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 June 30, 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
30,303,427 shares of the
registrants Common Stock were outstanding as of August 16, 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 prospectus, 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;
·
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;
1
Table of Contents
·
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 in the Risk Factors section of our
annual report on Form 10-K for the year ended December 31, 2009 and this
quarterly report on
Form 10-Q.
2
Table of Contents
Part I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PINNACLE GAS RESOURCES, INC.
Balance Sheets
|
|
June 30,
2010
|
|
December 31,
2009
|
|
|
|
(unaudited)
|
|
(audited)
|
|
|
|
(in thousands, except
|
|
|
|
share and
|
|
|
|
per share data)
|
|
Assets
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
144
|
|
$
|
175
|
|
Receivables
|
|
|
|
|
|
Accrued gas sales
|
|
866
|
|
1,240
|
|
Joint interest receivables, net of $14 and $100
allowance for doubtful accounts, respectively
|
|
2,173
|
|
1,207
|
|
Derivative instruments
|
|
903
|
|
|
|
Inventory of material held for exploration and
development
|
|
56
|
|
229
|
|
Restricted certificates of deposits
|
|
|
|
142
|
|
Prepaid expenses
|
|
22
|
|
134
|
|
Total current assets
|
|
4,164
|
|
3,127
|
|
Property and equipment, at cost, net of
accumulated depreciation
|
|
313
|
|
1,055
|
|
Oil and gas properties, using full cost
accounting, net of accumulated depletion and impairment
|
|
|
|
|
|
Proved
|
|
9,694
|
|
9,477
|
|
Unproved
|
|
49,750
|
|
48,700
|
|
Inventory of material held for exploration and
development
|
|
390
|
|
223
|
|
Deposits
|
|
57
|
|
76
|
|
Restricted certificates of deposit
|
|
499
|
|
1,842
|
|
Total assets
|
|
$
|
64,867
|
|
$
|
64,500
|
|
Liabilities and Stockholders Equity
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
Long term debt-current portion
|
|
$
|
5,154
|
|
$
|
6,148
|
|
Derivative instruments, current
|
|
|
|
1,375
|
|
Trade accounts payable
|
|
9,873
|
|
9,058
|
|
Revenue distribution payable
|
|
4,632
|
|
3,328
|
|
Drilling prepayments from joint interest owners
|
|
45
|
|
63
|
|
Asset retirement obligations, current
|
|
817
|
|
721
|
|
Accrued liabilities
|
|
4,002
|
|
3,090
|
|
Total current liabilities
|
|
24,523
|
|
23,783
|
|
Asset retirement
obligations, non-current
|
|
2,178
|
|
2,216
|
|
Production taxes, non-current
|
|
462
|
|
385
|
|
Long term debt, non-current
|
|
727
|
|
743
|
|
Total liabilities
|
|
27,890
|
|
27,127
|
|
Commitments and contingencies
|
|
|
|
|
|
Stockholders equity
|
|
|
|
|
|
Common stock, $0.01 par value; 100,000,000
authorized and 30,310,893 and 30,108,023 shares issued and outstanding at June
30, 2010 and December 31, 2009, respectively
|
|
289
|
|
289
|
|
Additional paid-in capital
|
|
151,949
|
|
151,725
|
|
Accumulated deficit
|
|
(115,261
|
)
|
(114,641
|
)
|
Total stockholders equity
|
|
36,977
|
|
37,373
|
|
Total liabilities and stockholders equity
|
|
$
|
64,867
|
|
$
|
64,500
|
|
See Notes to Financial Statements (unaudited)
3
Table of Contents
PINNACLE GAS RESOURCES, INC.
Statements
of Operations
(unaudited)
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
June 30,
|
|
June 30,
|
|
|
|
2010
|
|
2009
|
|
2010
|
|
2009
|
|
|
|
(in thousands, except share and
|
|
|
|
per share data)
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Gas sales
|
|
$
|
1,936
|
|
$
|
1,605
|
|
$
|
4,782
|
|
$
|
4,370
|
|
Realized gain on derivatives
|
|
590
|
|
2,053
|
|
124
|
|
3,510
|
|
Total revenues
|
|
2,526
|
|
3,658
|
|
4,906
|
|
7,880
|
|
Cost of revenues and expenses
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
769
|
|
939
|
|
1,787
|
|
2,124
|
|
Production taxes
|
|
208
|
|
140
|
|
526
|
|
418
|
|
Marketing and transportation
|
|
753
|
|
895
|
|
1,476
|
|
2,145
|
|
General and administrative, net
|
|
1,017
|
|
1,183
|
|
2,424
|
|
2,214
|
|
Depreciation, depletion, amortization and
accretion
|
|
843
|
|
916
|
|
1,558
|
|
2,744
|
|
Impairment of oil and gas properties
|
|
|
|
6,431
|
|
|
|
23,250
|
|
Total cost of revenues and expenses
|
|
3,590
|
|
10,504
|
|
7,771
|
|
32,895
|
|
Operating loss
|
|
(1,064
|
)
|
(6,846
|
)
|
(2,865
|
)
|
(25,015
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
Unrealized gain/(loss) on derivatives
|
|
(610
|
)
|
(2,704
|
)
|
2,278
|
|
(2,133
|
)
|
Interest income
|
|
19
|
|
26
|
|
33
|
|
34
|
|
Other income
|
|
93
|
|
95
|
|
238
|
|
200
|
|
Interest expense
|
|
(207
|
)
|
(30
|
)
|
(304
|
)
|
(55
|
)
|
Total other income (expense)
|
|
(705
|
)
|
(2,613
|
)
|
2,245
|
|
(1,954
|
)
|
Net loss before income taxes
|
|
(1,769
|
)
|
(9,459
|
)
|
(620
|
)
|
(26,969
|
)
|
Income taxes
|
|
|
|
|
|
|
|
|
|
Net loss attributable to common stockholders
|
|
$
|
(1,769
|
)
|
$
|
(9,459
|
)
|
$
|
(620
|
)
|
$
|
(26,969
|
)
|
Basic and diluted net loss per share
|
|
$
|
(.06
|
)
|
$
|
(0.32
|
)
|
$
|
(.02
|
)
|
$
|
(0.92
|
)
|
Weighted average shares outstanding basic and
diluted
|
|
30,318,454
|
|
29,364,087
|
|
30,282,892
|
|
29,277,885
|
|
See Notes to Financial Statements (unaudited)
4
Table of Contents
PINNACLE GAS RESOURCES, INC.
