the trading of the Companys stock would
have been suspended on March 25, 2010. The Company filed an appeal,
pursuant to NASDAQ listing rule series 5800 on March 22, 2010.
On April 29, 2010,
the Company met with representatives of NASDAQ to formally request a 180 day
extension to allow implementation of certain strategies to regain compliance.
On May 10, 2010, the
Company received a determination letter from the NASDAQ hearings panel granting
the Companys request for continued listing subject to a proxy being filed
which included a proposal for a reverse stock split and a closing bid price of
$1.00 or more for a minimum of ten consecutive trading days prior to September 13,
2010.
****
22
Table of Contents
ITEM
2. MANAGEMENTS DISCUSSION AND
ANALYSIS OF FINANCIAL
CONDITION AND RESULTS
OF OPERATIONS
The
discussion and analysis that follows should be read together with the
accompanying financial statements and notes related thereto that are included
elsewhere in this quarterly report on Form 10-Q. It includes
forward-looking statements that may reflect our estimates, beliefs, plans and
expected performance. The forward-looking statements are based upon events,
risks and uncertainties that may be outside our control. Our actual results
could differ significantly from those discussed in these forward-looking
statements. Factors that could cause or contribute to these differences
include, but are not limited to, market prices for natural gas and oil,
regulatory changes, estimates of proved reserves, economic conditions,
competitive conditions, development success rates, capital expenditures and
other uncertainties, as well as those factors discussed below and elsewhere in
this quarterly report on Form 10-Q and in our annual report on Form 10-K
for the year ended December 31, 2009, including in Risk Factors and Cautionary
Statement Concerning Forward-Looking Statements, all of which are difficult to
predict. As a result of these assumptions, risks and uncertainties, the
forward-looking matters discussed may not occur.
Overview
We are an
independent energy company engaged in the acquisition, exploration and
development of domestic onshore natural gas reserves. We primarily focus our
efforts on the development of CBM properties located in the Powder River Basin
in northeastern Wyoming and southern Montana. In addition, in April 2006,
we acquired properties located in the Green River Basin in southern Wyoming. As
of December 31, 2009, we owned natural gas and oil leasehold interests in
approximately 424,000 gross (308,000 net) acres, approximately 90% of which
were undeveloped. As of December 31, 2009, we had estimated net proved
reserves of approximately 15.0 Bcf based on the first day of the month, twelve
month average CIG index price of approximately $3.04 per Mcf.
The continued
credit crisis and related turmoil in the global financial system have had an
adverse impact on our business and financial condition. In addition, the prices
of oil and natural gas declined significantly in 2008 and have remained low in
2009 and during the first three months of 2010. Therefore, total capital
expenditures were limited to $4.2 million in 2009. As a result of low CIG
index prices, the economic climate and our limited capital resources, we expect
to continue operating during 2010 with a reduced capital expenditure plan.
Under our plan, we will generally make expenditures only as necessary to secure
drilling permits in strategic areas, drill wells that secure leasehold
positions and construct the necessary infrastructure to complete and hook-up
wells that have already been drilled. Our capital expenditure budget for 2010
will be dependent upon CIG index prices, our cash flows and the availability of
additional capital resources. We had
total capital expenditures of $0.2 million for the three months ended March 31,
2010.
Shares of our
common stock are traded on the NASDAQ Global Market under the symbol PINN.
Economic and Natural Gas Pricing Environment
During 2009, the
global economy experienced a significant downturn. The downturn, which began
over concerns related to the U.S. financial markets, spread to other
industries, including the energy industry. The initial effects of the downturn
restricted the capital and credit markets to a degree that has not been seen in
a number of decades in the United States. We have been able to partially
mitigate the constraints imposed by the current economic climate through
utilization of cash flows from operations.
The fear of global
recession led to an immediate drop in demand for natural gas, primarily by
industrial users, which in turn led to a significant reduction in natural gas
prices. The natural gas index price in the Rocky Mountain region averaged $6.24
per Mcf for the twelve months ended December 31, 2008 but only $3.07 per
Mcf for the twelve months ended December 31, 2009. For the first quarter
of 2010, the price averaged $5.14. This volatility
in price has caused us to reevaluate our 2010 business plan. We have curtailed
drilling, except for wells that will hold significant blocks of acreage, and
have also reduced administrative, operating and transportation costs. Even with
cost reductions and a flexible capital spending budget, the current natural gas
pricing and economic environment remains challenging. We are exploring
strategic alternatives to increase our capital resources.
Credit Facility and Liquidity
In
the past, our primary sources of liquidity have been private and public sales
of our equity securities, cash provided by operating activities, and debt
financing. All of these sources have been negatively impacted by the current
23
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economic
climate, its impact on our industry, and by significant fluctuations in oil and
gas prices, operating costs, and volumes produced. We have no control over the
market prices for oil and natural gas, although we are able to influence the
amount of our net realized revenues related to gas sales through the use of
derivative contracts. A decrease in market prices would reduce expected cash
flow from operating activities and could reduce the borrowing base of our
credit facility as well as the value of assets we might consider selling.
Historically, decreases in the market prices have limited our industrys access
to the capital markets. During these challenging times, we have reduced our
administrative, operating and transportation costs. We are also actively
marketing asset sales and exploring other strategic alternatives and capital
restructuring options.
On
January 13, 2010, we entered into a seventh amendment and waiver to credit
agreement (
waiver agreement
)
with the lenders party thereto. The waiver agreement provided that the lenders
would waive (i) our compliance with certain restrictions based on the
current ratio in the credit agreement, (ii) certain requirements
pertaining to the aging of certain accounts payable, and (iii) certain
restrictions regarding the amount of liens we have. Default remedies available
to the lenders under the credit agreement include acceleration of all principal
and interest amounts due under the credit agreement. The waiver agreement
extends the waiver period for these items until the earlier of June 15,
2010 and the date of any default arising out of a breach or non-compliance with
the credit agreement not expressly waived in the waiver agreement or a breach
of the waiver agreement.
In
addition, the waiver agreement amends the definition of Final Maturity Date
under the credit agreement to the earlier of (i) June 15, 2010 or (ii) the
date that is thirty days following the earlier of (A) the date the merger
(please see Note 10 in the notes to the financial statements) is withdrawn or
terminated in whole or in part or (B) the date that the lenders have been
advised that the merger will not proceed.
On
February 23, 2010, we entered into an Agreement and Plan of Merger with
Powder Holdings, LLC, a Delaware limited liability company, and Powder
Acquisition Co., a Delaware corporation and a direct, wholly owned
subsidiary of Powder Holdings. Powder Holdings is controlled by an investor
group led by Scotia Waterous (USA) Inc. and includes certain members of
the Companys management team.
We have also implemented various cost cutting
measures, including reducing general and administrative costs through staff
reductions, wage and benefit cuts and a hiring freeze. We have reduced lease operating expenses by
renegotiating water disposal contracts, reducing service costs and temporarily
shutting-in marginal wells. We continue
to communicate with key vendors to manage our obligations and payables. Management believes that appropriate steps,
including cost-cutting measures, are being taken to make operations sustainable
in the future. Although we are pursuing
various alternatives to provide additional liquidity, there is no assurance of
the likelihood or timing of any of these transactions.
We
also put additional hedges of our natural gas production in place to secure
certain operating cash flow levels during 2010. From January through April 2010,
we had 5,500 MMbtu per day hedged through fixed price swaps at a weighted
average price of $4.19 per MMbtu. From May through December 2010, we
have 5,500 MMbtu hedged through fixed price swaps at a weighted average price
of $5.08 per MMbtu. Although we are pursuing various alternatives to provide
additional liquidity, there is no assurance of the likelihood or timing of any
of these transactions.