Statements
of Cash Flows
(in thousands)
(unaudited)
|
|
For the Six Months
Ended
June 30,
|
|
|
|
2010
|
|
2009
|
|
Cash flows from operating activities
|
|
|
|
|
|
Net loss
|
|
$
|
(620
|
)
|
$
|
(26,969
|
)
|
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities
|
|
|
|
|
|
Impairment of oil and gas properties
|
|
|
|
23,250
|
|
Depreciation, depletion, amortization and
accretion
|
|
1,558
|
|
2,723
|
|
Gain on derivatives
|
|
(2,402
|
)
|
(1,377
|
)
|
Stock-based compensation
|
|
224
|
|
508
|
|
Changes in assets and liabilities
|
|
|
|
|
|
(Increase) decrease in receivables
|
|
(592
|
)
|
1,515
|
|
Decrease in inventory of material held for
exploration and development
|
|
173
|
|
26
|
|
Decrease in prepaid expenses
|
|
112
|
|
100
|
|
Increase in accounts payable and accrued
liabilities
|
|
1,798
|
|
820
|
|
Increase (decrease) in revenue distribution
payable
|
|
1,304
|
|
(1,714
|
)
|
(Decrease) increase in drilling prepayments
|
|
(18
|
)
|
56
|
|
Asset retirement obligations settled this period
|
|
(49
|
)
|
|
|
Net cash provided by (used in) operating
activities
|
|
1,488
|
|
(1,062
|
)
|
Cash flows from investing activities
|
|
|
|
|
|
Capital expenditures exploration and production
|
|
(1,880
|
)
|
(2,488
|
)
|
Capital expenditures property and equipment
|
|
(90
|
)
|
(88
|
)
|
Proceeds received from sale of oil and gas
properties
|
|
|
|
3,200
|
|
Decrease in purchase of restricted certificate of
deposit and deposits
|
|
1,504
|
|
120
|
|
Increase in inventory held for exploration and
development
|
|
(167
|
)
|
(20
|
)
|
Realized gain on derivatives
|
|
124
|
|
3,510
|
|
Net cash (used in) provided by investing
activities
|
|
(509
|
)
|
4,234
|
|
Cash flows from financing activities
|
|
|
|
|
|
Principal payments on note payable
|
|
(1,010
|
)
|
(3,471
|
)
|
Net cash used in financing activities
|
|
(1,010
|
)
|
(3,471
|
)
|
Net decrease in cash and cash equivalents
|
|
(31
|
)
|
(299
|
)
|
Cash and cash equivalents at beginning of the year
|
|
175
|
|
346
|
|
Cash and cash equivalents at June 30, 2010 and
2009, respectively
|
|
$
|
144
|
|
$
|
47
|
|
Noncash investing and financing activities
|
|
|
|
|
|
Capital expenditures included in trade accounts
payable
|
|
$
|
6,413
|
|
$
|
6,740
|
|
Asset retirement obligation included in oil and
gas properties
|
|
1
|
|
|
|
Supplemental cash flow information
|
|
|
|
|
|
Cash payments for interest, net of amount
capitalized
|
|
$
|
304
|
|
$
|
55
|
|
See Notes to Financial Statements (unaudited)
5
Table of Contents
PINNACLE GAS RESOURCES, INC.
Statement
of Stockholders Equity
(in thousands, except for share data)
|
|
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 shares (unaudited)
|
|
212,502
|
|
|
|
187
|
|
|
|
187
|
|
Forfeiture of restricted shares (unaudited)
|
|
(9,632
|
)
|
|
|
|
|
|
|
|
|
Stock-based compensation (unaudited)
|
|
|
|
|
|
37
|
|
|
|
37
|
|
Net loss (unaudited)
|
|
|
|
|
|
|
|
(620
|
)
|
(620
|
)
|
Balance at June 30, 2010 (unaudited)
|
|
30,310,893
|
|
$
|
289
|
|
$
|
151,949
|
|
$
|
(115,261
|
)
|
$
|
36,977
|
|
See Notes to Financial Statements (unaudited)
6
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.
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 direct, wholly owned subsidiary of Powder Holdings (Merger
Agreement). 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 and on June 29, 2010, the
Company filed a definitive proxy statement relating to the merger, with the
U.S. Securities and Exchange Commission.
At the special meeting of the shareholders on August 9, 2010, the
shareholders of the Company voted to approve a proposal to adopt the Merger
Agreement. The Company anticipates that the closing will occur during the third
quarter, subject to the satisfaction of customary closing conditions and the
receipt of waivers from the Companys lender, The Royal Bank of Scotland plc.
Although
the Company anticipates closing will occur in the third quarter, 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. 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. Management believes that
appropriate steps, including cost-cutting measures, are being taken to make
operations sustainable in the future. Although the Company is pursuing various
alternatives to provide additional liquidity, including its shareholder
approved merger with Powder, there is no assurance of the likelihood or timing
of any of these transactions.
In addition 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
CIG Rocky Mountain Index 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 CIG Rocky Mountain Index price of $5.08 per MMbtu.
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 six months of 2010. The results for the three and six months
ending June 30, 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 or on the
Securities and Exchange Commission website at
www.sec.gov
.
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
7
Table of Contents
properties,
the estimate of the timing and cost of the Companys future drilling activity,
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. No impairment was recorded for unevaluated properties for the three
and six months ended June 30, 2010.
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. As of June 30, 2010 and December 31, 2009, the estimated value was
approximately $6.8 million.