Critical
Accounting Policies
The most subjective and
complex judgments used in the preparation of our financial statements are:
·
Reserve evaluation and
determination;
·
Estimates of the timing and cost of
our future drilling activity;
·
Estimates of the fair valuation of
hedges in place;
·
Estimates of timing and cost of
asset retirement obligations;
·
Estimates of the expense and timing
of exercise of stock options;
·
Accruals of operating costs,
capital expenditures and revenue; and
·
Estimates for litigation.
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Oil and Gas Properties
We use the full
cost method of accounting for oil and gas producing activities. Under this
method, all costs associated with property acquisition, exploration and
development, including costs of unsuccessful exploration, costs of surrendered
and abandoned leaseholds, delay lease rentals and the fair value of estimated
future costs of site restoration, dismantlement and abandonment activities, are
capitalized within a cost center. Our oil and gas properties are all located
within the United States, which constitutes a single cost center. We capitalize
certain lease operating expenses associated with exploration and development of
unevaluated oil and gas properties. No gain or loss is recognized upon the sale
or abandonment of undeveloped or producing oil and gas properties unless the
sale represents a significant portion of gas properties and the gain
significantly alters the relationship between capitalized costs and proved gas
reserves of the cost center. Expenditures for maintenance and repairs are
charged to lease operating expense in the period incurred.
Depreciation,
depletion and amortization of oil and gas properties are computed on the
unit-of-production method based on proved reserves. Amortizable costs include
estimates of future development costs of proved undeveloped reserves and asset
retirement obligations. We invest in unevaluated oil and gas properties for the
purpose of exploration for proved reserves. The costs of such assets, including
exploration costs on properties where a determination of whether proved oil and
gas reserves will be established is still under evaluation, and any capitalized
interest and lease operating expenses, are included in unproved oil and gas
properties at the lower of cost or estimated fair market value and are not
subject to amortization. On a quarterly basis, such costs are evaluated for
inclusion in the costs to be amortized resulting from the determination of
proved reserves, impairments, or reductions in value. To the extent that the
evaluation indicates these properties are impaired, the amount of the
impairment is added to the capitalized costs to be amortized. We recorded an
impairment of unevaluated properties of $0 million and $36.7 million during the
three months ended March 31, 2010 and the year ended December 31,
2009, respectively. Abandonment of unproved properties is also accounted for as
an adjustment to capitalized costs related to proved oil and gas properties,
with no losses recognized.
Substantially all
remaining unproved property costs are expected to be developed and included in
the amortization base ratably over the next three to five years. Salvage value
is taken into account in determining depletion rates and is based on our
estimate of the value of equipment and supplies at the time the well is
abandoned. As of March 31, 2010 and March 31, 2009, the estimated
salvage value of equipment was $6.8 million and $7.2 million, respectively.
Under the full cost
method of accounting rules, capitalized costs less accumulated depletion and
related deferred income taxes may not exceed a ceiling value which is the sum
of (1) the present value discounted at 10% of estimated future net revenue
using current costs and the first day of the month, twelve month average CIG
price, including the effects of derivative instruments designated as cash flow
hedges but excluding the future cash outflows associated with settling asset
retirement obligations that have been accrued on the balance sheet, less any
related income tax effects; plus (2) the cost of properties not being
amortized, if any; plus (3) the lower of costs or estimated fair value of
unproved properties; less (4) the income tax effects related to
differences in the book to tax basis of oil and gas properties. This is
referred to as the full cost ceiling limitation. If capitalized costs exceed
the limit, the excess must be charged to expense. The expense may not be
reversed in future periods. At the end of each quarter, we calculate the full
cost ceiling limitation. At March 31, 2010, the full cost ceiling
limitation exceeded the capitalized cost of the Companys oil and gas
properties by approximately $4.1 million based on the first day of the month,
twelve month average CIG price of approximately $3.48 per Mcf. Therefore, no
impairment was taken for the quarter ended March 31, 2010. An impairment
of $16.8 million was taken for the quarter ended March 31, 2009 based on a
natural gas price of $3.31 per Mcf. A decline in gas prices or an increase in
operating costs subsequent to the measurement date or reductions in
economically recoverable quantities could result in the recognition of
additional impairments of our oil and gas properties in future periods.
Gas Sales
We use the sales method
for recording natural gas sales. Sales of gas applicable to our interest in
producing natural gas and oil leases are recorded as revenues when the gas is
metered and title transferred pursuant to the gas sales contracts covering our
interest in gas reserves. During such times as our sales of gas exceed our pro
rata ownership in a well, such sales are recorded as revenues unless total
sales from the well have exceeded our share of estimated total gas reserves
underlying the property at which time such excess is recorded as a gas
imbalance liability. At March 31, 2010 and December 31, 2009, there
was no such liability recorded. Although there was no such liability recorded
for prior periods, gas reserves are an estimate and are updated on an annual
and interim basis. Gas pricing, expenses and production may impact future gas
reserves remaining which, in turn, could impact the recording of liabilities in
the future. Gas sales accruals at March 31, 2010, and December 31,
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2009 were based on the
actual volume statements from our purchasers and distribution process. If
accruals were to change by 10% at March 31, 2010 and at December 31,
2009, the impact would have been a change of $133,000 and $124,000,
respectively.
Asset Retirement Obligations
We follow certain
accounting provisions that apply to legal obligations associated with the
retirement of long-lived assets that result from the acquisition, construction,
development and/or the normal operation of a long-lived asset. These provisions
require us to recognize an estimated liability for costs associated with the
abandonment of our oil and gas properties.
A liability for the fair
value of an asset retirement obligation with a corresponding increase to the
carrying value of the related long-lived asset is recorded at the time a well
is completed or acquired. The increased carrying value is depleted using the
units-of-production method, and the discounted liability is increased through
accretion over the remaining life of the respective oil and gas properties.
The estimated liability
is based on historical gas industry experience in abandoning wells, including
estimated economic lives, external estimates as to the cost to abandon the
wells in the future and federal and state regulatory requirements. Our
liability is discounted using our best estimate of our credit-adjusted
risk-free rate. Revisions to the liability could occur due to changes in
estimated abandonment costs, changes in well economic lives or if federal or
state regulators enact new requirements regarding the abandonment of wells. For
example, a 10% change in our estimated retirement costs would have had a
$296,000 effect on our asset retirement obligation liability at March 31,
2010.
The following is a
summary of our asset retirement obligation activity for the three months ended March 31,
2010 and 2009 (in thousands):
|
|
Three
Months Ended
March 31,
|
|
Three
Months Ended
March 31,
|
|
|
|
2010
|
|
2009
|
|
|
|
(unaudited)
|
|
(unaudited)
|
|
Beginning
balance asset retirement obligations
|
|
$
|
2,937
|
|
$
|
3,366
|
|
Additional
obligation added during the period
|
|
1
|
|
|
|
Obligations
settled during the period
|
|
(31
|
)
|
|
|
Accretion
expense
|
|
52
|
|
56
|
|
Ending balance
of asset retirement obligations
|
|
$
|
2,959
|
|
$
|
3,422
|
|
Inventory
We have acquired
inventory of oil and gas equipment, primarily tubulars, to take advantage of
quantity pricing and to secure a readily available supply. Inventory is valued
at the lower of average cost or market. Inventory is used in the development of
gas properties and to the extent it is estimated that it will be billed to
other working interest owners during the next year, it is included in current
assets. Otherwise, it is recorded in non-current assets. The price of steel is
a primary factor in valuing our inventory. Under the valuation method of lower
of average cost or market, a 10% reduction in the price of steel would have
caused a $44,000 reduction in our inventory valuation as of March 31,
2010. The market price of steel is evaluated each quarter using prices quoted
by authorized vendors in the area.
Property and Equipment
Property and equipment is
comprised primarily of a building, computer hardware and software, vehicles and
equipment, and is recorded at cost. Renewals and betterments that substantially
extend the useful lives of the assets are capitalized. Maintenance and repairs
are expensed when incurred. Depreciation and amortization are provided using
the straight-line method over the estimated useful lives of the assets, ranging
as follows: buildings30 years, computer hardware and software3 to
5 years, machinery, equipment and vehicles5 years, and office
furniture and equipment3 to 5 years.
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Long-Lived Assets
Long-lived assets to be
held and used in our business are reviewed for impairment whenever events or
changes in circumstances indicate that the related carrying amount may not be
recoverable. When the carrying amounts of long-lived assets exceed the fair
value, which is generally based on discounted expected future cash flows, we
recorded an impairment. No impairments were recorded during the three months
ended March 31, 2010 and the year ended December 31, 2009.
General and Administrative Expenses
General and
administrative expenses are reported net of amounts allocated and billed to
working interest owners of gas properties operated by us. The administrative
expenses billed to working interest owners may change in accordance with the
terms of the joint operating agreements. Administrative expenses are charged to
working interest owners based on productive well counts. A 10% change in well counts for the three
months ended March 31, 2010 would have increased or decreased our expenses
billed to working interest owners by approximately $29,000. As we operate and
drill additional wells in the future, additional administrative expenses will
be charged to the working interest owners when the wells become productive.
Income Taxes
We use the asset and
liability method of accounting for income taxes. Deferred tax assets and
liabilities are recognized for the expected future tax consequences of
temporary differences between the financial statement and tax bases of assets
and liabilities. If appropriate, deferred tax assets are reduced by a valuation
allowance which reflects expectations of the extent to which such assets will
be realized. As of March 31, 2010 and December 31, 2009, we recorded
a full valuation allowance for our net deferred tax asset.
On January 1,
2007, we adopted accounting provisions that prescribe a recognition threshold
and measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return.
This provision requires that we recognize in our consolidated financial
statements only those tax positions that are more-likely-than-not of being
sustained as of the adoption date, based on the technical merits of the
position. As a result of the implementation of the provision, we performed a
comprehensive review of our material tax positions in accordance with these
recognition and measurement standards. As a result of this review, we did not
identify any material deferred tax assets that required adjustment. As of March 31,
2010 and December 31, 2009, we had not recorded any material uncertain tax
positions.
Our policy is to
recognize interest and penalties related to uncertain tax benefits in income
tax expense. As of March 31, 2010 and 2009, we had not recognized any
interest or penalties in our statement of operations or statement of financial
position.
We are subject to the
following material taxing jurisdictions: U.S. federal. We also have material
operations in the state of Wyoming; however, Wyoming does not impose a
corporate income tax. The tax years that remain open to examination by the U.S.
Internal Revenue Service are years 2005 through 2009. Due to our net operating
loss carry forwards, the Internal Revenue Service may also adjust the amount of
loss realizable under examination back to 2003.
Derivatives
We use derivative
instruments to manage our exposure to fluctuating natural gas prices through
the use of natural gas swap and option contracts. We account for derivative
instruments or hedging activities under authoritive guidance prescribed by FASB
that requires us to record derivative instruments at their 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 in earnings. If the derivative is designated as a cash flow hedge,
the effective portions of changes in the fair value of the derivative are
recorded in other comprehensive income (loss) and are recognized in the
statement of operations when the hedged item affects earnings. Ineffective
portions of changes in the fair value of cash flow hedges, if any, are
recognized in earnings. Changes in the fair value of derivatives that do not
qualify for hedge treatment are recognized in earnings.
We periodically
hedge a portion of our oil and gas production through swap and collar
agreements. The purpose of the hedges is to provide a measure of stability to
our cash flows in an environment of volatile oil and gas prices and to manage
the exposure to commodity price risk. Our management decided not to use hedge
accounting for these agreements. Therefore, in accordance with certain
accounting provisions, the changes in fair market value are recognized in
earnings.
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Stock-Based Compensation
Effective January 1,
2006, we adopted accounting provisions, which require companies to recognize
compensation expense for share-based payments based on the estimated fair value
of the awards. We recognized an expense of approximately $19,000 for the three
months ended March 31, 2010, based on the fair value of vested options. We recognized an expense of approximately
$129,000 for the three months ended March 31, 2010, based on the fair value of
restricted stock that vested during the quarter. We recognized an expense of approximately
$6,000 for the three months ending March 31, 2010, based on the fair market
value of stock appreciation rights. This accounting provision also requires
that the benefits of tax deductions in excess of compensation cost recognized
for stock awards and options (excess tax benefits) be presented as financing
cash inflows in the Statement of Cash Flows.
Accounts Receivable
Our revenue producing
activities are conducted primarily in Wyoming. We grant credit to qualified
customers, which potentially subjects us to credit risk resulting from, among
other factors, adverse changes in the industry in which we operate and the
financial condition of our customers. We continuously monitor collections and
payments from our customers and, if necessary, record an allowance for doubtful
accounts based upon historical experience and any specific customer collection
issues identified. We recorded an allowance of approximately $14,000 and
$100,000 at each of March 31, 2010 and December 31, 2009
respectively.
Transportation Costs
We account for
transportation costs under authoritative guidance prescribed by the FASB
related to the accounting for shipping and handling fees and costs, whereby
amounts paid for transportation are classified as operating expenses.
Legal Estimates
From time to time,
we are subject to legal proceedings and claims that arise in the ordinary
course of business. We account for these costs under an accounting provision,
which states that a loss contingency be recorded if it is probable that a
liability has been incurred and it is reasonably estimatable. At March 31,
2010 and 2009, we recorded no expenses for legal proceedings.
Per Share Information
Basic
earnings (loss) per share is computed by dividing net income (loss) from
continuing operations attributable to common stock by the weighted average
number of shares of common stock outstanding during each period. Diluted
earnings per share are computed by adjusting the average number of shares of
common stock outstanding for the dilutive effect, if any, of common stock
equivalents such as stock options and warrants. For the three months ended March 31,
2010, diluted net income per share was $0.04 and basic net income per share was
$0.04. During the three months ended March 31, 2009, 645,000 options were
excluded because they were anti-dilutive.
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Recent Accounting Pronouncements
For information
concerning recent accounting pronouncements, please see Note 2 in the notes to
the audited financial statements appearing elsewhere in this report.
Trends
Affecting Our Business
The
continued credit crisis and related turmoil in the global financial system have
had an adverse impact on our business and financial condition. In addition, the
prices of oil and natural gas declined significantly in 2008 and have remained
low in 2009 and the first quarter of 2010. As a result of low CIG index prices,
the economic climate and our limited capital resources, we expect to continue
operating during 2010 with a reduced capital expenditure plan for 2010. Under
our plan, we will generally make expenditures only as are necessary to secure
drilling permits in strategic areas, drill wells that secure leasehold
positions and construct the necessary infrastructure to complete and hook-up
wells that have already been drilled.
Historically,
natural gas prices have been extremely volatile, and we expect that volatility
to continue. For example, during the three months ended March 31, 2010,
the NYMEX natural gas index price ranged from a high of $6.00 per MMBtu to a
low of $3.84 per MMBtu, while the CIG natural gas index price ranged from a
high of $6.08 per MMBtu to a low of $3.41 per MMBtu. During the year ended December 31,
2009, the NYMEX natural gas index price ranged from a high of $6.07 per MMBtu
to a low of $2.51 per MMBtu, while the CIG natural gas index price ranged from
a high of $5.75 per MMBtu to a low of $1.33 per MMBtu. Changes in natural gas
pricing have impacted our revenue streams, production taxes, prices used in
reserve calculations, borrowing base calculations and the carrying value of our
properties and the valuation of potential property acquisitions. During the
three months ended March 31, 2010, estimated future gas prices had an
impact on both our revenues and the costs attributable to our future
operations. We expect that changing natural gas prices will continue to impact
our operations and financial results in the future.