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 June 30, 2010, the full cost ceiling
limitation exceeded the capitalized cost of the Companys oil and gas
properties by approximately $5.2 million based on the first day of the month,
twelve month average CIG price of approximately $3.76 per Mcf. Therefore, no
impairment was taken for the quarter ended June 30, 2010. An impairment of $6.4
million was taken for the quarter ended June 30, 2009 based on a natural gas price
of $3.09 per Mcf.
Per Share Information
Basic loss per share is
computed by dividing net 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
six months ended June 30, 2010, basic and diluted net loss per share was
$0.02. During the six months ended June 30, 2010, 835,446 options and
stock appreciation rights were excluded because they were anti-dilutive.
8
Table of
Contents
|
|
(in thousands except per share data)
|
|
|
|
Three
Months Ended
June 30,
|
|
Six
Months Ended
June 30,
|
|
Three
Months Ended
June 30,
|
|
Six
Months Ended
June 30,
|
|
|
|
2010
|
|
2009
|
|
Net loss
|
|
$
|
(1,769
|
)
|
$
|
(620
|
)
|
$
|
(9,459
|
)
|
$
|
(26,969
|
)
|
Common shares outstanding:
|
|
|
|
|
|
|
|
|
|
Historical common shares outstanding at beginning
of period
|
|
30,247
|
|
30,108
|
|
$
|
29,188
|
|
$
|
29,194
|
|
Weighted average common shares issued
|
|
71
|
|
175
|
|
176
|
|
84
|
|
Weighted average common shares outstanding-basic
|
|
30,318
|
|
30,283
|
|
29,364
|
|
29,278
|
|
Net loss per share-basic and diluted
|
|
(0.06
|
)
|
(0.02
|
)
|
(0.32
|
)
|
(0.92
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 June 30, 2010 and December 31, 2009, the Company
had recorded a full valuation allowance for its net deferred tax asset.
New Accounting Pronouncements
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 June 30, 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.
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.
9
Table of Contents
The
following is a summary of the Companys asset retirement obligation activity
for the three and six months ended June 30, 2010 and June 30, 2009
(unaudited).
|
|
(in thousands)
|
|
|
|
For the Three
Months Ended
June 30,
|
|
For the Six
Months Ended
June 30,
|
|
For the Three
Months Ended
June 30,
|
|
For the Six
Months Ended
June 30,
|
|
|
|
2010
|
|
2009
|
|
Beginning balance asset retirement obligations
|
|
$
|
2,959
|
|
$
|
2,937
|
|
$
|
3,422
|
|
$
|
3,366
|
|
Additional obligation added during the period
|
|
|
|
1
|
|
|
|
|
|
Obligations settled during the period
|
|
(18
|
)
|
(49
|
)
|
(23
|
)
|
(23
|
)
|
Accretion expense
|
|
54
|
|
106
|
|
58
|
|
114
|
|
Ending balance of asset retirement obligations
|
|
$
|
2,995
|
|
$
|
2,995
|
|
$
|
3,457
|
|
$
|
3,457
|
|
Note 4
Restricted
Assets (Certificates of Deposit), Surety Bonds and Deposits
Certificates of deposit.
The Company holds a certificate of deposit (CD),
which expires in July 2011, totalling approximately $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 June 30, 2010. The issuer of the
bond has commenced litigation against the Company to increase its collateral
position, although this litigation was tolled through June 15, 2010 (see
Note 9).
On January 1, 2010 the Company held two
CDs for $604,000 and $964,000. These CDs collateralized letters of credit in
favor of Powder River Energy Corporation (PRECorp) in order to secure power
lines in the Recluse, Kirby, Deer Creek and Cabin Creek areas. These CDs were
to be renewed annually as the amount of the CDs would decrease over time as the
Company paid down the capital cost recovery amounts on its monthly billing. On February 14,
2010, the $604,000 CD was lowered to $513,000 and renewed on February 19,
2010. The $964,000 CD was set to expire on May 27, 2010. However, the
Company was presented with an opportunity to pay the capital cost recovery work
orders in full which would result in a savings of approximately $282,000 in
interest costs. On May 18, 2010,
the Company cashed the $513,000 CD and received approximately $506,000 in
proceeds and on May 21, 2010, the Company cashed the second CD and
received approximately $966,000 in proceeds. On May 20, 2010 the Company
wired $500,000 to PRECorp and on May 28, 2010 the Company wired
approximately $690,000 to PRECorp which fulfilled its obligation to PRECorp. In
March 2010 the Company posted a cash security deposit to Powder River
Energy Corp. of approximately $225,000 to collateralize electrical usage in its
Recluse, 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 drew approximately
$858,000 on this LOC for compression services provided to the Company in 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 June 30, 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.
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 June 30,
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
10
Table of Contents
totaling
$903,000 and an asset of $2,213,000 at June 30, 2010 and 2009,
respectively. The Company realized a hedging gain of $590,000 and a hedging
gain of $2,053,000 for the quarters ended June 30, 2010 and 2009,
respectively. As a result of the change in the fair value of the commodity
derivatives, the Company had an unrealized loss of $610,000 for the quarter
ended June 30, 2010 and unrealized loss of $2,704,000 for the quarter
ended June 30, 2009. For the six months ended June 30, 2010, the
Company realized a hedging gain of $124,000 compared to a hedging gain of
$3,510,000 for the six months ended June 30, 2009. For the six months
ended June 30, 2010, the Company had an unrealized gain of $2,278,000
compared to an unrealized loss of $2,133,000 for the six months ended June 30,
2009. The aggregate of these contracts resulted in a gain on derivatives of
$2,403,000 and $1,377,000 for the six months ended June 30, 2010 and 2009,
respectively. Unrealized gains and losses are included in gains or losses on
derivatives in the statement of operations. Realized gains and losses are
included in revenues in the statements of operations. As of June 30, 2010 and 2009, the
Company had natural gas hedges in place as follows:
As
of June 30, 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
|
|
June 30, 2010 (unaudited)
|
|
|
|
|
|
|
|
Natural GasSwap
|
|
2,000
|
|
$4.48
|
|
01/10-12/10
|
|
Natural GasSwap
|
|
1,000
|
|
$5.50
|
|
01/10-12/10
|
|
Natural GasSwap
|
|
2,500
|
|
$5.40
|
|
05/10-12/10
|
|
June 30, 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
|
|
1,000
|
|
$4.00
|
|
06/09-12/09
|
|
Natural GasSwap
|
|
2,500
|
|
$3.45
|
|
05/09-04/10
|
|
Natural GasSwap
|
|
2,000
|
|
$4.48
|
|
01/10-12/10
|
|
Natural GasSwap
|
|
1,000
|
|
$5.50
|
|
01/10-12/10
|
|
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 Stock Incentive Plan
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.
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 June 30, 2010, there
were options to purchase 640,000 shares granted under the plan.
The
options granted since formation in June 2003 vest in general as follows:
Year 1
|
|
20
|
%
|
Year 2
|
|
30
|
%
|
Year 3
|
|
50
|
%
|
|
|
100
|
%
|
During
the three months ended June 30, 2010, the Company did not grant any
options to purchase common stock. During
the three and six months ended June 30, 2010 the Company recognized an
expense of approximately $6,000 and $25,000, respectively, based on the fair
value of the vested options.
11
Table of Contents
The
following table summarizes stock option activity for the six months ended June 30,
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, June 30, 2010 (unaudited)
|
|
640,000
|
|
$
|
5.81
|
|
1.83
|
|
$
|
|
|
Exercisable, June 30, 2010 (unaudited)
|
|
640,000
|
|
$
|
5.81
|
|
1.83
|
|
$
|
|
|
The
following table summarizes information about stock options outstanding at June 30,
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
|
|
0.3 years
|
|
137,500
|
|
$
|
4.00
|
|
Black-Scholes
(minimum value)
|
|
$4.80
|
|
265,000
|
|
1.7 years
|
|
265,000
|
|
$
|
4.80
|
|
Black-Scholes
(minimum value)
|
|
$5.20
|
|
112,500
|
|
2.5 years
|
|
112,500
|
|
$
|
5.20
|
|
Black-Scholes
|
|
$8.40
|
|
25,000
|
|
3.9 years
|
|
25,000
|
|
$
|
8.40
|
|
Black-Scholes
|
|
$11.00
|
|
100,000
|
|
3.0 years
|
|
100,000
|
|
$
|
11.00
|
|
Black-Scholes
|
|
Total
|
|
640,000
|
|
|
|
640,000
|
|
|
|
|
|
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 195,446 were outstanding as of
June 30, 2010.
The
SARs granted in June 2010 vest in general as follows:
Year 1
|
|
33.33
|
%
|
Year 2
|
|
33.33
|
%
|
Year 3
|
|
33.34
|
%
|
|
|
100.00
|
%
|
At
June 30, 2010 the Company had unvested options to purchase 128,025 shares
with a weighted average grant date fair market value of $47,000.
The
following table summarizes stock appreciation activity for the six months ended
June 30, 2010:
|
|
Shares
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Weighted
Average
Remaining
Contractual
Life
|
|
Outstanding at December 31, 2009
|
|
202,280
|
|
0.41
|
|
|
|
Canceled or forfeited
|
|
(6,834
|
)
|
|
|
|
|
Outstanding at June 30, 2010 (unaudited)
|
|
195,446
|
|
$
|
0.41
|
|
5.9
|
|
|
|
|
|
|
|
|
|
|
During
the three and six months ended June 30, 2010, the Company recognized
compensation expense of approximately $6,000 and $12,000 respectively, based on
the fair value of the vested shares using a Black-Scholes model.
12
Table of Contents
Restricted Stock under the Stock Incentive Plan
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. During the three and six months ended June 30,
2010, the Company recognized compensation expense of approximately $58,000 and
$187,000, respectively, based on the fair value of the vested shares.
A
summary of the status and activity of the restricted stock for the six months
ended June 30, 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
|
|
Forfeited
|
|
(9,632
|
)
|
$
|
1.28
|
|
Vested
|
|
(282,424
|
)
|
$
|
0.43
|
|
Unvested
at June 30, 2010 (unaudited)
|
|
263,439
|
|
$
|
2.58
|
|
As
of June 30, 2010, the Company had approximately $0.4 million of
unrecognized share-based compensation expense related to non-vested 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 June 30, 2010 and December 31, 2009, the Company had
$5.1 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 and borrowing base
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 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 matured 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 June 30, 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.
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The
Credit Agreement 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 that the Company 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 agreement), 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.
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, 2009 and March 31, 2009 and with the restrictive
covenants related to accounts payable, permitted liens and permitted debt until
the 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, 2010.
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.
On July 8, 2010, the
Company was notified by its lender that it failed to make the principal and
interest payments due on July 1, 2010 and that such missed payments
constituted an Events of Default under the Credit Agreement. The Company
remains obligated to pay all amounts outstanding under the credit agreement.
The current amount outstanding under the credit facility is approximately
$5,100,000 plus accrued interest.
The
Company has requested additional waivers from its lender; however, there can be
no assurance that it will be able to obtain such waivers or that such waivers
will be obtained on acceptable terms. If the Company is unable to obtain future
waivers and/or to comply with the restrictive covenants, the lender could foreclose
on properties held by liens. Due to borrowing base limitations and waiver
stipulations, the Company is currently unable to incur additional indebtedness
under the credit facility.
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 June 30,
2010, the Company had $717,000 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 June 30, 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
15
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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:
·
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 June 30, 2010 (in thousands):
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Assets
|
|
|
|
|
|
|
|
|
|
Oil and gas derivative instruments
|
|
$
|
|
|
$
|
903
|
|
$
|
|
|
$
|
903
|
|
Total
|
|
$
|
|
|
$
|
903
|
|
$
|
|
|
$
|
903
|
|
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 June 30, 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 its building in August 2005, the Company was assigned the
lease agreements for existing tenants and executed lease agreements with new
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
|
|
$
|
57,000
|
|
2011
|
|
60,000
|
|
2012
|
|
44,000
|
|
2013
|
|
44,000
|
|
Total minimum lease payments
|
|
$
|
205,000
|
|
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 Mcf
either compressed
16
Table of Contents
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 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.