Transportation of natural gas and access to throughput
capacity have a direct impact on natural gas prices in the Rocky Mountain
region, where our operations are concentrated. As drilling activity increases
throughout the Rocky Mountain region, additional production may come on line,
which could cause bottlenecks or capacity constraints. Generally speaking, a
surplus of natural gas production relative to available transportation capacity
has a negative impact on prices. Conversely, as capacity increases, and
bottlenecks are eliminated, prices generally increase. Although there is
currently adequate transportation capacity out of the Powder River Basin, a
surplus of natural gas arriving at key marketing hubs from the Powder River
Basin and elsewhere relative to available takeaway capacity from these hubs has
caused Rocky Mountain gas to generally trade at a discount to the NYMEX natural
gas index price. For example, from January 1, 2010 through March 31,
2010, Rocky Mountain gas traded at a differential to the NYMEX natural gas
index price that ranged from a premium of $0.27 per Mcf to a discount of $0.64
per Mcf, with an average differential of a discount of $0.24 per Mcf. The
Rockies Express Pipeline which was completed and placed into service in early
2008, has increased takeaway capacity by approximately 1.5 Bcf per day from
these hubs. We expect that the completion of additional proposed pipelines will
help reduce the differential between gas produced in the Rocky Mountain region
and the NYMEX natural gas index price. Additional proposed pipelines are
scheduled to be completed in late 2010 and 2011. General economic conditions
and the future demand for natural gas may change the development schedule of
proposed pipelines.
The U.S. House of
Representatives recently passed the American Clean Energy and Security Act of
2009 which, if passed into law, will establish a federal cap-and-trade system.
Under this system, major producers of greenhouse gas emissions would be
required to acquire emission allowances, either through purchases at auctions
or through trades with other allowance holders, and then surrender the
allowances to the government. If a regulated party could not acquire sufficient
allowances or reduce its emissions to the level of the allowances that it did
acquire, the party would face regulatory penalties. This legislation would
initially cover electrical generation facilities and would phase in coverage of
other industrial sources of emissions and natural gas and fossil fuel
distribution. If this or similar legislation is enacted into law, it could have
a material adverse effect on our operations through significant increases in
operating costs and decreases in the demand for natural gas.
The U.S. Congress
is currently considering legislation that would amend the Safe Drinking Water
Act to eliminate an existing exemption from federal regulation of hydraulic
fracturing activities. Hydraulic fracturing is a common process in our industry
of creating artificial cracks or fractures in deep underground formations
through the pressurized injection of water or other materials. The resulting
fractures allow natural gas and oil to flow more freely to a producing well.
This
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process is often
necessary to produce economically viable quantities of oil and natural gas from
many reservoirs. Currently, regulation of hydraulic fracturing is primarily
conducted at the state level through permitting and other compliance
requirements. If adopted, the proposed amendment to the Safe Drinking Water Act
could result in additional regulations and permitting requirements at the
federal level. These additional regulations and permitting requirements could
lead to significant operational delays and increased operating costs as well as
encumbering field enhancements through fracturing.
Results
of Operations
Net income attributable
to stockholders for the quarter ended March 31, 2010 was $1.1 million, or
$0.04 per diluted share, on total revenues of $2.8 million. Other income for
the quarter ended March 31, 2010 included a $2.9 million unrealized gain
associated with the change in the fair valuation of our natural gas hedges in
place in accordance with certain accounting provisions. Absent such change in
the valuation of hedges, we would have shown a loss of $1.7 million This
compares to a net loss attributable to stockholders of $17.5 million for the
quarter ended March 31, 2009 on total revenue of $2.8 million. Adjusted
for an unrealized gain in the fair valuation of our natural gas hedges in place
of $0.6 million shown in other income, our results for the quarter ended March 31,
2009 would have been a net loss attributable to common stockholders of $18.1
million.
In order to
provide a measure of stability to the cash flow in an environment of volatile
oil and gas prices and to manage the exposure to commodity price risk, we chose
to periodically hedge a portion of our oil and gas production using swap and
collar agreements. We account for our derivative instruments under certain
accounting provisions which require us to record derivative instruments at
their fair value. Management has chosen not to use hedge accounting for these
arrangements. Therefore, in accordance with these provisions, changes in the
fair market value are recognized in earnings.
Three Months Ended March 31,
2010 Compared To Three Months Ended March 31, 2009
Gas
sales volume.
Gas sales volume
decreased 27%, from 813 MMcf in the three months ended March 31, 2009 to
594 MMcf in the three months ended March 31, 2010. Daily sales volume was
6.6 MMcf for the three months ended March 31, 2010 as compared to 9.0 MMcf
for the three months ended March 31, 2009, a 2.4 MMcf per day decrease.
The decrease resulted primarily from shutting in wells due to low natural gas
prices, reductions in volumes due to compression maintenance and repairs, and
weather related downtime.
Gas
sales revenue.
Revenue from gas sales
increased approximately $80,000 during the three months ended March 31,
2010, to approximately $2.8 million, a 3% increase compared to the three months
ended March 31, 2009. This increase was primarily due to an increase in
the average realized price per Mcf but was partially offset by a decrease in
volume. The average realized price per Mcf increased approximately 41%, from
$3.40 per Mcf in the three months ended March 31, 2009 to $4.79 per Mcf in
the three months ended March 31, 2010.
Derivatives.
For the three
months ended March 31, 2010, we had an unrealized gain of $2.9 million
compared to an unrealized gain of $0.6 million for the three months ended March 31,
2009. The unrealized gains are non-cash income based primarily on the
Black-Scholes model for valuing future cash flows utilizing price volatility
with a normal discount rate for our costless collars in place and an intrinsic
model for our swaps in place. Hedges settled during the three months ended March 31,
2010 resulted in a realized loss of $0.5 million compared to a realized hedge
gain of approximately $1.5 million during the three months ended March 31,
2009. The unrealized hedge gain for the three months ended March 31, 2010,
was due to future gas prices being lower than the weighted average price of our
future hedge positions.
Lease
operating expenses.
Lease
operating expenses decreased $0.2 million in the three months ended March 31,
2010 to $1.0 million, a 14% decrease compared to the three months ended March 31,
2009. This decrease resulted primarily from a reduction in contract services,
fuel, and water management related costs offset partially by an increase in
surface use expenses in the productive
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cycle during the three
months ended March 31, 2010. On a Mcf basis, lease operating expenses
increased 18% from $1.46 per Mcf in the three months ended March 31, 2009
to $1.71 per Mcf in the three months ended March 31, 2010. The increase
per Mcf was primarily due to a number of shut-in wells in the Kirby area being
turned back on in the first quarter of 2010 that have not yet begun producing
gas.
Production taxes.
Production taxes
increased $40,000 in the three months ended March 31, 2010 to $0.3
million, a 14% increase from the three months ended March 31, 2009.
Production taxes generally correlate to gross sales revenue because production
taxes are based on a percentage of sales value. In Wyoming, the percentage
averages 11% to 13%, depending on rates in effect for the respective year,
while in Montana the percentage averages 9%. The decrease in production taxes
for the three months ended March 31, 2010 was primarily due to decreased
revenues associated with decreased volume and realized pricing. On a Mcf basis,
production taxes were $0.54 per Mcf for the three months ended March 31,
2010 and $0.34 per Mcf for the three months ended March 31, 2009, a 56%
increase, which correlates to the increase in the price per Mcf received in the
three months ended March 31, 2010 from the three months ended March 31,
2009.
Marketing
and transportation.