17
Table of Contents
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 alleged 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 sought 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 stipulated that the parties
dismiss all claims and counterclaims 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 stipulated 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 obligated 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.
The Tolling Agreement has lapsed and, to the Companys knowledge on the
date hereof, RLI Insurance Company has not re-filed its claims against the
Company.
The
Company is a party to two stockholder class action lawsuit filed in the
Delaware Court of Chancery. 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, entering into the merger agreement
with Powder and Powder Holdings, 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.
On
May 24, 2010, the Company and its directors entered into a Memorandum of
Understanding in anticipation of settling the shareholder lawsuit. Under the
terms of the Memorandum of Understanding, the Company agreed to make additional
proxy disclosures regarding the interests of our executive officers in the
surviving entity and furnish additional information regarding FBRs analysis
and fairness opinion. In return the shareholders will provide a release of
their claims against the Company, its directors, Powder and DLJ. The Company and its directors, Powder and DLJ
do not admit any wrongdoing and entered into the Memorandum of Understanding to
avoid the distraction, burden and expense of further litigation. The settlement
is subject to confirmatory discovery, negotiation of a definitive settlement
agreement, and approval by the Delaware Chancery Court. Powder and DLJ have
agreed to the terms of the Memorandum of Understanding.
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.
Note 10
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.
18
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Note 11 Recent Developments
At
the special meeting of the shareholders on August 9, 2010, the our
shareholders voted to approve a proposal to adopt the Agreement and Plan of
Merger dated February 23, 2010 (Merger Agreement) by and amongst us,
Powder Holdings, LLC, a Delaware LLC, and Powder Acquisition Co. (Powder), A
Delaware Corporation and wholly-owned subsidiary of Powder. We anticipate that
the closing will occur during the third quarter, subject to the satisfaction of
customary closing conditions and the receipt of waivers from our lender, The
Royal Bank of Scotland plc.
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 June 30, 2010, we owned natural gas and oil
leasehold interests in approximately 406,000 gross (297,000 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 six 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 $1.9
million for the six months ended June 30, 2010.
On
February 23, 2010, we entered into an Agreement and Plan of Merger with
Powder Holdings, LLC, and Powder Acquisition Co., 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 our
management team. On April 2, 2010, we filed a preliminary proxy statement
relating to the merger, with the U.S. Securities and Exchange Commission (SEC).
On June 29, 2010, we filed a definitive proxy statement relating to the
merger with the SEC. At the special meeting of the shareholders on August 9,
2010, our shareholders voted to approve a proposal to adopt the Agreement and
Plan of Merger dated February 23, 2010 (Merger Agreement) by and amongst
us, Powder Holdings, LLC, and Powder Acquisition Co. (Powder), a wholly-owned
subsidiary of Powder. We anticipate that the closing will occur during the
third quarter, subject to the satisfaction of customary closing conditions and
the receipt of waivers from our lender, The Royal Bank of Scotland plc.
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.
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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 six months of 2010, the price averaged
$4.38. 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 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 July 8, 2010, we
were notified by our lender that we failed to make the principal and interest
payments due on July 1, 2010 and that such missed payments constituted an
Events of Default under the Credit Agreement. We remain obligated to pay all
amounts outstanding under the credit agreement.
The current amount outstanding under the credit facility is
approximately $5,100,000.
We
have requested additional waivers from our lender; however, there can be no
assurance that we will be able to obtain such waivers or that such waivers will
be obtained on acceptable terms. If we are unable to obtain future waivers
and/or to comply with the restrictive covenants, the lender could foreclose on
properties held by liens. Due to borrowing base limitations and waiver
stipulations, we are currently unable to incur additional indebtedness under
the credit facility.
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;
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·
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;
·
Estimates for litigation.
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. No
impairment was recorded on unevaluated properties for the three and six months
ended June 30, 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 June 30, 2010 and December 31, 2009, the
estimated salvage value of equipment was $6.8 million.
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 June 30, 2010, the full cost ceiling
limitation exceeded the capitalized cost of the Companys oil and gas
properties by approximately $5.2 million based on the first day of the month,
twelve month average CIG price of approximately $3.76 per Mcf. Therefore, no
impairment was taken for the quarter ended June 30, 2010. An impairment of
$6.4 million was taken for the quarter ended June 30, 2009 based on a
natural gas price of $3.09 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
21
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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 June 30, 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 June 30, 2010, and December 31,
2009 were based on the actual volume statements from our purchasers and
distribution process. If accruals were to change by 10% at June 30, 2010
and at December 31, 2009, the impact would have been a change of $87,000
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 requires 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 $300,000 effect on our asset retirement obligation liability at June 30,
2010.
The
following is a summary of our asset retirement obligation activity for the
three and six months ended June 30, 2010 and June 30, 2009
(unaudited):
|
|
(in thousands)
|
|
|
|
Three
Months Ended
June 30,
|
|
Six
Months Ended June 30,
|
|
Three
Months Ended
June 30,
|
|
Six
Months Ended
June 30,
|
|
|
|
2010
|
|
2009
|
|
Beginning balance of asset retirement obligations
|
|
$
|
2,959
|
|
$
|
2,937
|
|
$
|
3,422
|
|
$
|
3,366
|
|
Additional obligation added during the period
|
|
|
|
1
|
|
$
|
|
|
$
|
|
|
Obligations to be settled
|
|
(18
|
)
|
(49
|
)
|
(23
|
)
|
(23
|
)
|
Accretion expense
|
|
54
|
|
106
|
|
58
|
|
114
|
|
Ending balance of asset retirement obligations
|
|
2,995
|
|
2,995
|
|
3,457
|
|
3,457
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 $45,000 reduction in our
inventory valuation as of June 30, 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 impairment. No impairments were recorded during the six
months ended June 30, 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 six
months ended June 30, 2010 would have increased or decreased our expenses
billed to working interest owners by approximately $33,000. 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 basis 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 June 30, 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 June 30,
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 June 30, 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
On
July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection
Act was enacted into law. This financial reform legislation includes
provisions that require over-the-counter derivative transactions to be executed
through an exchange or centrally cleared. In addition, the legislation
provides an exemption from mandatory clearing requirements based on regulations
to be developed by the Commodity Futures Trading Commission (CFTC) and the
Securities and Exchange Commission for transactions
by non-financial institutions to hedge or mitigate commercial risk. At
the same time, the legislation includes provisions under which the CFTC may
impose collateral requirements for transactions, including those that are used
to hedge commercial risk. However, during drafting of the legislation,
members of Congress adopted report language and issued a public letter stating
that it was not their intention to impose margin and collateral requirements on
counterparties that utilize transactions to hedge commercial risk. Final
rules on major provisions in the legislation will be established through
rulemakings and will not take effect until 12 months after the date of
enactment. Although we cannot predict the ultimate outcome of these
rulemakings, new regulations in this area may result in increased costs and
cash collateral requirements for the types of oil and gas derivative
instruments we use to hedge and otherwise manage our financial risks related to
volatility in oil and gas commodity prices.
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.
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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.
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 $25,000 for the six months ended June 30, 2010, based on the
fair value of vested options. We
recognized an expense of approximately $187,000 for six months ended June 30,
2010, based on the fair value of restricted stock that vested during the
quarter. We recognized an expense of
approximately $12,000 for the six months ending June 30, 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 June 30, 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 June 30, 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
six months ended June 30, 2010, basic and diluted net loss per share was
$0.02. During the six months ended June 30, 2010, 835,446 options and
stock appreciation rights were excluded because they were anti-dilutive.
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 and second
quarters 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
six months ended June 30, 2010, the NYMEX natural gas index price ranged
from a high of $6.00 per MMBtu to a low of $3.84
24
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per
MMBtu, while the CIG natural gas index price ranged from a high of $6.08 per
MMBtu to a low of $3.35 per MMBtu. During the year ended December 31,
2009, the NYMEX natural gas index price ranged from a high of $4.45 per MMBtu
to a low of $3.25 per MMBtu, while the CIG natural gas index price ranged from
a high of $3.47 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 six
months ended June 30, 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 has 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 June 30, 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 $1.00 per Mcf, with an average
differential of a discount of $0.38 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.
Results of Operations
Net
loss attributable to stockholders for the quarter ended June 30, 2010 was
$1.8 million, or $0.06 per diluted share, on total revenues of $2.5 million.
Other income for the quarter ended June 30, 2010 included a $0.6 million
unrealized loss 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 $1.2
million. This compares to a net loss
attributable to stockholders of $9.5 million for the quarter ended June 30,
2009 on total revenue of $3.7 million. Adjusted for an unrealized loss in the
fair valuation of our natural gas hedges in place of $2.7 million shown in
other income, our results for the quarter ended June 30, 2009 would have
been a net loss attributable to common stockholders of $6.8 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 June 30, 2010
Compared to Three Months Ended June 30, 2009
Gas sales volume.
Gas
sales volume decreased 18%, from 702 MMcf in the three months ended June 30,
2009 to 575 MMcf in the three months ended June 30, 2010. Daily sales
volume was 6.3 MMcf for the three months ended June 30, 2010 as compared
to 7.7 MMcf for the three months ended June 30, 2009, a 1.4 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 $0.3 million during the three months
ended June 30, 2010, to approximately $1.9 million, a 21% increase
compared to the three months ended June 30, 2009. This increase was
primarily due to an increase in the average realized price per Mcf along with a
reduction in gas sales volume. The average realized price per Mcf increased
approximately 47%, from $2.29 per Mcf in the three months ended June 30,
2009 to $3.37 per Mcf in the three months ended June 30, 2010.
Derivatives.
For
the three months ended June 30, 2010, we had an unrealized loss of
$610,000 compared to an unrealized loss of $2.7 million for the three months
ended June 30, 2009. The unrealized losses are non-cash expenses based
primarily on the Black-Scholes
25
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model
for valuing future cash flows utilizing price volatility with a normal discount
rate. Hedges settled during the three months ended June 30, 2010 resulted
in a realized gain of $590,000 compared to a realized hedge gain of $2.1
million during the three months ended June 30, 2009. The realized hedge
gain for the three months ended June 30, 2010 was primarily due to the
fact that gas prices were lower than the weighted average floor price of our
hedges in place.
Lease operating expenses.
Lease
operating expenses decreased $0.2 million in the three months ended June 30,
2010 to $0.8 million, a 18% decrease compared to the three months ended June 30,
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 cycle during the three months ended June 30,
2010. On a Mcf basis, lease operating expenses were $1.34 an Mcf for the three
months ended June 30, 2010 and June 30, 2009.
Production taxes.
Production
taxes increased $68,000 in the three months ended June 30, 2010 to $0.2
million, a 49% increase from the three months ended June 30, 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 June 30, 2010 was primarily due to decreased
revenues associated with decreased volume and realized pricing. On a Mcf basis,
production taxes were $0.36 per Mcf for the three months ended June 30,
2010 and $0.20 per Mcf for the three months ended June 30, 2009, a 81%
increase, which correlates to the increase in the price per Mcf received in the
three months ended June 30, 2010 from the three months ended June 30,
2009.
Marketing and transportation.
Marketing
and transportation expenses decreased approximately $0.1 million in the three
months ended June 30, 2010 to approximately $0.8 million, a 16% decrease
from the three months ended June 30, 2009. The decrease related primarily
to a decrease in transportation fees and compression due to lower production
volumes. On an Mcf basis, marketing and transportation expenses increased 3% to
$1.31 per Mcf in the three months ended June 30, 2010 from $1.27 per Mcf
in the three months ended June 30, 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 $332,000 in
the three months ended June 30, 2010 compared to $335,000 for the three
months ended June 30, 2009. General and administrative expenses net
decreased $0.2 million in the three months ended June 30, 2010 to $1.0
million. On a Mcf basis, general and administrative expenses, net increased 5%,
from $1.69 per Mcf in the three months ended June 30, 2009 to $1.77 per
Mcf in the three months ended June 30, 2010. General and administrative
expenses, for the quarter ended June 30, 2010, include $0.4 million for
professional services expense incurred in connection with the merger agreement
with Powder and Powder Holdings.