Marketing and
transportation expenses decreased approximately $0.5 million in the three
months ended March 31, 2010 to approximately $0.7 million, a 42% decrease
from the three months ended March 31, 2009. The decrease related primarily
to a decrease in transportation fees and compression due to lower production volumes.
On a Mcf basis, marketing and transportation expenses decreased 21% to $1.22
per Mcf in the three months ended March 31, 2010 from $1.54 per Mcf in the
three months ended March 31, 2009.
General
and administrative expenses, net.
General and administrative
expenses are offset by operating income from drilling and production activities
for which we can charge an overhead fee to nonoperating working interest
owners. These well operating overhead fees were $289,000 in the three months
ended March 31, 2010 compared to $325,000 for the three months ended March 31,
2009, an 11% decrease. General and administrative expenses net increased $0.4
million in the three months ended March 31, 2010 to $1.4 million. On a Mcf
basis, general and administrative expenses, net increased 87%, from $1.27 per
Mcf in the three months ended March 31, 2009 to $2.37 per Mcf in the three
months ended March 31, 2010. General and administrative expenses, for the
quarter ended March 31, 2010, include $0.7 million of professional services
expense for restructuring under the potential merger agreement with Scotia
Waterous signed February 23, 2010.
Depreciation,
depletion, amortization and accretion.
Depreciation, depletion,
amortization and accretion expense decreased $1.1 million for the three months
ended March 31, 2010 to $0.7 million, a 61% decrease compared to the three
months ended March 31, 2009. The decrease was primarily due to a decrease
in the capitalized basis in our full cost pool. On a Mcf basis, the
depreciation, depletion, amortization and accretion rate decreased to $1.20 per
Mcf in the three months ended March 31, 2010, from $2.25 per Mcf in the
three months ended March 31, 2009.
Impairment.
At March 31, 2010,
the full cost ceiling limitation of our oil and gas properties exceeded the
capitalized cost by approximately $4.1 million based upon a natural gas price
of approximately $3.48 per Mcf (based on the first day of the month, twelve
month average per Mcf on the Colorado Interstate Gas Rocky Mountain Index) in
effect at that date. Therefore, no impairment was taken for the quarter ended March 31,
2010. An impairment of approximately $16.8 million was taken for the quarter
ended March 31, 2009. For further
information regarding this impairment, please see Note 2 Basis of
Presentation in the Notes to the unaudited financial statements appearing
elsewhere in this quarterly report. A decline in natural gas prices or an
increase in operating costs in economically recoverable quantities could result
in the recognition of additional impairments of our oil and gas properties in
future periods.
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Liquidity
and Capital Resources
In the past, our primary sources of liquidity have
been private and public sales of our equity securities, cash provided by operating
activities, and debt financing. All of these sources have been negatively
impacted by the current economic climate, its impact on our industry, and by
significant fluctuations in oil and gas prices, operating costs, and volumes
produced. We have no control over the market prices for oil and natural gas,
although we are able to influence the amount of our net realized revenues
related to gas sales through the use of derivative contracts. A decrease in
market prices would reduce expected cash flow from operating activities and
could reduce the borrowing base of our credit facility as well as the value of
assets we might consider selling. Historically, decreases in market prices have
limited our industrys access to the capital markets. During these challenging
times, we have reduced our administrative, operating and transportation costs.
We are also actively marketing asset sales and exploring other strategic
alternatives and capital restructuring options
Credit Facility.
Effective February 12, 2007, we entered into a
credit facility which permits borrowings up to the borrowing base as designated
by the administrative agent. As of March 31, 2010 and December 31,
2009, we had $5.5 million and $6.1 million, respectively, of debt outstanding
under the facility. As described below, we are currently unable to borrow
additional amounts under the credit facility due to covenant limitations and
may be further limited in the future based on borrowing base limitations.
As of December 31, 2008, the borrowing base under
the credit facility was approximately $13.2 million. The borrowing base was
subject to automatic reductions of approximately $666,667 per month until it
reached $10.5 million on April 1, 2009. As of April 14, 2009, our
borrowing base was reduced to $9.0 million, subject to automatic reductions of
$500,000 per month until it reaches $6.5 million on October 1, 2009, where
it will remain until the next borrowing base redetermination. If natural gas
prices do not improve, we expect that our borrowing base could be further
reduced in the future.
The borrowing base is determined on a semi-annual
basis and at such other additional times, up to twice yearly, as may be
requested by either us or the administrative agent and is determined by the
administrative agent in accordance with customary practices and standards for
loans of a similar nature, although such determination is at the administrative
agents discretion as the credit agreement does not provide a specific
borrowing base formula.
Borrowings under this credit facility may be used
solely to acquire, explore or develop oil and gas properties and for general
corporate purposes. The credit facility matures February 12, 2011.
Our obligations under the credit facility are secured
by liens on (i) no less than 90% of the net present value of the oil and
gas to be produced from our oil and gas properties that are included in the
borrowing base determination, calculated using a discount rate of 10% per annum
and reserve estimates, prices and production rates and costs, (ii) options
to lease, seismic options, permits, and records related to such properties, and
(iii) seismic data.
Borrowings under our credit facility, as amended, bear
interest either: (i) at the greater of the one month London Interbank
Offered Rate, or LIBOR, plus 1.00% or a domestic bank rate, plus in either case
an applicable margin of 0.75% to 1.75% based on utilization, or (ii) on a
sliding scale from the one, two, three or six month LIBOR, plus an applicable
margin of 2.00% to 3.00% based on utilization. The weighted average interest
rate as of March 31, 2010 was 5.0%.
The credit agreement provides for various fees, including a quarterly
commitment fee of 0.5% per annum and engineering fees to the administrative
agent in connection with a borrowing base determination. In addition, the
credit facility provided for an up front fee of $27,000, which was paid on the
closing date of the credit facility, and an additional arrangement fee of 1%
based on utilization. Borrowings under this credit facility may be prepaid
without premium or penalty, except on Eurodollar advances.
The credit agreement, as amended, contains covenants
that among other things restrict our ability (subject to certain exceptions) to
do the following:
·
incur liens;
·
incur debt;
·
make investments in other persons;
32
Table
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·
declare dividends or redeem or repurchase stock;
·
engage in mergers, acquisitions, consolidations and
asset sales or amend our organizational documents;
·
enter into certain hedging arrangements;
·
amend material contracts; and
·
enter into related party transactions.
With regard to hedging arrangements, our credit
agreement provides that acceptable commodity hedging arrangements cannot cover
greater than 80 to 85%, depending on the measurement date, of our monthly
production from our hydrocarbon properties that are used in the borrowing base
determination, and that the fixed or floor price of our hedging arrangements
must be equal to or greater than the gas price used by the lenders in
determining the borrowing base.
The credit agreement, as amended, also requires that
we satisfy certain affirmative covenants, meet certain financial tests,
maintain certain financial ratios and make certain customary indemnifications
to lenders and the administrative agent. The financial covenants include
requirements to maintain: (i) a ratio of EBITDA to cash interest expense of
not less than 3.00 to 1.00, (ii) a ratio of current assets to current
liabilities of not less than 1.00 to 1.00, (iii) a total debt to
annualized EBITDA ratio of not more than 3.0 to 1.0, (iv) a quarterly
total senior debt to annualized EBITDA ratio equal to or less than 3.0 to 1.0,
and (v) a total proved PV-10 value to total debt ratio of at least 1.50 to
1.00.
The credit agreement, as amended, contains customary
events of default, including payment defaults, covenant defaults, certain
events of bankruptcy and insolvency, defaults in the payment of other material
debt, judgment defaults, breaches of representations and warranties, loss of
material permits and licenses and a change in control. The credit agreement
requires any wholly-owned subsidiaries to guarantee the obligations under the
credit agreement.