Depreciation, depletion, amortization and accretion.
Depreciation,
depletion, amortization and accretion expense decreased $0.1 million for the
three months ended June 30, 2010 to $0.8 million, an 8% decrease compared
to the three months ended June 30, 2009. The decrease was primarily due to
a decrease in the capitalized basis in our full cost pool at June 30,
2010. On an Mcf basis, the depreciation, depletion, amortization and accretion
rate increased to $1.47 per Mcf in the three months ended June 30, 2010
from $1.30 per Mcf in the three months ended June 30, 2009.
Impairment.
At
June 30, 2010, the full cost ceiling limitation of our oil and gas properties
exceeded the capitalized cost by approximately $5.2 million based upon a
natural gas price of approximately $3.76 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 three months ended June 30, 2010. An impairment of approximately $6.4
million was taken for the three months ended June 30, 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.
26
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Six Months Ended June 30, 2010
Compared to Six Months Ended June 30, 2009
Gas sales volume.
Gas
sales volume decreased 23%, from 1,516 MMcf in the six months ended
June 30, 2009 to 1,169 MMcf in the six months ended June 30, 2010.
Daily sales volume was 6.5 MMcf for the six months ended June 30, 2010 as
compared to 8.4 MMcf for the six months ended June 30, 2009, a 1.9 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 $0.4 million during the six months ended
June 30, 2010, to approximately $4.8 million, a 9% increase compared to
the six months ended June 30, 2009. This increase was primarily due to a
increase in the average realized price offset by a decrease in gas sales volume
per Mcf. The average realized price per Mcf increased approximately 42%, from
$2.88 per Mcf in the six months ended June 30, 2009 to $4.09 per Mcf in
the six months ended June 30, 2010.
Derivatives.
For
the six months ended June 30, 2010, we had an unrealized gain of $2.3
million compared to an unrealized loss of $2.1 million for the six months ended
June 30, 2009. The unrealized losses are non-cash expenses based primarily
on the Black-Scholes model for valuing future cash flows utilizing price
volatility with a normal discount rate. Hedges settled during the six months
ended June 30, 2010 resulted in a realized gain of $0.1 million compared
to a realized hedge gain of $3.5 million during the six months ended
June 30, 2009. The realized hedge gain for the six months ended June 30,
2010 was primarily due to the fact that gas prices were lower than the weighted
average floor price of our hedges in place.
Lease operating expenses.
Lease
operating expenses decreased $0.3 million in the six months ended June 30,
2010 to $1.8 million, a 16% decrease compared to the six months ended
June 30, 2009. This decrease resulted primarily from a reduction in labor,
fuel, workover and water management related costs offset partially by an
increase in surface use expenses in the productive cycle during the six months
ended June 30, 2010. On a Mcf basis, lease operating expenses increased 9%
from $1.40 per Mcf in the six months ended June 30, 2009 to $1.53 per Mcf
in the six months ended June 30, 2010.
Production taxes.
Production
taxes increased $0.1 million in the six months ended June 30, 2010 to $0.5
million, a 26% increase from the six months ended June 30, 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 six months ended June 30, 2010 was primarily due to decreased
revenues associated with decreased volume and realized pricing. On an Mcf
basis, production taxes were $0.45 per Mcf for the six months ended June 30,
2010 and $0.28 per Mcf for the six months ended June 30, 2009, a 63%
increase, which correlates to the increase in the price per Mcf received in the
six months ended June 30, 2010 from the six months ended June 30,
2009.
Marketing and transportation.
Marketing
and transportation expenses decreased approximately $0.7 million in the six
months ended June 30, 2010 to approximately $1.5 million, a 31% decrease
from the six months ended June 30, 2009. The decrease related primarily to
a slight decrease in transportation fees and compression due to lower
production volumes. On an Mcf basis, marketing and transportation expenses
decreased 11% to $1.26 per Mcf in the six months ended June 30, 2010 from
$1.41 per Mcf in the six months ended June 30, 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 $0.6 million
in the six months ended June 30, 2010 compared to $0.7 million for the six
months ended June 30, 2009, a 6% decrease. General and administrative
expenses, net, increased $0.2 million in the six months ended June 30,
2010 to $2.4 million. On an Mcf basis, general and administrative expenses, net
increased 42%, from $1.46 per Mcf in the six months ended June 30, 2009 to
$2.07 per Mcf in the six months ended June 30, 2010. The increase in
general and administrative expenses was primarily a result of professional
services expense incurred in connection with the merger agreement with Powder and
Powder Holdings.
Depreciation, depletion, amortization and accretion.
Depreciation,
depletion, amortization and accretion expense decreased $1.2 million for the
six months ended June 30, 2010 to $1.6 million, a 43% decrease compared to
the six months ended June 30, 2009. The decrease was primarily due to a
decrease in the
27
Table of Contents
capitalized
basis in our full cost pool. On an Mcf basis, the depreciation, depletion,
amortization and accretion rate decreased to $1.33 per Mcf in the six months ended
June 30, 2010 from $1.81 per Mcf in the six months ended June 30,
2009.
Impairment.
In
the six months ending June 30, 2010, the full cost ceiling limitation of
our oil and gas properties exceeded the capitalized cost by approximately $5.2
million based upon a natural gas price of approximately $3.76 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 June 30, 2010. An impairment of
approximately $23.3 million was taken for the quarter ended June 30,
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.
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 June 30, 2010 and December 31, 2009, we had $5.1 million and
$11.5 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, 2009, 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 August 13, 2009, our borrowing base was
reduced to $7.5 million, subject to automatic reductions of $500,000 per month
until it reaches $6.5 million on October 1, 2009. Further borrowing base redeterminations were
made pursuant to a series of waivers and agreements described below.
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.
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 June 30, 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 contains covenants that, among other things, restrict our
ability, subject to certain exceptions, to do the following:
28
Table of Contents
·
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 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,
2009, 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,
2009, 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 is 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,
2009 and June 30, 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, 2010.
29
Table of Contents
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 extended 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.
On July 8, 2010, we were notified by our lender that we failed to
make the principal and interest payments due on July 1, 2010 and that such
missed payments constituted an Events of Default under the Credit Agreement. We
remain obligated to pay all amounts outstanding under the credit agreement. The
current amount outstanding under the credit facility is approximately
$5,100,000.
We
have requested additional waivers from our lender; however, there can be no
assurance that we will be able to obtain such waivers or that such waivers will
be obtained on acceptable terms. If we are unable to obtain future waivers
and/or to comply with the restrictive covenants, the lender could foreclose on
properties held by liens. Due to borrowing base limitations and waiver
stipulations, we are currently unable to incur additional indebtedness under
the credit facility.
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, 2009, 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
$531,300 will become due. As of June
30
Table of Contents
30, 2010, we had $717,000
outstanding in principal on this mortgage. On November 15, 2009, the
interest rate on our mortgage loan changed from a fixed rate of 6.875% to a
variable rate. As of June 30, 2010, the variable rate was 4.00%.
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 six months ending June 30, 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 $1.9 million
for the six months ended June 30, 2010.
Cash Flow from Operating Activities
Net cash provided by operating activities was $1.5 million for the six
months ended June 30, 2010, compared to net cash used in operating
activities of $1.1 million for the six months ended June 30, 2009. The
change was primarily due to increases in accounts payable, accrued liabilities,
and revenue distribution payables.
Cash Flow from Investing Activities
Net
cash used in investing activities was approximately $0.5 million for the six
months ended June 30, 2010, compared to net cash provided by investing
activities of $4.2 million for the six months ended June 30, 2009. The
change in 2010 was primarily due to smaller realized gains on derivatives, a
sale of properties in 2009, and a liquidation of certificate of deposits in
2010.
Cash Flow from Financing Activities
Net cash used in financing activities was $1.0 million for the six
months ended June 30, 2010, compared to $3.5 million for the six months
ended June 30, 2009. The change in 2010 was primarily due to a reduction
in the balance owed on the line of credit for the six months ended June 30,
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 June 30,
2010:
|
|
Total
|
|
2010
|
|
20112012
|
|
20132014
|
|
Thereafter
|
|
|
|
(In Thousands)
|
|
Notes payable in connection with mortgage
|
|
$
|
717
|
|
$
|
17
|
|
$
|
71
|
|
$
|
76
|
|
$
|
553
|
|
Capital lease
|
|
65
|
|
10
|
|
45
|
|
10
|
|
|
|
Asset retirement obligations
|
|
2,995
|
|
652
|
|
822
|
|
420
|
|
1,101
|
|
Production and property taxes
|
|
3,735
|
|
3,273
|
|
462
|
|
|
|
|
|
Total
|
|
$
|
7,512
|
|
$
|
3,952
|
|
$
|
1,400
|
|
$
|
506
|
|
$
|
1,654
|
|
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. 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
31
Table of Contents
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 June 30, 2010. At June 30,
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)
|
|
1,012,000
|
|
Weighted-average fixed price sales per MMBtu(1)
|
|
$
|
5.08
|
|
Fair value, net (thousands)(2)
|
|
$
|
904
|
|
Total Natural Gas Contracts:
|
|
|
|
Contract volumes (MMBtu)
|
|
1,012,000
|
|
Fixed-price sales
|
|
$
|
5.08
|
|
Fair value, net (thousands)(2)
|
|
$
|
904
|
|
(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 June 30, 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 June 30, 2010, we had $5.1 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 six months ended June 30, 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 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
$51,000 per year based on our outstanding indebtness at June 30, 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 disclosure 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.
32
Table of Contents
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.
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 June 30, 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. 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 11 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.
We are in default pursuant to our
credit facility.
As described in
the Liquidity and Capital Resources section in this report, the seventh
amendment and waiver to credit agreement has expired and we failed to make the
principal and interest payments due July 1, 2010 and August 1,
2010. As a result, we are in default
pursuant to the credit facility and our lender may elect to pursue remedies
under the credit facility including foreclosure of our secured assets.
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;
33
Table of Contents
·
create liens;
·
sell our assets or
consolidate or merge with or into other companies;
·
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 was 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
On
July 8, 2010, the Company was notified by its lender that it failed to
make the principal and interest payments due on July 1, 2010 and that such
missed payments constituted an Events of Default under the Credit
Agreement. The Company was obligated to pay all amounts outstanding under
the credit agreement on or before July 15, 2010, but to date has not paid
such amounts. Furthermore, the Company did not make its principal and
interest payment on August 1, 2010.
The current amount outstanding under the credit facility is
approximately $5,100,000.
To
date, the lender has not accelerated the payment of the amounts due.
The
default under the terms of the credit agreement is also a default under the
term of the Merger Agreement with Powder, providing Powder the right to
terminate the Merger. Powder has indicated at this time that it will not
waive the default; however, it has not terminated the Merger. One
condition to the closing of the Merger is the receipt of waiver of defaults
under the credit agreement from our lender, The Royal Bank of Scotland. Although Powder has not terminated the
Merger, as discussed below, there is no assurance that the Company will be able
to obtain additional waivers from our lender.
The
Company has requested additional waivers from its lender; however, there can be
no assurance that it will be able to obtain such waivers or that such waivers
will be obtained on acceptable terms. If the Company is unable to obtain future
waivers and/or to comply with the restrictive covenants, the lender could
foreclose on properties held by liens. Due to borrowing base limitations
and waiver stipulations, the Company is currently unable to incur additional
indebtedness under the credit facility.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not
applicable.
ITEM 5.
OTHER INFORMATION
Not
applicable.
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
|
34
Table of Contents
|
|
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
35
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:
|
August 16,
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:
|
August 16,
2010
|
36
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