After an event of default, the outstanding debt bears
interest at the default rate under the terms of the credit agreement. The
default rate is (i) with respect to principal, 2% over the otherwise applicable
rate and (ii) with respect to interest, fees and other amounts, the Base
Rate (as defined in the credit facility), plus the Applicable Margin (as
defined in the credit agreement), plus 2%. Any default interest is payable on
demand. Failure to pay the default interest when the administrative agent
demands would be another default. The lenders remedies for defaults under the
credit agreement are to terminate further borrowings, accelerate the repayment
of indebtedness and/or ultimately foreclose on the collateral property.
Effective August 4, 2008, we and the
administrative agent and lender entered into the second amendment to the credit
agreement (the second amendment). The second amendment provided, among other
things, for (i) an increase in the total quarterly senior debt to
annualized EBITDA ratio from 2.0 to 1.0, to 3.0 to 1.0, (ii) an increase
in interest at each utilization level for LIBOR borrowings, (iii) the
amendment of the utilization calculation to be determined as the greater of (x) the
percentage of credit exposure over the borrowing base or (y) the
percentage of credit exposure over three times EBITDA minus permitted
subordinated debt, and (iv) the payment of an amendment fee.
Effective September 30, 2008, we and the
administrative agent and lender entered into the third amendment to the credit
agreement (the third amendment). In addition to waiving compliance with the
current ratio covenant as of September 30, 2008, the third amendment,
among other things, required that immediately prior to any additional
borrowings under the credit agreement, our ratio of current assets to current
liabilities be not less than 1.00 to 1.00. As a result of this new condition to
additional borrowings, we are currently unable to borrow additional amounts
under the credit agreement. The third amendment also increased the interest
rate payable under the credit agreement to either (i) the greater of the
one month LIBOR plus 1.00% or a domestic bank rate, plus in either case an
applicable margin of 0.75% to 1.75% based on utilization, or (ii) a
sliding scale from the one, two, three or six month LIBOR, plus an applicable
margin of 2.00% to 3.00% based on utilization, and provided for the payment of
an amendment fee.
On April 14,
2009, we and the administrative agent entered into the fourth amendment to the
credit agreement which reduced the borrowing base as described above and waived
compliance with the current ratio financial covenant as of December 31,
2008 and March 31, 2009 and with the restrictive covenants related to
accounts payable, permitted liens and permitted debt until the current ratio
financial covenant and next borrowing base redetermination, subject to certain
financial
33
Table
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caps. On August 19,
2009, the lenders waived compliance with the current ratio financial covenant
under the Credit Agreement for the period ending August 26, 2009 and the
quarter ending June 30, 2009.
On August 26,
2009, we entered into a fifth amendment to the credit agreement which provided
a waiver of the current ratio covenant through October 26, 2009 and for
the quarter ending June 30, 2009. The fifth amendment to the credit agreement
also extended restrictive covenants related to accounts payable, permitted
liens and permitted debt, until October 26, 2009, subject to certain
financial caps.
On October 20,
2009, we and the Lenders executed the sixth amendment to the credit agreement.
This amendment established the borrowing base for the following amounts in the
following applicable periods:
December 1,
2009 through December 31, 2009
|
|
$
|
6,300,000
|
|
January 1,
2010 through January 31, 2010
|
|
$
|
6,100,000
|
|
February 1,
2010 through February 28, 2010
|
|
$
|
5,900,000
|
|
March 1,
2010 through March 31, 2010
|
|
$
|
5,700,000
|
|
April 1,
2010 through April 30, 2010
|
|
$
|
5,500,000
|
|
Each Calendar
month thereafter commencing May 1, 2010; the borrowing base for the
preceding calendar month reduced by $200,000.
On October 26,
2009, the lenders provided a waiver effectively extending the terms of the
fifth amendment to the credit agreement through November 16, 2009. On November 16,
2009, the lenders provided an additional waiver effectively extending the terms
of the fifth amendment to the credit agreement through November 23, 2009.
On November 23,
2009, the lenders provided an additional waiver extending the terms of the
fifth amendment to the credit agreement through December 1, 2009 and for
the quarter ended December 31, 2009.
On December 1,
2009 the lenders provided an additional waiver extending the terms of the fifth
amendment to the credit agreement through January 5, 2010.
On January 5,
2010 the lenders provided an additional waiver extending the terms of the fifth
amendment to the credit agreement through January 12, 2010.
On January 13,
2010, we entered into a seventh amendment and waiver to credit agreement (
waiver agreement
) with the lenders party
thereto. The waiver agreement provided that the lenders would waive (i) our
compliance with certain restrictions based on the current ratio in the credit
agreement, (ii) certain requirements pertaining to the aging of certain
accounts payable, and (iii) certain restrictions regarding the amount of
liens we have. Default remedies available to the lenders under the credit
agreement include acceleration of all principal and interest amounts due under
the credit agreement. The waiver agreement extends the waiver period for these
items until the earlier of June 15, 2010 and the date of any default
arising out of a breach or non-compliance with the credit agreement not
expressly waived in the waiver agreement or a breach of the waiver agreement.
In addition, the
waiver agreement amends the definition of Final Maturity Date under the
credit agreement to the earlier of (i) June 15, 2010 or (ii) the
date that is thirty days following the earlier of (A) the date the merger
is withdrawn or terminated in whole or in part or (B) the date that the
lenders have been advised that the merger will not proceed.
Office
Building Loan.
On November 15, 2005, we entered into a mortgage
loan secured by our office building in Sheridan, Wyoming in the aggregate
principal amount of $829,000. The promissory note provides for monthly payments
of principal and interest in the initial amount of $6,400, and unpaid principal
that bore interest at 6.875% until November 15, 2008, currently bears
interest at a variable base rate plus 0.5% and will bear interest at 18% upon a
default. The variable base rate is based on the lenders base rate. The
maturity date of this mortgage is November 15, 2015, at which time a
principal and interest payment of $520,800 will become due. As of March 31,
2010, we had $725,000 outstanding in principal on this mortgage. On November 15,
2008, the interest rate on our mortgage loan changed from a fixed rate of
6.875% to a variable rate. As of March 31, 2010, the variable rate was
4.00%.
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Table
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Capital
Expenditure Budget
.
The continued
credit crisis and related turmoil in the global financial system have had an
adverse impact on our business and financial condition. In addition, the prices
of oil and natural gas declined significantly in 2008 and remained low in 2009
and the first quarter of 2010. Therefore, total capital expenditures were
limited to $4.2 million in 2009. As a result of low CIG index prices, the
economic climate and our limited capital resources, we expect to continue
operating during 2010 with a reduced capital expenditure plan. Under our plan,
we will generally make expenditures only as necessary to secure drilling
permits in strategic areas, drill wells that secure leasehold positions and
construct the necessary infrastructure to complete and hook-up wells that have
already been drilled. Our capital expenditure budget for 2010 will be dependent
upon CIG index prices, our cash flows and the availability of additional
capital resources. We had total capital expenditures of $0.7 million for the
three months ended March 31, 2010.
Cash Flow from Operating Activities
Net cash provided
by operating activities was $1.8 million for the three months ended March 31,
2010, compared to $0.7 million for the three months ended March 31, 2009.
The change was primarily due to an increase in accounts payable, an increase in
accrued liabilities, and an increase in revenue distribution payables.
Cash Flow from Investing Activities
Net cash used in
investing activities was approximately $0.9 million for the three months
ended March 31, 2010, compared to net cash provided by operating
activities of $49,000 for the three months ended March 31, 2009. The
change in 2010 was primarily due to a realized loss on derivatives.
Cash
Flow from Financing Activities
Net cash used in
financing activities was $0.6 million for the three months ended March 31,
2010, compared to $1.0 million for the three months ended March 31, 2009.
The change in 2010 was primarily due to a reduction in the balance owed on the
line of credit for the quarter ended March 31, 2010.
There have been no
issuances of shares of common stock since our initial public offering except to
employees, executive officers and directors pursuant to our incentive stock
plan.
Contractual Obligations
Please see Notes 3 and 7
of the Notes to the unaudited financial statements appearing elsewhere in this
quarterly report for information regarding our credit facility and other indebtedness.
The following table
summarizes by period our contractual obligations as of March 31, 2010:
|
|
Total
|
|
2010
|
|
20112012
|
|
20132014
|
|
Thereafter
|
|
|
|
(In Thousands)
|
|
Notes
payable in connection with mortgage and equipment
|
|
$
|
749
|
|
$
|
31
|
|
$
|
89
|
|
$
|
76
|
|
$
|
553
|
|
Capital
lease
|
|
55
|
|
11
|
|
34
|
|
10
|
|
|
|
Asset
retirement obligations
|
|
2,959
|
|
710
|
|
752
|
|
395
|
|
1,102
|
|
Production
and property taxes
|
|
3,656
|
|
2,991
|
|
665
|
|
|
|
|
|
Total
|
|
$
|
7,419
|
|
$
|
3,743
|
|
$
|
1,540
|
|
$
|
481
|
|
$
|
1,655
|
|
35
Table
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ITEM 3. 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 risk. The term market
risk refers to the risk of loss arising from adverse changes in natural gas
prices or interest rates. This forward-looking information provides indicators
of how we view and manage our ongoing market risk exposure. All of our market
risk sensitive instruments were entered into for purposes other than
speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing
applicable to our natural gas production. The prices we receive for our
production depend on many factors beyond our control. We seek to reduce our
exposure to unfavorable changes in natural gas prices, which are subject to
significant and often volatile fluctuation, through the use of fixed-price
contracts. Our fixed-price contracts are comprised of energy swaps and collars.
Fixed price contracts allow us to predict with greater certainty the effective
natural gas prices to be received for hedged production and benefit operating
cash flows and earnings when market prices are less than the fixed prices
provided by the contracts. However, we will not benefit from market prices that
are higher than the fixed prices in the contracts for hedged production. Collar
structures provide for participation in price increases and decreases to the
extent of the ceiling prices and floors provided in those contracts. With
regard to hedging arrangements, our credit facility provides that acceptable
commodity hedging arrangements cannot cover greater than 80 to 85%, depending
on the measurement date, of our monthly production from our hydrocarbon
properties that are used in the borrowing base determination, and that the
fixed or floor price of our hedging arrangements must be equal to or greater
than the gas price used by the lenders in determining the borrowing base.
The following table summarizes the estimated volumes,
fixed prices, fixed price sales and fair value attributable to the fixed price
contracts as of March 31, 2010. At March 31, 2010, we had hedged
volumes through December 2010. Please see Note 5 of the Notes to the
unaudited financial statements appearing elsewhere in this quarterly report for
further information regarding our derivatives.
|
|
Year Ending
December 31, 2010
|
|
|
|
(Unaudited)
|
|
Natural Gas Swaps:
|
|
|
|
Contract
volumes (MMBtu)
|
|
1,512,500
|
|
Weighted-average
fixed price sales per MMBtu(1)
|
|
$
|
4.98
|
|
Fair
value, net (thousands)(2)
|
|
$
|
1,513
|
|
Total Natural Gas Contracts:
|
|
|
|
Contract
volumes (MMBtu)
|
|
1,512,500
|
|
Fixed-price
sales
|
|
$
|
4.98
|
|
Fair
value, net (thousands)(2)
|
|
$
|
1,513
|
|
(1)
Volumes hedged using the CIG index price
published in the first issue of Inside FERCs Gas Market Report for each calendar
month of the derivative transaction.
(2)
Fair value based on CIG index price in
effect for each month as of March 31, 2010.
Interest Rate Risk
Borrowings under our
credit facility bear interest at fluctuating market-based rates. Accordingly, our interest expenses are
sensitive to market changes, which expose us to interest rate risk on current
and future borrowings under our credit facility.
As of March 31,
2010, we had $5.5 million in outstanding indebtedness under our credit
facility. Borrowings under the credit facility bear interest either: (i) at
the greater of the one month LIBOR plus 1.00% or a domestic bank rate, plus in
either case an applicable margin of 0.75% to 1.75% based on utilization, or (ii) on
a sliding scale from one, two, three, or six month LIBOR, plus an applicable
margin of 2.00% to 3.00% based on utilization. The weighted average interest
rate for borrowings under our credit facility was 5.0% for the three months
ended March 31, 2010 and for the year ended December 31, 2009,
respectively. In light of the current economic climate, we expect that interest
rates on alternative financing options to range from 8% to 12%. The
availability of alternative financing arrangements and the interest rates
36
Table
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thereof would depend on
the type of financing and our ability to restructure our current indebtness
outstanding under our credit facility. Due to covenant restrictions in our
credit facility, we are currently unable to borrow additional amounts.
A hypothetical change of
1% in either the domestic bank rate or the LIBOR interest rates would increase
or decrease gross interest expense approximately $55,000 per year based on our
outstanding indebtness at March 31, 2010.
ITEM 4T. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our principal executive officer and principal
financial officer are responsible for establishing and maintaining adequate
disclose controls and procedures. Based
on their evaluation as of the end of the period covered by this quarterly
report, our principal executive officer and principal financial officer have
concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934, as amended (the
Exchange Act)) are effective to ensure that information required to be
disclosed in reports that we file or submit under the Exchange Act are
recorded, processed, summarized and reported within the time periods specified
in the SECs rules and forms.
Changes in Internal Control Over
Financial Reporting
During the most recent fiscal quarter, there has been
no change in our internal control over financial reporting that has materially
affected, or is reasonably likely to materially affect, our internal control
over financial reporting.
37
Table of Contents
PART II. OTHER INFORMATION
ITEM
1. LEGAL PROCEEDINGS
From time to time, we are
subject to legal proceedings and claims that arise in the ordinary course of
our business. While the outcome of these proceedings cannot be predicted with
certainty, we do not currently expect them to have a material adverse effect on
the financial statements.
There has been no
material developments during the quarter ended March 31, 2010 regarding
our currently pending legal proceedings. For a discussion of certain of our
current legal proceedings, please see Note 9 Commitments and Contingencies
of the Notes to the unaudited financial statements appearing elsewhere in this
quarterly report.
ITEM
1A. RISK FACTORS
The following
discussion supplements or updates the risk factors set forth under the heading Risk
Factors in our annual report on Form 10-K for the year ended December 31,
2009.
Due to the recent
financial and credit crisis, we may not be able to obtain funding, or obtain
funding on acceptable terms, to meet our future capital needs, which could
negatively affect our business, results of operations and financial condition.
The continued
credit crisis and the related turmoil in the global financial system have had
an adverse impact on our business and financial condition, and we may face
major challenges if conditions in the financial markets do not improve.
Currently, we are not able to borrow additional amounts under our credit
facility. As a result, we curtailed substantially all new drilling in 2009 and
if our operating cash flow is not sufficient to carry out our drilling plans
for 2010, we will be required to reduce the number of wells we drill or seek
alternative sources of financing. However, due to the financial crisis,
financing through the capital markets or otherwise may not be available to us
on acceptable terms or at all. If additional funding is not available, or is
available only on unfavorable terms, we may be unable to implement our drilling
plans, make capital expenditures, withstand a further downturn in our business
or the economy in general, or take advantage of business opportunities that may
arise. Any further curtailment of our operations would have an additional
adverse effect on our revenues and results of operations. In addition, current
economic conditions have led to reduced demand for, and lower prices of, oil
and natural gas, and a sustained decline the price of natural gas would
adversely affect our business, results of operations and financial condition.
Please read The volatility of natural gas and oil prices could have a material
adverse effect on our business below. Further, the economic situation could
have an impact on our lenders or customers, causing them to fail to meet their
obligations to us, and on the liquidity of our operating partners, resulting in
delays in operations or their failure to make required payments. Also, market
conditions could have an impact on our natural gas and oil derivatives
transactions if our counterparties are unable to perform their obligations or
seek bankruptcy protection.
Our contemplated merger
agreement may not be consummated.
We have entered an
Agreement and Plan of Merger, as further described in Note 10 in the notes
to the unaudited financial statements herein and in the proxy statement filed April 2,
2010. There can be no assurances that the contemplated merger transaction will
occur. If the merger is not consummated, we will continue to need additional
capital to remain a going concern and successfully operate our business.
Our credit facility has substantial restrictions and
financial covenants that may affect our ability to successfully operate our
business. In addition, we may have difficulty returning to compliance with
certain financial covenants.
Our credit
facility imposes certain operational and financial restrictions on us. These
restrictions, among other things, limit our ability to:
·
incur additional indebtedness;
·
create liens;
·
sell our assets or consolidate or merge with or into other companies;
38
Table
of Contents
·
make investments and other restricted payments, including dividends;
and
·
engage in transactions with affiliates.
These limitations
are subject to a number of important qualifications and exceptions. In
addition, our credit facility requires us to maintain certain financial ratios
and to satisfy certain financial conditions which may require us to reduce our
debt or to take some other action in order to comply with them. These restrictions
in our credit facility could also limit our ability to obtain future
financings, make needed capital expenditures, withstand a downturn in our
business or the economy in general, or otherwise conduct necessary corporate
activities. We also may be prevented from taking advantage of business
opportunities that arise because of the limitations imposed on us by the
restrictive covenants under our credit facility.
We were not in
compliance with the current ratio financial covenant and certain other covenants
related to accounts payable, permitted liens and permitted debt under our
credit facility, and would be in default absent a waiver or amendment. On January 13,
2010, the lenders waived compliance with the current ratio as of December 31,
2009 through June 15, 2010, and with such other restrictive covenants,
subject to certain financial caps. We have also not been in compliance with
certain financial covenants for the last seven quarters, but obtained waivers
and/or amendments in each instance. In addition, the final maturity date of the
funds outstanding under our credit facility has accelerated to June 15,
2010. As a result of such non-compliance, we are unable to borrow additional
funds under our credit agreement.
Please see Managements
Discussion and Analysis of Financial Condition and Results of
OperationsLiquidity and Capital ResourcesCredit Facility, for further
discussion of our credit facility.
ITEM 2. UNREGISTERED SHARES OF EQUITY
SECURITIES AND USE OF PROCEEDS
Not
applicable.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not
applicable.
ITEM 4. SUBMISSION OF MATTERS TO
A VOTE OF SECURITY HOLDERS
Not
applicable.
ITEM 5. OTHER INFORMATION
Not applicable.
39
Table of Contents
ITEM 6. EXHIBITS
Exhibit
No.
|
|
Description
|
2.1
|
|
Amended and Restated
Agreement and Plan of Merger, dated as of February 23, 2010, among
Powder Holdings, LLC, Pinnacle Gas Resources, Inc. and Powder
Acquisition, Co. (incorporated by reference to Exhibit 2.1 to the
Current Report on Form 8-K (File No. 001-33457) filed by Pinnacle
Gas Resources, Inc. on February 26, 2010).
|
3.1
|
|
Second Amended and Restated Certificate of
Incorporation of Pinnacle Gas Resources, Inc. (incorporated herein by
reference to Exhibit 3.1 to the Registration Statement on Form S-1
(File No. 333-133983) filed by Pinnacle Gas Resources, Inc. on
May 10, 2006).
|
3.2
|
|
Amended and Restated Bylaws of Pinnacle Gas
Resources, Inc. (incorporated herein by reference to Exhibit 3.2 to
the Registration Statement on Form S-1 (File No. 333-133983) filed
by Pinnacle Gas Resources, Inc. on May 10, 2006).
|
4.1
|
|
Amended and Restated Securityholders Agreement,
dated February 16, 2006 (incorporated herein by reference to
Exhibit 4.1 to the Registration Statement on Form S-1 (File
No. 333-133983) filed by Pinnacle Gas Resources, Inc. on
May 10, 2006).
|
4.2
|
|
Registration Rights Agreement, dated April 11,
2006 (incorporated herein by reference to Exhibit 4.2 to the
Registration Statement on Form S-1 (File No. 333-133983) filed by
Pinnacle Gas Resources, Inc. on May 10, 2006).
|
10.21
|
|
Fourth Amendment to
Credit Agreement, dated as of April 14, 2009 (incorporated herein by
reference to Exhibit 10.21 to the Annual Report on Form 10-K (File
No. 001-33457) filed by Pinnacle Gas Resources, Inc. on
April 15, 2009).
|
10.22
|
|
Waiver to Credit
Agreement, dated as of August 19, 2009 (incorporated herein by reference
to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed by
Pinnacle Gas Resources on August 19, 2009).
|
10.23
|
|
Fifth Amendment to the
Credit Agreement, dated August 26, 2009 (incorporated herein by
reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas
Resources, Inc. on August 27, 2009).
|
10.24
|
|
Sixth Amendment to the
Credit Agreement, dated October 20, 2009 (incorporated herein by
reference to Exhibit 10.1 to the 8-K filed by Pinnacle Gas
Resources, Inc. on October 22, 2009).
|
10.25
|
|
Waiver and Amendment,
dated October 26, 2009 (incorporated herein by reference to
Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on
October 29, 2009).
|
10.26
|
|
Waiver and Amendment,
dated November 16, 2009 (incorporated herein by reference to
Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on
November 19, 2009).
|
10.27
|
|
Waiver and Amendment,
dated November 23, 2009 (incorporated herein by reference to
Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on
November 23, 2009).
|
10.28
|
|
Waiver and Agreement
dated as of January 5, 2010 (incorporated herein by reference to
Exhibit 10.1 to the 8-K filed by Pinnacle Gas Resources, Inc. on
January 8, 2010).
|
10.29
|
|
Seventh Amendment and
Waiver to the Credit Agreement dated as of January 13, 2010
(incorporated herein by reference to Exhibit 10.1 to the 8-K filed by
Pinnacle Gas Resources, Inc. on January 19, 2010).
|
*31.1
|
|
Certification of President and Chief Executive
Officer of Pinnacle Gas Resources, Inc. pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
|
*31.2
|
|
Certification of Senior Vice President, Chief
Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
|
*32.1
|
|
Certification of President and Chief Executive
Officer of Pinnacle Gas Resources, Inc. pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
*32.2
|
|
Certification of Senior Vice President, Chief
Financial Officer and Secretary of Pinnacle Gas Resources, Inc. pursuant
to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
|
* Filed
herewith
40
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
|
PINNACLE GAS RESOURCES, INC.
|
|
|
|
By:
|
/s/ Peter G.
Schoonmaker
|
|
Name:
|
Peter G. Schoonmaker
|
|
Title:
|
President,
Chief Executive
|
|
|
Officer
and Director
|
|
|
(Principal Executive
Officer)
|
|
|
|
|
Date:
|
May 14, 2010
|
|
|
|
|
By:
|
/s/ Ronald T. Barnes
|
|
Name:
|
Ronald T. Barnes
|
|
Title:
|
Senior
Vice President, Chief Financial
|
|
|
Officer
and Secretary
|
|
|
(Principal Financial
Officer and
|
|
|
Principal Accounting
Officer)
|
|
|
|
|
Date:
|
May 14, 2010
|
41
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